ML22112A088
| ML22112A088 | |
| Person / Time | |
|---|---|
| Site: | LaSalle, 05200002 |
| Issue date: | 01/31/1997 |
| From: | ABB Combustion Engineering |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20148A597 | List:
|
| References | |
| NUDOCS 9705090171 | |
| Download: ML22112A088 (1) | |
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e Copyright C 1997 Combustior; Engineering, Inc., All Rights Reserved. Warning, Legal Notice and Disclaimer of Liability , The design, engineering and other information contained in this document have been prepared by or for Combustion Engineering, Inc. in connection with its application to the United States Nuclear Regulatory Commission (US NRC) for design certification of the System 80+* nuclear plant design pursuant to Title 10, Code of Federal Regulations Part 52. No use of any such information is authorized by Combustion Engineering, Inc. except for use by the US NRC and its contractors in connection with review and approval of such application. Combustion Engineering, Inc. hereby disclaims all responsibility and liability in connection with unauthorized use of such information. Neither Combustion Engineering, Inc. nor any other person or entity makes any warranty or representation to any person or entity (other than the US NRC in connection with its review of Combustion Engineering's application) concerning such information or its use, except to the extent an express warranty is made by Combustion Engineering, Inc. to its customer in a wntten contract for the sale of the goods or services described in this document. Potential users are hereby warned that any such information may be unsuitable for use except in connection with the performance of such a written contract by Combustion Engineering, Inc. i Such information or its use are subject to copyright, patent, trademark or other rights of Combustion Engineering, Inc. or of others, and no license is granted with respect to l such rights, except that the US NRC is authorized to make such copies as are l necessary for the use of the US NRC and its contractors,in connection with the Combustion Engineering, Inc. application for design certification. Publication, distribution or sale of this document does not constitute the performance of engineering or other professional services and does not create or establish any duty of ) care towards any recipient (other than the US NRC in connection with its review of l Combustion Engineering's application) or towards any person affected by this document. l l 1 For information address: Combustion Engineering, Inc., Nuclear Systems Licensing, 2000 Day Hill Road; Windsor, Connecticut 06095 e i
System 30+ Design ConuelDocument O Introduction
-Q s Certified Design Material 1.0 Introduction 2.0 System arx! Structure ITAAC -
-3.0 Non-System 1TAAC 4.0 Interface Requirements
' 5.0 Site Parameters Approved Design Material - Design & Analysis 1.0 General Plant Description 2.0 Site Characteristics 30 Design of Systems, Structres & Components 4.0 Reactor
-l 5.0 RCS and Connected Systems
. 6.0 Engineered Safety Features [
7.0 Instrumentation and Control 8.0 Electric Power 9.0 Auxiliary Systems - 10.0 Steam and Power Conversion 11.0 Radioactive Waste Management l
-( 12.0 Radiation Protection N 13.0 Conduct of Operations 14.0 Initial Test Program 15.0 Accident Analyres 16.0 Technical Specifications 17.0 Quality Assurance 18.0 Human Factors 17.0 Probabilistic Risk Assessment 20.0 Unresolved and Generic Safety Issues Approved Design Material - Emergency Operations Guidelines ]
1.0 Introduction j 2.0 Standard Post-Trip Actions 3.0 Diagnostic Actions 4.0 Reactor Trip Recovery 5.0 - Loss of Coolant Accident Recovery 6.0 Steam Generator Tube Rupture Recovery i 7.0 Excess Steam Demand Event Recovery 8.0 Loss of All Feedwater Recovery 9.0 less of Offsite Power Recovery 10.0 - Station Blackout Recovery
-11.0 Functional Recovery Guideline O
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l Approved Design Material O oesign a Anaiysis
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System 80+ Deslan controlDocument 15.2 Decrease in Heat Removal by the Secondary System , l 15.2.1 Loss of External Load 15.2.1.1 Identification of Event and Causes ! The loss of external load event is caused by the disconnection of the turbine generator from the electrical distribution grid. j 15.2.1.2 Sequence of Events and Systems Operation A loss of external load generates a turbine trip which results in a reduction in steam flow from the steam generators to the turbine due to the closure of the turbine stop valves. The Steam Bypass Control System (SBCS) and Reactor Power Cutback System (RPCS) are both normally in the automatic mode and would be available upon turbine trip to accommodate the load rejection without necessitating reactor trip or the opening of main steam safety valves. Should a turbine trip occur with these systems in manual mode, a complete tennination of main steam flow results and reactor trip would occur on high pressurizer pressure (assuming the failure of the control grade reactor trip on turbine trip with the RPCS in manual). If no credit is taken for immediate operator action, the main steam safety valves will open to limit the secondary pressure increase and provide a heat sink for the NSSS. The operator can initiate a controlled system cooldown using the SBCS or the atmospheric dump valves any time after the reactor trip occurs. 15.2.1.3 Analysis of Effects and Consequences V The results of the loss of load event are no more limiting with respect to RCS pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in a turbine trip; however, feedwater flow terminates following LOCV whereas it ramps down following the loss of load. This larger reduction in heat removal capability results in a higher peak RCS pressure t and lower minimum DNBR for the LOCV. J Due to its similarity with the LOCV event, there are no concurrent single failures which when combined with the loss of external load result in consequences more severe than the LOCV with a concurrent single failure event with respect to RCS pressurization and fuel performance. This event with a loss of offsite power or with a loss of offsite power with a single failure results in an event no more adverse than the I LOCV event with the loss of offsite power or with a loss of offsite power with a single failure, respectively. j 15.2.1.4 Conclusions For the loss of load event and the loss of load event with coincident loss of offsite power, as well as these events in combination with a single failure, the maximum RCS pressure remains below 2750 psia, thus l I ensuring primary system integrity, the maximum steam generator pressure remains below 1320 psia, thus ensuring secondary system integrity, and the minimum DNBR remains above 1.24, thus ensuring fuel cladding integrity. LJ , l i I
^ .::Dee> A000erief. AccMant Anotysee Page 15.21 l l
System 80+ Design ControlDocument 15.2.2 Turbine Trip 15.2.2.1 Identification of Event and Causes . A turbine trip may result from a number of conditions which cause the turbine generator control system (TGCS) to initiate a turbine trip signal. A turbine trip initiates closure of the turbine stop valves. 15.2.2.2 Sequence of Events and Systems Operation A turbine trip results in a reduction in steam flow from the steam generators to the turbine due to the closure of the turbine stop valves. The Steam Bypass Control System (SBCS) and Reactor Power Cutback System (RPCS) are botF mally in the automatic mode and would be available upon turbine trip to accommodate the load rejecuon without necessitating reactor trip or the opening of main steam safety valves. Should a turbine trip occur with these systems in the manual mode, a complete termination of main steam flow results and reactor trip would occur on high pressurizer pressure (assuming the failure of the control grade reactor trip on turbine trip with the RPCS in manual). If no credit is taken for immediate operator action, the main steam safety valves will open to limit the secondary pressure increase and provide a heat sink for the NSSS. The operator can initiate a controlled system cooldown using the SBCS or atmospheric dump valves any time after reactor trip occurs. 15.2.2.3 Analysis of Effects and Consequences The results of the turbine trip event are no more limiting with respect to RCS pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in a turbine trip; however, feedwater flow instantaneously terminates following LOCV whereas it ramps down following the turbine trip. This larger reduction in heat removal capability results in a higher peak RCS pressure and lower minimum DNBR for the LOCV. Due to its similarity with the LOCV events, there are no concurrent single failures which when combined with the turbine trip result in consequences more severe than the LOCV event with a concurrent single failure with respect to RCS pressurization and fuel performance. This event with a loss of offsite power or with a loss of offsite power and a single failure results in an event no more adverse than the LOCV event with the loss of offsite power or with a loss of offsite power and a single failure, respectively. 15.2.2.4 Conclusions For the turbine trip event, and the turbine trip event with coincident loss of offsite power, as well as these events in combination with a single failure, the maximum RCS pressure remains below 2750 psia, thus, ensuring primary system integrity, the maximum steam generator pressure remains below 1320 psia, thus ensuring secondary system integrity, and the minimum DNBR remains above 1.24, thus ensuring fuel cladding integrity. 15.2.3 Loss of Condenser Vacuum 15.2.3.1 Identification of Event and Cause A loss of condenser vacuum (LOCV) may occur due to the failure of the circulating water system to supply cooling water, failure of the main condenser evacuation system to remove noncondensible gases, or excessive in-leakage of air. Immediate cessation of feedwater flow is assumed, and the turbine is assumed to trip immediately coincident with the cause for the loss of condenser vacuum. Anwoved Deskn Metodel. AccMent Ane&ses Page 15.2-2
System 80+ Dea lgn ConeralDocument M J The earlier LOCV analysis considered a loss of offsite power (LOOP), which was delayed by at least 3 seconds following turbine trip. In compliance with GDC 17, the final LOCV event presented was considered both with and without a loss of offsite power coincident with turbine trip. i When in the autornatic mode, the Steam Bypass Control System (SBCS), ifit controls atmospheric bypass
. valves, and the Reactor Power Cutback System (RPCS) will function to reduce the steam generator and RCS pressure increases during a loss of condenser vacuum. These systems may allow the NSSS to continue operating at a reduced power level. However, in this analysis both the SBCS and RPCS are assumed to be in the manual mode and credit is not taken for their functioning. Also, the Alternate Protection System control grade reactor trip on turbine trip with the RPCS in manual is assumed to fail.
Consideration of the influence of the loss of offsite power and consideration of single failures is addressed
; in Section 15.2.3.3.-
15.2.3.2 Sequence of Events and Systesns Operation
- Table 15.2.3-1 presents a chronological sequence of events which occur following the LOCV until ;
operator action is initiated. 15.2.3.3 Analysis of Effects and Consequences i 4 e Mathematical Model : l t Q The NSSS response to a LOCV was simulated using the CESEC-III computer program , V described in Section 15.0. The DNBR was calculated using the CETOP-D computer code (see
)
Section 15.0.3.1.6) which uses the CE-1 CHF correlation described in Reference 19 of Section ' 15.0 and the TORC computer code. i e Input Parameters and Initial Conditions ; l The input parameters and initial conditions used to analyze the NSSS response to a LOCV are ; discussed in Section 15.0. Table 15.2.3-2 contains the initial conditions and assumptions used for this event. The initial conditions for the principal process variables were varied within the ; ! ranges given in Table 15.0-3 to determine the set of initial conditions that would produce the l - most adverse consequences following a LOCV. Various combinations _of initial core inlet } temperature, core inlet flow, pressurizer pressure, and pressurizer water level were considered j in order to evaluate the effects on peak reactor coolant system (RCS) pressure. j Decreasing the initial core inlet temperature reduces the initial steam generator pressure, thereby ! delaying the heat removal associated with the opening of the main steam safety valves. The ; initial inlet temperature for this event was the minimum of 550'F. t Reduction of the initial pressurizer pressure delays the occurrence of reactor trip on high l , pressurizer pressure and allows the maximum reduction in steam generator heat removal prior ] to and following trip, As a result, maximum RCS overpressurization occurs provi3ed that the ; delay does not allow the main steam safety valves to open substantially prior to reaching the peak ; pressure condition. Decreasing the initial pressurizer water level produces similar trip delays. l L ::ceepr noneww Aeewart anerpene rene 15.2-2 i
System 80+ Design Control Document e Loss of Offsite Power The LOCV event is assumed to abruptly and completely terminate both main steam and feedwater flow. Satisfaction of GDC-17 stipulates that the event must be considered both with and without an attendant loss of offsite power (LOOP). The LOOP is postulated as a concurrent consequence of the turbine generator trip which occurs at the initiation of the event. The four pump coastdown caused by the LOOP produces a reactor trip signal generated by low pump shaft speed. This results in a reactor trip signal which is earlier than the reactor trip signal generated by the high pressurizer pressure signal from the event without LOOP. Consequently, with respect to peak pressure, the event with LOOP is less severe than the event without LOOP. With respect to fuel performance, the LOCV event with coincident LOOP is similar to the loss of non-emergency power to the station auxiliaries discussed in Section 15.2.6. These events are in effect the same as the loss of flow event, which is discussed in detail in Section 15.3.1. e Single Failure With respect to peak pressure criteria, there are no single failures which, when combined with the event, result in a more severe peak pressure than the LOCV by itself. Similarly, with regard to fuel performance, there are no single failures which, when combined with the event result in a more severe minimum DNBR than the event by itself. e Results The dynamic behavior of important NSSS parameters following the loss of condenser vacuum is presented in Figures 15.2.3-1 through 15.2.3-13. The sudden reduction of steam flow, caused by the LOCV, leads to a reduction of the primary-to-secondary heat transfer. The moderator reactivity is constant prior to reactor trip due to a zero MTC, even though the average core temperature increased from the initial conditions. At 6.9 seconds, a high pressurizer pressure trip signal is generated. The reactor trip breakers open at 7.05 seconds, limiting the maximum core power to 102% of full power. The pressurizer safety valves open a 7.65 seconds and the maximum RCS pressure of 2726 psia is reached at 8.45 seconds. The main steam safety valves open at 7.05 seconds and the maximum secondary pressure of 1273 psia is reached at 10.39 seconds. The RCS pressure then decreased rapidly due to the combined effects of reactor trip and primary and main steam safety valves. The pressurizer safety valves close at 14.09 seconds and the main steam safety valves close at 65.7 seconds. Emergency feedwater automatically begins at 177 seconds. Thirty minutes after initiation of the event, the operator commences a cooldown using the atmor,pheric dump valves to release steam. Initiating the LOCV event with initial conditions selected to minimize the transient DNBR results in a minimum DNBR of 1.26 at 28.05 seconds. 15.2>3.4 Conclusions For the loss of condenser vacuum event and the loss of condenser vacuum event with a coincident loss of offsite power, as well as these events in combination with a single failure, the maximum RCS pressure remains below 2750 psia, thus ensuring prunary system integrity, the maximum steam generator pressure AMvond Design nionerial Accident Anstyses rege 15.2 4
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[ l i System 80+ Design ConnelDocument remains below 1320 psia, thus ensuring =~=hry system integrity, and the minimum DNBR remains ! , above 1.24, thus ensuring fuel cladding integrity. ! 15.2.4 Main Steem Isolation Valve Closure 15.2.4.1 Ms=dfiendan of Event and Causes The Main Steam isolation Valve (MSIV) closure event is initiated by the closure of all MSIVs due to a
. spurious closure signal. !
15.2.4.2 Sequence of Events and Systems Operation ;
'I The closure of all MSTVs results in the termination of all main steam flow. The decreased heat n moval results in increasing primary and secondary temperatures and pressure. Reactor trip occt;rs on high r pressurizer pressure. The pressure increases in the primary and secondary systems are limited by the '
pressurizer and steam generator safety valves. The operator can initiate a controlled system cooldown using the atmospheric dump valves or the steam bypass control system any time after reactor trip occurs. , 15.2.4.3 Analysis of Effects and Conseg=ar== > i
'Ihe results of the MSIV closure event are no more limiting with respect to RCS pressurization and fuel i performance than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The !
LOCV also results in the termmation of all main steam flow. However, main steam flow is terminated t more rapidly during the LOCV since the closure time for the turbine stop valves is much shorter than i that for the MSIVs. The faster reduction in heat removal results in a higher peak RCS pressure and i lower DNBR for the LOCV event. Due to the similarity with the LOCV event, there are no concurrent single failures which when combined ! with the MSIV closure event result in consequences more severe than the LOCV event with a concurrent , single failure with respect to RCS pressurization and with respect to fuel performance. This event with l a loss of offsite power or with a loss of offsite power with a single failure results in an event no nere adverse than the LOCV event with the loss of offsite power or with a loss of offsite power with a single failure, respectively. t 15.2.4.4 Conclusions l For the MSIV closure event and the MSIV closure with coincident loss of offsite power, as well as these events in combination with a single failure, the maximum RCS pressure remains below 2750 psia, thus ensuring primary system integrity, the maximum steam generator pressure remains below 1320 psia, thus ( ensuring secondary system integrity, and the minimum DNBR remains above 1.24, thus ensuring fuel ; cladding integrity, j i 15.2.5 Steam Prussee Regulator FaGure j i This event does not apply to the System 80+ Standard Design and, therefore, is not presented. l i k l Ausweestase(pe asseaW. AseMast Anshees . page f5.24 1 i I
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System 80+ Design ControlDocument 15.2.6 Loss of Non-Emergency AC Power to the Station Auxiliaries , 15.2.6.1 Identification of Event and Causes The loss of non-emergency AC power to the station auxiliaries (LOAC) may result from either a complete loss of the external grid or a loss of the onsite AC distribution system. The LOAC is presented as the initiating event for the four pump loss of flow event discussed in Section 15.3.1. 15.2.6.2 Sequence of Events and Systems Operation When all normal AC power is assumed to be lost to the plant, the turbine stop valves close, and it is assumed that the area of the tmbine control valves is instantaneously reduced to zero. Also, the feedwater flow to both steam generators is instantaneously assumed to go to zero. The reactor coolant pumps coast down and the reactor coolant flow begins to decrease. A reactor trip will occur as a result of a low pump shaft speed as the flow coastdown begins. The pressure increases in the RCS and steam generators are limited by the pressurizer and steam generator safety valves. The loss of all normal AC power is followed by automatic startup of the standby diesel generators, the power output of which is sufficient to supply electrical power to all necessary engineered safety features systems and to provide the capability to maintain the plant in a safe shutdown condition. Subsequent to the reactor trip, stored and fission product decay energy must be dissipated by the reactor coolant system and main steam system. In the absence of forced reactor coolant flow, core heat removal occurs by natural circulation in the RCS. Initially, the residual water inventory in the steam generators is used as a heat sink, and the resultant steam is released to atmosphere by the main steam safety valves. With the ! availability of standby diesel power, emergency feedwater is automatically initiated on a low steam generator water level signal. Plant cooldown is operator controlled via the atmospheric dump valves until offsite power is restored at which time the steam bypass control system and the condenser are utilized for the remainder of the cooldown. 15.2.6.3 Analysis of Effects and Consequences The results of the LOAC event are identical to those of the loss of reactor coolant flow event presented in Section 15.3.1 and are no more limiting with respect to RCS pressurization than the loss of condenser vacuum (LOCV) event discussed in Section 15.2.3. During the LOCV event the plant experiences simultaneous losses of steam and feedwater flow and condenser availability. In addition, the plant experiences a complete loss of forced reactor coolant flow at the initiation of the LOAC event. The loss of forced reactor coolant flow results in an earlier reactor trip for the LOAC event (on low RCP shaft speed) compared to the reacter trip for the LOCV event. The earlier trip promotes a less severe primary-to-secondary heat imbalance and hence a lower peak RCS pressure for the LOAC event. The fuel performance for the LOAC is no more limiting than that for the loss of flow (LOF) event discussed in Section 15.3.1. The LOAC is the initiating event for the LOF so the fuel performance results of the LOF event are directly applicable to the LOAC event. 15.2.6.4 Conclusions For the LOAC event and the LOAC with a concurrent single failure, the RCS pressure remams below 2750 psia, thus ensuring primary system integrity, the steam generator pressure remains below 1320 psia, thus ensuring secondary system integrity and the minimum DNBR remains above 1.24, thus ensuring fuel cladding integrity. Anrevet Desipos t Mewn!. AccMent Ane!yses Pege 15.2-6
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, System 80+ Deslan ControlDocument -
/T Q 15.2.7 Loss of Normal Feedwater Flow 15.2.7.1 Identification of Event and Causes
- The loss of normal feedwater flow (LFW) event may be initiated by losing one or more of the three operating main feedwater pumps or by a spurious signal being generated by the feedwater control system resulting in a closure of the feedwater control valve (s). 15.2.7.2 h7 m of Events and Systems Operation
- LFW results in decreasing water level and increasing pressure and temperature in the steam generators.
The RCS pressure and temperature also rise until a reactor trip occurs either due to low steam generator 3 water level or high pressurizer pressure. Assuming the steam bypass control system (SBCS) is in the j manual mode of opera: ion, termination of main steam flow due to closure of the turbine stop valves ' following reactor trip temporarily causes steam generator and RCS pressurization. The decrease in core heat rate after insertion of the CEAs in combination with the main steam safety valves opening restores the RCS to a new steady state condition. Emergency feedwater flow is automatically initiated on a low ; i steam generator water level assuring sufficient steam generator inventory for core decay heat removal and cooldown to shutdown cooling entry conditions. The cooldown is operator controlled using the SBCS and the condenser. i 15.2.7.3 Analysis of Effects and Consequences l
. The maximum RCS pressure and fuel performance for the LFW event are less limiting than that for the i' loss of condenser vacuum (LOCV) event discussed in Section 15.2.3. The LOCV event results in the termination of main steam flow prior to reactor trip in addition to the total loss of normal feedwater flow. l This additional condition aggravates RCS pressurization and the impact on fuel performance by further reducing the rate of primary-to-secondary heat transfer below that of the LFW event.
There are no concurrent single failures which when combined with LFW result in consequences more severe than the LOCV event with a single failure with respect to RCS pressurization and fuel performance. 2 This event with a loss of offsite power coincident with turbine trip or with a loss of offsite power in combination with a single failure results in an event less severe than the LOCV event with a loss of offsite power or with a loss of offsite power in combination with a single failure, respectively. 15.2.7.4 Conclusions For the loss of feedwater flow event and the loss of feedwater flow event with loss of offsite power as well as these events in combination with a single failure, the RCS pressure remains below 2750 psia, thus msuring primary system integrity, the steam generator pressure remains below 1320 psia, thus ensuring secondary system integrity, and the minimum DNBR remains above 1.24, thus ensuring fuel cladding , integrity. !
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1 L. -2Deekn aneeeriet AceMont Ane&see page 15.2 7
System 80+ Design ControlDocument j 15.2.8 Feedwater System Pipe Breaks 15.2.8.1 Identification of Event and Causes The Feedwater Line Break (FLB) event is initiated by a break in the main feedwater system (MFS) piping. Depending on the break size and location and the response of the MFS, the effects of a break can vary from a rapid heatup to a rapid cooldown of the Nuclear Steam Supply System (NSSS). In order to discuss the possible effects, breaks are categorized as small, if the associated discharge flow is within the excess capacity of the MFS, and as large, otherwise. Break locations are identified with respect to the feedwater line reverse flow check valves which are located between the steam generator feedwater nozzles and the containment penetrations. For a break upstream of the valves, the closure of these valves maintains the integrity of the steam generator by preventing reverse flow from the nearest steam generator. Breaks upstream of the check valves can initiate one of the following transients. If the MFS is unavailable following the pipe failure, a total loss of normal feedwater flow (LOFW) results. With the MFS remaining in operation no reduction in feedwater flow to the steam generators occurs for small breaks, while large breaks impose either a partial LOFW or a total LOFW, if the area is sufficient to discharge the entire feedwater pump flow capacity. In addition to the possibility of partial or total LOFW events, breaks downstream of the check valves have the potential to establish reverse flow from the nearest steam generator (referred to as the " ruptured" generator) back to the break. Reverse flow occurs whenever the MFS is not operating subsequent to a pipe break or when the MFS 4 operating but without sufficient capacity to maintain pressure at the break above the steam generator pressure. It is only these breaks which develop reverse flow that are of interest in this analysis. Depending on the enthalpy of the reverse flow and the ruptured steam generator's heat transfer characteristics, the reverse flow may induce either an RCS heatup or cooldown. However, excessive heat removal through the break is not considered in this analysis, because the cooldown potential is less than that of the steam line break (SLB) events. The maximum break size is smaller for the FLB events than for SLB events. In addition, the SLBs have a greater potential for discharging high enthalpy fluid due to the location of steam piping above feedwater piping within the steam generator. Furthermore, the FLB breaks could cause an instant reduction in feedwater flow unlike SLB, which results in a reduced heat removal capacity due to the lower liquid inventory. Since FLB breaks can cause a rapid depletion of ruptured steam generator liquid mass, reducing the heat transfer capability and causing a rapid RCS heatup and pressurization, it is the heatup potential which is maximized in this section. The earlier FLB analysis did consider a loss of offsite power (LOOP), which was delayed by 3 seconds following a turbine trip. In compliance with GDC 17, i.e., considering the event with and without LOOP, the final limiting case presented assumes a LOOP coincident with a turbine generator trip following a reactor trip. 15.2.8.2 Sequence of Events and Systems Operation A general description of the limiting FLB event follows which assumes a break downstream of the check valves, inoperability of the MFS, and low enthalpy break discharge: The loss of subcooled feedwater flow to both steam generators causes increasing steam generator temperatures and decreasing liquid inventories and water levels. The rising secondary temperatures Aneroved Design Material. AccMent Analyses Page 15.2 8
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System 80+ Deslan ControlDocument O V reduce the primary-to-secondary heat transfer and force a heatup and pressurization of the RCS. The heatup becomes more severe as the ruptured steam generator experiences a further reduction in its heat transfer capability due to insufficient liquid inventory as the break discharge continues. This initial sequence of events culminates with a reactor trip on high pressurizer pressure, low steam generator water level or high containment pressure. RCS heatup can continue after trip due to a total loss of heat transfer in the ruptured steam generator as it empties. Eventually the decreasing core power following reactor trip reduces the core heat rate to the heat removal capacity of the intact steam generator. Table 15.2.8-2 presents a chronological sequence of events which occur following the FLB until operator action is iaitiated. 15.2.8.3 Analysis of Effecte and Consequences
- Mathematical Models Analysis of the Fi a event is performed using the CESEC-Ill computer program described in Section 15.0.3 along with several simplifying assumptions which, with respect to RCS overpressurization, conservatively model the break discharge flow and enthalpy and the ruptured steam generator water level and heat transfer. In addition, sensitivity of the RCS overpressurization to changes in various plant initial conditions was evaluated to insure acceptable results with the most adverse initial conditions for the FLB event.
Blowdown of the steam generator nearest the feedwater line break is modeled assuming O frictionless critical flow as calculated by the Henry-Fauske/ Moody correlation (References 28 and [O 59 of Section 15.0). Although the enthalpy of the blowdown physically depends upon the location of the break relative to fluid conditions within the ruptured steam generator, it is assumed that saturated liquid is discharged until no liquid remains at which time saturated steam discharge is assumed. With respect to RCS overpressurization, these assumptions result in conservatively high mass flow and conservatively low energy f;ow from the steam gencrator to the break, thereby minimizing the ruptured generator heat removal capacity. For the case with a loss of offsite power, no credit is taken for a low water level trip condition in the ruptured steam generator until the generator is emptied of liquid. This conservatively delays the time of reactor trip, prolonging the RCS heatup and overpressurization. No credit is taken for the high containment pressure trip. In order to determine the sensitivity of the RCS overpressurization to the ruptured steam generator heat transfer characteristics 4.vithout implementing a detailed steam generator model, the effective heat transfer area is assumed to decrease linearly from the design value to zero as the steam generator liquid mss decreases from a selected value through a specified increment. For the limiting case, the hut transfer area is decreased to zero over the time interval required for the inventory to decrease by an increment of 500 lbm. The value of 500 lbm represents only 0.2% of the initial inventory and causes a decrease in the heat transfer area to zero in only 0.2 seconds for the limiting break flow rate. This assumption is consistent with FLB simulations in the Semiscale facility (as discussed in Section 4.3.3.1 of NUREG/CR-4945, dated July 1987) p) where the heat transfer across the steam generator tubes was observed to decrease rapidly from nearly the full power value to essentially zero at the time the liquid inventory was depleted. A me,. m anneaw acemeta w pea rene rs.2.s
System 80+ Design ControlDocument Sensitivity studies are used to establish the most adverse set of initial operating and transient parameters with respect to RCS overpressurization. These parameters include break size and initial core inlet temperature.
- Input parameters and initial conditions The input parameters and initial conditions used to analyze the NSSS response are discussed in Section 15.0. The initial conditions considered are given in Table 15.0-3. The set of initial conditions used in the analysis are shown in Table 15.2.8-1.
In addition to conservatively delaying steam generator low level trip coincident with the assumed heat transfer degradation, the initial primary system pressure was adjusted within the range specified in Table 15.0-3 to achieve, where possible, a coincident reactor trip signal on high pressurizer pressure. This maximizes the primary pressurization potential of the event, by maximizing the primary system pressure at the time of the coincident reactor trip signal. To minimize DNBR the initial pressure was 2175 psia as this minimizes pressure at time of trip. To determine the limiting single failure of the FLB event with the loss of offsite power, Table 15.04 was used. There are no single failures identified in this table which can adversely impact the consequences (i.e., pressurization) associated with the FLB event. As a result of the evaluation rr-thod applied to the FLB event analysis, the only mechanisms for mitigation of the reactor coolant system (RCS) pressurization are the pressurizer safety valves, the reactor coolant flow and the main steam safety valves. The last two influence the RCS-to-steam generator heat transfer rate. There are no credible failures which can degrade pressurizer safety valve or main steam safety valve capacity. Nor are there any credible failures which can reduce steam flow to the ruptured steam generator. A decrease in RCS to steam generator heat transfer due to reactor coolant flow coastdown can only be caused by a loss of offsite power following turbine trip. Because offsite power is assumed to be unavailable in this analysis, the failure of one Emergency Feedwater Pump (EFP) to start is assumed in order to minimize the long term decay heat removal capability. A spectrum of break sizes was analyzed using the methodology described in the preceding paragraphs to determine the limiting break size. The results of this analysis are provided in Figure 15.2.8-1 which plots maximum primary pressure vs. break size. As can be seen, the 2 limiting break size is the 0.6 ft2 break for overpressurization. A 0.2 ft break was determined to be limiting for DNBR. Detailed results of the 0.6 ft 2break size are presented in the following section.
- Results The sequence of events and the dynamic response of the important NSSS parameters following the FLB are provided in Table 15.2.8-2 and Figures 15.2.8-2 through 15.2.8-17, respectively.
A 0.6 ft 2crack in the main feedwater line is assumed to instantaneously terminate feedwater flow to both steam generators and establish critical flow (~ 5000 lbm/sec of saturated liquid) from the generator nearest the break. The absence of subcooled water arxl pressurization of the steam generators during the first 19.10 seconds reduces the primary-to-secondary heat transfer rate. Rising reactor coolant temperatures and pressure result. Due to temperature reactivity feedback Alprennt Design Material AccMent Analyses Pope 15.210
System 80+ Design controlDocument ( ) during this period the core power decreases slightly from 102.3 percent to 100.9 percent of design full power. The reactor pressure increases and reaches the high pressurizer pressure trip setpoint at 17.00 seconds. This generates a high pressure trip signal at 18.00 seconds and a reaaor trip at 18.15 seconds. At 19.10 seconds the ruptured steam generator is assumed to instantaneously lose all heat transfer capability due to total depletion of its liquid inventory by boil-off and the break discharge flow. This initiates a rapid heatup and pressurization of the reactor coolant system and depressurization of the steam generators. The rate of reactor coolant system pressurization is further aggravated at 18.15 seconds when closure of the turbine stop valves leaves the pipe break as the only steam relief path. This reduces the energy flow from the intact steam generator to below that of the primary-to-secondary heat transfer rate. The resulting steam generator pressurization reduces the primary-to-secondary temperature difference further degrading primary to secondary heat transfer. In addition, the loss of reactoi coolant flow following the loss of electrical power decreases the heat transfer coefficient of the coolant in the steam generator tubes. A significant heat transfer reduction occurs. Compression of the pressurizer steam volume due to the high insurge flow raises the pressure to the safety valve setpoint at 19.50 seconds. The reactM coolant system pressure continues to increase to a maximum of 2798 psia at 20.29 seconds. The rate of heatup decreases subsequent to core heat flux decay causing the primary ppm ares to drop. The intact generator is forced to a maximum cf 1238 psia before the heat transfer p begins to decrease. liowever, the core-to-steam gencator heat rate mismatch is reduced V sufficiently by 29.37 seconds to allow closure of the pressurizer safety valves. The reactor coolant system experiences a cooldown under the influence of steam blowdown through the ruptured steam generator to the break. Main steam isolation is initiated at 105.35 seconds on low steam generator pressure which closes ! the mr.in steam isolation valves decoupling the intact steam generator from the ruptured steam l i generator and the break. The intact steam generator repressurizes, thereby reducing heat transfer I and eventually causing a primary system heatup. With the main steam safety valves open by 409.30 seconds, the primary-to-secondary heat imbalance is eliminated. Thereafter the NSSS enters into a quasi-steady state with a very gradual cooldown and depressurization due to decreasing core decay heat, cycling of the main steam safety valves and emergency feedwater i flow which was initiated at 78.35 seconds maintaining an adequate liquid inventory within the intact steam generator for heat removal. By 1800 seconds the operator initiates a controlled cooldown to shutdown cooling utilizing the atmospheric dump valves. The feedwater line break event with a 0.6-ft 2break was also analyzed assuming offsite power is available and the low steam generator level trip signal in the affected steam generator is available on the level in the steam generator reaching the harsh environment analysis setpoint of the Reactor Protection System. The Low Steam Generator Water Level Trip (LSGLT) is a Plant Protection System (PPS) trip i function provided with each steam generator. The trip signal is produced using the wide range steam generator level sensors that are seismically and environmentally qualified in accordance j [s) () with the methodology discussed in Sections 3.0 and 3.11. Inputs to the trip function are from AenproomtDes> Menese! AccMent Aneyses Page 15.211
System 80+ Design ControlDocument redundant sensors which are powered by channelized battery backed Class IE power. The sensors are provided with conduit seals which serve to satisfy the Postaccident Monitoring Instrumentation (PAMI) requirements of these channels. Since steam generator pressure is increasing in the time period up to and past the time of reac,or trip and the time of peak RCS pressure, there is no tendency for level swell in the steata , generator to occur or to affect the low water level signal. Consequently, there are no level fluctuations which will have an adverse influence on the instrumentation. Therefore, the 33.7% wide range level corresponding with the minimum analysis setpoint of the Reactor Protection System is a conservative reactor trip serpoint for the FLB event. The heat transfer characteristics in the affected steam generator are the same as those applied in the analysis which assumes loss of offsite power. That is, the effective steam generator heat transfer area is decreased to zero over the time interval required for the inventory to decrease by an increment of 500 lbm. The value of 500 lbm represents only 0.2% of the initialinventory and causes a decrease in the heat transfer area to zero in only 0.2 seconds for the limiting break flow rate. This approximation is consistent with FLB simulations in the Semiscale Facility (as discaued in Section 4.3.3.1 of NUREG/CR-4945, dated July 1987) where the heat transfer across the steam generator tubes was observed to decrease rapidly from nearly the full power value to essentially zero at the time the liquid inventory was depleted. With regard to the influence of single failures on the FLB event, there are no single failures from the listing in Table 15.0-4 which can adversely affect the peak pressures associated with the FLB event. Ilowever, for this evaluation, the loss of one emergency feedwater pump has been included to adversely influence long term pressurization. The influence of offsite power and credit for the harsh environment LSGLT setpoint in the affected steam generator is a substantial reduction of the peak RCS pressure from 2798 psia to 2676 psia and an increase in peak steam generator pressure from 1238 psia to 1273 psia. Both effects are due to the continuity of RCS flow ra.: and delay of dryout in the affected steam generator. The later also delays backflow of steam from the intact steam generator into the affected steam generator until after the core power is decreased by the reactor trip. The RCS pressure response and the responses of parameters with a substantial change from the case with loss of offsite power are provided in Figures 15.2.8-18 to 15.2.8-23. histantaneous termination of feedwater flow to both steam generators along with a 0.6-ft: break increases steam generator pressure as the steam generators boil offliquid inventory. The absence ; of subcooled water and the pressurization of the steam generators reduces the primary to l secondary heat transfer which increases primary temperature and pressure. The peak RCS ; pressures are generated when the LSGLT in the affected steam generator is attained at 15.85 l seconds and coincident with a high pressurizer pressure reactor trip. i The turbine stop valves close simultaneously with reactor trip causing the steam generator pressures and the RCS temperatures and pressures to increase more rapidly until the MSSVs open : l at 17.76 seconds and the PSVs open at 17.65 seconds. The peak RCS pressure is 2676 psia at 17.93 seconds, and the peak steam generator pressure is 1273 psia at 20.0 seconds. Thereafter, pressure and temperature decrease, trailing the decrease in reactor power. There is a momentary increase in RCS temperatures and pressures when the affected steam generator Altvond Design A4aterial. Accident Analyses (11/96) Page 15.2-12
l l System 80+ Design ControlDocument reaches the dryout condition at 28.18 seconds. However, the reactor power is low at this time; (nC') therefore, the loss of heat transfer in the affected steam generator is inconsequential. A case was run in order to minimize the DNBR for this transient. The limiting break size for this case was 0.2 ft2 and resulted in a MDNBR less than 1.24 but also less than 0.60% fuel failure. During the FLB event the pressurizer liquid level did not reach the safety valve nozzle elevation, thus ensuring normal safety valve operation. Also, RCS hot leg subcooling was maintained during safety valve blowdown. The primary safety valve blowdown pressure assumed was 18.5 % below the set pressure. i During the first 30 minutes following the initiation of this FLB event, mass releases from the system amount to 163,500 lbm and 174,200 lbm of steam which is assumed to be released to the atmosphere and into the containment, respectively. Between 30 minutes and 8 hours the steam releases are assumed to be the same as for steamline break, as the cool down is the same. During this event, three sources of radioactivity contribute to the site boundary dose; the initial activity in the steam generator inventory, the activity associated with primary to secondary leakage from the steam generator tubes and the contribution from failed fuel. The activities in the first two suerces are assumed to be at the technical specification limits. The methods for calculating radiological consequences are outlined in Appendix 15A. n The radiological consequence following a Minimum DNBR was analyzed for two bounding scenarios: Qi Scenario A: a feedwater line break inside containment which will trigger containment isolation resulting in an unfiltered power purge at 16000 cfm for 30 seconds. The power purge rate is conservatively based on the LOCA pressure transient. It is noted that fuel failure does not occur until 43.7 seconds into the accident. Scenario B: a feedwater line break inside containment which doer. not trigger containment isolation, resulting in a filtered containment purge at 1250 cfm until it is manually isolated 30 minutes after the accident. l l Radiological analyses were also performed to evaluate the impact on site boundary doses following the overpressurization case of the FLB cvent. The analyses addressed two scenarios: a) preaccident iodine spike; b) concurrent iodine spike. The applicable parameters are presented in Table 15.2.8-3. 15.2.8.4 Conclusions The limiting overpressurization case of the FLB event (0.6 ft2break), which assumes a loss of offsite I power, produces an NSSS transient with a maximum pressure above 110% of design but less than 120% j of design in the RCS and is than 110% of design in the steam generators. This meets the overpressurization requirements for very low probability events. With credit for offsite power, the maximum RCS pressure and the maximum steam generator pressures remain below 110% of design ( ') pressure. kj 1 1 AppromiDe@n Meterial. AccMent Anayses (11/961 Page 15.2-13 l
System 80+ Design ControlDocument In a case run specifically to minimize DNBR, less than 0.6% of the fuel experienced cladding failure. The radiological consequences of the bounding scenarios described in Section 15.2.8.3 are a small fraction of 10CFR100 guidelines. The doses provided in Table 15.2.84 for the MDNBR Case represent the results of Scenario B which is the more limiting. Control room dose are presented in Section 6.4. Table 15.2,3-1 Sequence of Events for the LOCV Time Event Setpoint (Sec) or Value 0.0 Loss of Condenser Vacuum -- 5.90 liigh Pressurizer Pressure Trip 2434 Condition Reached. p:!a 6.9 liigh Pressurizer Pressure Trip Signal Generated -- 7.05 Trip Breakers Open - 7.05 Main Steam Safety Valves Open, psia 1212 7.65 Pressurizer Safety Valves Open, psia 2525 8.45 Maximum RCS Pressure, psia 2726 10.39 Maximum Steam Generator Pressure, psia 1273 14.09 Pressurizer Safety Valves Close, psia 2070 65.7 Main Safety Valves Close, psia 1151 117.0 Steam Generator Water level Reaches Emergency 19.9 Feedwater Actuation Signal Analysis Setpoint, percent of wide range 177.0 Emergency Feedwater Flow Initiated, gpm 500 1800.0 Operator Initiates Plant Cooldown - O Asuveved Design Atatorial Accident Analyses Page 15.214 I
l System 80+ Design ControlDocumarrt
/*M d Table 15.2.3-2 Assumed Initial Conditions for LOCV Parameter Valee Initial Core Power level, MWt 3993 j Core Inlet Coolant Temperature, 'F 550 l 6
Core Mass Flow,10 lbm/hr 154.3 Pressurizer Pressure, psia 2250 Initial Pressurizer Wi.ter level, percent of wide range 26 initial Core Minimrm DNBR 1.63 Integrated Radia! Peaking Factor 1.53 , Steam Generator Water level, percent of wide range 76.4 CEA Worth for Trip,10r2 Ap -8.86 d 0.0 Moderator Temperature Coefficient,10 Ap/*F Doppler Reactivity Table 15.0-5 Table 15.2.8-1 Assumptions for the Limiting Case Feedwater Line Break Event Parameter Assumed Value i b Initial Core Power, MWt 3992 Initial Core inlet Temperature. 'F 561 Initial Core Mass Flow Rate,106 lbm/hr 152.0 Initial Pressurizer Pressure, psia 2275 Fuel Gas Gap Heat Transfer Coefficient, 450 Bru/Hr-ft2 ,.p
- g. Doppler Coefficient Multiplier 0.85 Pressurizer Safety Valves Rated Flow Rate per 525000 Valve, Ibm /hr Initial Pressurizer Liquid Volume, ft 3 1400 Initial Steam Generator Inventory, Ibm 170000 Initial Feedwater Enthalpy, Btu /lbm 376 Steam Bypass Control System Manual Normal Onsite or Offsite Electrical Power After Unavailable Turbine Trip Feedwater Pipe Break Area, ft2 0.6 CEA Worth at Trip,10-2 Ap -8.86 j Moderator Temperature Coefficient,10 d Ap/'F 0.0 v
Doppler Reactivity Table 15.0-5 AnweeedOneiper ateswaint AccMent Ane&ses 6
- age 15.215
l l System 80+ Design ControlDocument Table 15,2.8-2 Sequence of Events for the Limiting Case Feedwater Line Break Event h Time (see) Event Setpoint or Value 0.0 Break in the Main Feedwater Line, ft2 0.6 0.0 Instantaneous less of All Feedwater Flow to Both Steam Generators - 0.0 Instantaneous Development of Critical Flow from the Ruptured Steam - Generator to the Break 17.00 Pressurizer Pressure Reaches Reactor Trip Analysis Setpoint, psia 2475 18.00 High Pressurizer Pressure Trip Signal Generated - 18.15 Trip Breakers Open - 18.15 Instantaneous Closure of the Turbine Stop Valves - 18.15 Loss of Normal Onsite and Offsite Electrical Power - 18.35 Steam Generator Water level Reaches Emergency Feedwater 5 Actuation Analysis Setpoint in the intact Generator, percent of wide range 19.10 instantaneous less of All Heat Transfer to the Ruptured Steam - Generator 19.10 Steam Generator Water Level Reaches Reactor Trip Analvsis Setpoint Empty in the Ruptured Generator 19.10 Steam Generator Water Level Reaches Emergency Ft.edwater Empty Actuation Signal Analysis Setpoint in the Ruptured Generator 19.50 Main Steam Safety Valves Open, Unaffected LOOP, psia 1212 19.50 Pressurizer Safety Valves Open, psia 2540 20.29 Maximum Reactor Coolant Pressure, psia 2798 21.19 Maximum Pressuriier Surge Line Flow, Ibm /sec 2783 25.36 Maximum Steam Generator Pressure, psia 1238 3 27.04 Minimum Pressurizer Steam Volume, ft 587 29.37 Pressurizer Safety Valves Close, psia 2070 39.00 Main Steam Safety Valves Close. Unaffected LOOP psia 1151 78.35 Emergency Feedwater Flow Initiated to the intact Steam Generator, 500 gpm 104.60 Steam Generator Pressure Reaches Main Steam Isolation Signal 719 Analysis Setpoint, psia 110.35 Main Steam Isolation Valves Closed - 409.30 Main Steam Safety Valves Open, psia 1212 1800.0 Operator Opens the Atmospheric Steam Dump Valves to Begin Plant Cooldown to Shutdown Cooling - Anwoved Design Meterie!= AccMeet Anotyses Pepe 15.2-16
System 80+ Design ControlDocumust l Q} Table 15.2.8 3 Parameters Used in Evaluating the Radiological Consequences of Feedwater Line Break value h d" MDNBR Case Over Pressure Case A. Data and Assumptions Used to Evaluate the Radioactive Source Term
- 1. Power Level, MWt 3992 3992
'.2 Burnup, MWD /MT 28,000 28,000
- 3. Percent of Fuel Assumed to Experience 0.60 0 DNB,%
4 Reactor Coolant Activity Before Event Tech Spec Tech Spec IU (based on 3992 MWt), Appendix 15A Appendix 15A
- 5. Secondary System Activity Before Event Tech Spec Tech Spec Appendix 15A Appendix 15A
- 6. Pnmary System Liquid Inventory, Ibm 638,000 638,000
- 7. Steam Generator inventory, Ibm
- Affected Steam Generator 227,000 170,000
- Intact Steam Generator 227,000 170,000 B. Data and Assumptions Used to Estimate Activity Released from the Secondary System
- 1. Primary to Secondary Izak Rate, gpm 1.0 (total) 1.0 (total)
- 2. Total Mass Release into contamment 174,200 217.600 from the Affected Steam Generator, Ibm (0-30 min)
- 3. Total rnass release via MSSV's from 163,500 117,900 both SG's, Ibm (0-30 min)
- 4. Total Mass Release via ADV's from the 1,280.490 (2 hrs) 1,280,490 (2 hrs)
Intact Steam Generator after 30 mins, 2,815,000 (8 hrs) 2,815,000 (8 hrs) lbm
- 5. Percent of Core Inventory of Volatile 5 N/A Fission Products Assumed in the gap
- 6. Iodine / Cesium / Rubidium 1.0 1.0 Decontamination Factor in the Affected Steam Generator
- 7. Iodine / Cesium / Rubidium 100 100 Decontamination Factor in the intact Steam Generator
- 8. Peaking Factor 1.58 N/A
- 9. less of Offsite Power Yes Yes ,
r i V IU Except for cases assuming pre existing and concurrent iodine spike. L a-2 Deep aseseria!- AccMurt AmWyees rege 15.217
System 80+ oesign controlDocwnent Table 15.2.8-3 Parameters Used in Evaluating the Radiological Consequences of Feedwater Line Dreak (Cont'd.) Value Parameter MDNBR Case Over Pressure Case
- 10. Containment Leakage
- 1. Containment Volume, ft3 3.34E-06 3.34E-06
- 2. Containment leak Rate, vol.
%/ day 0-24 hrs 0.5 0.5 1-30 day 0.25 0.25
- 3. Natural Deposition in Yes N/A Contamment A-0.15 hr8 for particulate
- 4. Credit for Radioactive Deay
- Hold up in Containment Yes Yes
- In Transit to Dose Point No No
- 11. Engineered Safety Features
- 1. Containment Spray Credit None None
- 2. Annulus Building Ventilation None None Credit
- 3. Contamment Power Purge Isolation Scenario A
- a. Isolation Time 30 secs 30 secs
- b. Flowrate 16000 cfm 16000cfm
- c. Filter efficiency None None Scenado B
- a. Isolation Time 30 mins 30 mins
- b. Flowrate Prior to 1250 cfm 1250 cfm Isolation
- c. Filter efficiency 99% particulate 99% Particulate C. Dispersion Data Atmospheric Dispersion Factor, 1.0 x 10-3 1.0 x 10-3 d 4 sec/m3 ,0-2 hr at EAB (0-8 hr LPZ) (1.35 x 10 ) (1.35 x 10 )
D. Dose Data
- 1. Method of Dose Calculation Appendix 15A Appendix 15A
- 2. Dose Conversion Assumptions Appendix 1$A Appendix 15A O
Approwd Design Meteniel
- AccMeest Anotyses Page 15.218 i
System 80+ Desian controlDocument Radiological Consequences of Feedwater L!ne Break (d" Table 15.2.8-4
- t Offsite Doses (rem)
MDNBR Case Over Pressure Case
- 1. Exclusion Area Boundary (0-2 hours) i
- a. Thyroid 15.6 19.5 (PIS)D1 15.2 (GIS)Ul I
- b. Whole-Body 0.12 0.033 (PIS) 0.032 (GIS)
- 2. lew Population Zone (0-8 hours)
- a. Thyroid 7.66 8.4 (PIS) 21.6 (GIS)
- b. Whole-Body 0.05 0.010 (PIS) ,
0.013 (GIS) { i O , l t i i r l l O ! b ! 01 Values are provided for a Pre-existing Iodine Spike (PIS) and for an event Generated lodine Spike (GIS) i Nweved Deep neesord. Accuent A& page 15.2.ss
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, . i 15.3.1 TotalIAss of Reactor Coolant Flow
- 15.3.1.1 Identification of Events and Causes ;
.A complete loss of forced reactor coolant flow will result from the simultaneous loss of electrical power 1 ' to all reactor coolant pumps (RCPs). The only credible failure which can result in a simultaneous loss of power is a complete loss of offsite power. In addition, since a loss of offsite power is assumed to result in a turbine trip and renders the steam dump and bypass system function unavailable, the plant cooldown is performed utilizing the main steam safety valves and .hr.o.phic dump valves.
A total loss of forced reactor coolant flow will produce a muumum DNBR more adverse than any partial loss of forced reactor coolant flow event.
. The loss of offsite power event plus a single failure will not result in a lower DNBR than that calculated -
j for the loss of offsite power event alone. For decreasing reactor coolant flow events, the major parameter
. of concern is the minimum hot channel DNBR. This parameter establishes whether a fuel design limit ;
has been violated and, thus, whether fuel damage might be anticipated. Those factors which cause a ; decrease in local DNBR are: o Increasing coolant temperature ; 4 e Decreasing coolant pressure l e Increasing local heat flux (including radial and axial power distribution effects)
)
e Decreasing coolant flow ; i For the loss of offsite power event, the minimum DNBR occurs during the first few seconds of the transient and the reactor is tripped by the Core Protection Calculators (CPCs) on the approach to the : i DNBR limit. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first few seconds of the event. None of the single failures listed in Table 15.04 will have any effect on the transient minimum DNBR during this period of time. Additionally, none of the single failures listed in Table 15.04 will have any effect on the peak primary system pressure. The loss of offsite power will make unavailable any systems whose failure could affect the calculated peak pressure. For example, a failure of the steam dump and bypass system to modulate or quick open and a failure of the pressurizer spray control valve to open involve systems ! (Steam Dump and Bypass System and Preswrizer Pressure Control System (PPCS)) which are assumed ,
- to be in the manual mode as a result of theloss of offsite power and, hence, unavailable for at least 30 l
< minutes. Another example involving the PPCS would be the failure of the back-up heaters to turn off.
. Since the event is characterized by increasing RCS pressure, the back-up heaters will not be called upon i to operate in such a transient.
For the reasons stated in the above paragraphs, the loss of offsite power event with a single failure is no i ^ more adverse than the loss of offsite power event in terms of the minimum DNBR and peak pnmary :
# l system pressure.
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System 80+ Design ControlDocument 15.3.1.2 Sequence of Events and Systems Operation Table 15.3.1-1 preserts a chronological list and time of systems actions which occur during the total loss of reactor cociant flw event. The sequence of evetts and systems operations represents the way in which the plant was assumed to respond to the event initiator. Many plant responses are possible. However, certain responses are limiting with respect to the acceptance guidelines for this section. Of the limiting responses, the most likely one to be followed was selected. 15.3.1.3 Analysis of Effects and Consequences
- Mathematical Model The NSSS response to a total loss of reactor coolant flow was simulated using the CESEC-III computer program. The minimum DNBR was calculated using the CETOP computer code, which uses the CE-1 CHF correlation, and the HERMITE computer code. A description of the total loss of reactor coolant flow methodology is referenced in Section 15.0.3.1.1.
- Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a total loss of flow are discussed in Section 15.0. The parameters, which are unique to the analysis, discussed below, are listed in Table 15.3.1-2.
The principal process variables that determine thermal margin to DNB in the core are monitored by COLSS. COLSS computes a power-operating limit which assists the operator in maintaining the thermal margin in the core greater than that needed to cause the minimum DNBR to remain greater than 1.24, for a four-pump loss of flow. COLSS is described in Section 7.7. The set of initial conditions chosen for the analysis presented in this section is one of a very large number of combinations within the reactor operating space given in Table 15.0-3 which would provide the minimum thennal margin required by the COLSS power operating limit. The consequences following a total loss of flow initiated from any one of these combinations of conditions would be no more adverse, with respect to core thermal margin, than tl ose presented herein.
- Results The dynamic behavior of important NSSS parameters following a total loss of reactor coolant flow is provided in Figures 15.3.1-1 through 15.3.1-8.
The loss of offsite power causes the plant to experience a simultaneous turbine trip, loss of main feedwater, condenser inoperability, and a coastdown of all four reactor coolant pumps. The loss of steam flow due to closure of the turbine stop valves results in a rapid increase in the steam generator pressure. A sharp reduction in primary-to-secondary heat transfer follows which, in conjunction with the loss of forced reactor coolant flow, causes a rapid heatup of the primary coolant. The Pressurizer Safety Valves open at 4.90 seconds. The Main Steam Safety Valves (MSSVs) open at 9.60 seconds. The RCS pressure reaches a maximum of 2652 psia (including the pressure difference between the cold leg at the primary coolant pump discharge and the surge line) at 5.59 seconds (Figure 15.3.1-3). At 14.10 seconds the steam generator pressure reaches its maximum value of 1249 psia (Figure 15.3.1-7). AAereved Desigts Meterial- Acciderst J ontyres Page 15.32
~ System 80+ Deslan ConkelDocument i. S+====ely, the RCS pressure decreases rapidly as the combination of reactor trip, pressurizer ' safety valve and main steam safety valves opening reduce the reactor coolant system energy. - After 30 minutes, the operator commences cooldown using the emergency feedwater system and :
; the atmospheric steam dump system.
The minimum CE-1 DNBR calculated to occur during the transient is 1.27 (Figure 15.3.1-8); f
. thus, no fuel pins are assumed to experience DNB for this event.
The RCS and steam generator pressures reach 2652 psia and 1249 psia, respectively. A sepa: ate I analysis performed to maximize the primary and secondary system pressures shows that the peak ,
!- RCS and steam system pressures do not exceed 2665 and 1273 psia, respectively. The peak l pressure analysis used the initial core inlet coolant temperature of 561'F, and the initial steam !
generator pressure of 1054 psia, with all other initial condition parameter values as listed in Table l 15.3.1-2. The reported peak RCS pressures include the pressure difference between cold leg at RCP discharge and the surge line. These values are less than 110% of design RCS and steam l generator pressures. i 15.3.1.4 Conclusions ; The maximum RCS and steam generator pressures remain within 110% of their respective design values !
- following the total loss of forced reactor coolant flow event. The minimum DNBR calculated to occur ;
- during the transient is greater than 1.24, which ensures that the specified acceptable fuel design limit is j 4
not violated. , i 15.3.2 Flow Contreuer Malfunction Causing Mow Canddawn
- ~
This event is categorized as a Boiling Water Reactor event in SRP 15.3.2 and, therefore, will not be i analyzed. i 15.3.3 Single Reactor Caala=# Pump Rotor Seizure with Loss of Offsite Power } i 15.3.3.1 Identification of Event and Causes A single reactor coolant pump rotor seizure can be caused by seizure of the upper or lower thrust journal bearings. Loss of offsite power, as a result of the turbine generator trip, may be caused by a complete ; loss of the external electrical grid triggered by the turbine generator trip. The onsite loads will j subsequently lose power and the plant will experience a simultaneous loss of feedwater flow, condenser j
. inoperability, and a coastdown of all reactor coolant pumps. Following the loss of offsite power, the l < diesel generators start providing power to the two plant 4.16 kV safety buses. No credit is taken for j 6
restoration of offsite power prior to initiation of shutdown cooling. 4 4 For decreasing reactor coolant flow events, the major parameter of concern is the mimmum hot channel 4 DNBR. This parameter establishes whether a fuel design limit has been violated and, thus, whether fuel !
. damage could be anticipated. A second parameter of concern is the peak RCS pressure attained. Those j
' factors which cause a decrease in local DNBR are: !
I
* - Increasing coolant temperature ,
- Decreasing coolant pressure i
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l System 80' Design ControlDocument l l 1
- Increasing local heat flux (including radial and axial distribution effects)
- Decreasing coolant flow ,
l For the single reactor coolant pump rotor seizure event, the minimum DNBR occurs during the first one to four seconds of the transient, and the reactor is tripped by the RPS on low reactor coolant flow. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first one to four seconds of the event. The single failures that have been postulated are listed in Table 15.04. Most of these failures affect the secondary system, and during the first one to four seconds they do not affect the primary system parameters which determine the DNBR. The only failures which could affect the RCS behavior during this interval are:
- Failure of the pressurizer level control system
- Failure of the pressurizer pressure control system
- Failure of the reactor regulating system The loss of normal AC power, which is assumed, results in loss of power to the reactor coolant pumps, the condensate pumps and the circulating water pumps. The functions performed by the pressurizer pre.sure and level control systems, the reactor regulating system, the feedwater control system and the steam bypass control system are also lost upon loss of AC power.
Loss of power to the reactor regulating system and pressurizer level and pressure control system functions will have no significant impact on DNBR during the first one to four seconds. Thus, none of the single failures listed in Table 15.04 will result in a more adverse transient minimum DNBR than that predicted for the single reactor coolant pump rotor seizure event. The assumed loss of AC renders the steam bypass control system functions inoperable as a result of the loss of the circulating water pumps. This results in the secondary system energy being released to the atmosphere by the main steam safety valves (prior to operator action) and the Atmospheric Dump Valves (ADVs) after operator action is assumed. Operator action is assumed 1800 seconds into the transient. At this time, the operator attempts a controlled cooldown of the plant. l A single active failure of an ADV to close is assumed at 1800 seconds. The stuck open ADV causes excessive steam to be released from the steam generators. Thus, this failure in combination with the loss of offsite power maximizes the radiological consequences of the single reactor coolant pump rotor seizure event. None of the other single failures listed in Table 15.0-4 in combination with a loss of AC will yield more severe radiological consequences than that presented here. 15.3.3.2 Sequence of Events and Systems Operation Table 15.3.3-1 presents a chronological list and time of system actions which occur following the single reactor coolant pump rotor seizure event for initial conditions selected to minimize the DNBR and maximize the radiological release. A separate case was analyzed with maximum initial pressure to determine the maximum pressure transient. ANwoved Destyn Meterlaf AccJdent Ana&ses Pope 15.34
I l t System 80+ Design ControlDecanent ; The loss of offsite power is assumed to occur due to grid instability. No delay between the time of ; turbine trip and the time of bss of offsite power is assumed in the final analysis. Earlier analysis assumed a 3 second time delay. .l The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. If offsite power can be restored, the operator may elect instead to stabilim the plant at a mode other than cold shutdown. All actions required to stabilize the plant and perform the required repairs are , not described here. i The sequence of events and systems operations represents the way in which the plant was assemed to .! respond to the event initiator. Many plant responses are possible. However, certain responses are limiting with respect to the accee guidelines for this section. Of the limiting responses, the inost j likely one to be followed was selected. l l 15.3.3.3 Analysis of Effects and Consequences j i 15.3.3.3.1 Core and Systen Perfor==ce e Mathematical Model I i The NSSS response to a single reactor coolant pump rotor seizure with loss of offsite power ! concurrent with turbine trip was simulated using the CESEC-III computer program referenced ; in Section 15.0. In addition, the HERMITE code, referenced in Section 15.0, was used to I determine the short-term response of the reactor core during the postulated RCP rotor seizure ! event. The DNBR is calculated using the TORC and CETOP computer codes (see Section l 15.0.3) which use the CE-1 CHF correlation described in References 18,19, 21 and 29 of l I Section 15.0. e Input Parameters and Initial Conditions l The ranges of initial conditions considered are given in Section 15.0. Table 15.3.3-2 gives the initial conditions used in the analysis of the radiological consequences. The rationale for selecting the values of the initial conditions which have a first order effect on the analysis follows. Using ; I the highest core power maximizes the RCS heatup, which is the driving force of the secondary steam release. Based on the parametric studies the most adverse combination of initial conditions was selected to maximize the amount of failed fuel. A high primary system pressure and a low core inlet temperature were chosen, in conjunction with the radial peaking factor compatible with these initial conditions, to initiate the event from a Power Operating Limit (POL) allowed by 8 COLSS. The reactor coolant flow was chosen to be its mmimum value of 154.5 x 10 lbm/hr. The most positive moderator tempenature coefficient and the minimum available scram CEA worth tend to maximize the heat flux after a reactor trip occurs, increasing the RCS heatup. The operator initiates the plant cooldown with the rate assumed to maxinuze the offsite doses. During this event, two sources of radioactivity contribute to the offsite doses: the initial activity in the steam generator, and the activity associated with the assumed one gallon per minute steam generator tube leak. The initial iodine secondary activity is assumed to be 0.1 pCi/gm dose equivalent 1-131. The initial iodine activity assumed to be present in the reactor coolant leakmg through the steam generator tubes is 1.0 pCi/gm. t' Anwevent Den 6e aaneener. Aceinun Anemeen rene 15.3-5 2 _ _ . . . _ - _ _ _ _ _. . _
System 80+ Design ControlDocument e Results The dynamic behavior of important NSSS parameters following a single reactor coolant pump rotor seizure with a loss of offsite power is presented on Figures 15.3.3-1 through 15.3.3-13. Table 15.3.3-1 summarizes the significant results of the event. The single reactor coolant pump rotor seizure event results in a flow coast down in the affected loop, a consequent reduction in flow through the core, an increase in the average coolant temperature in the core, a corresponding reduction in the margin to DNB, and an increase in the primary system pressure. A reactor trip on low reactor coolant flow is generated by the Reactor Protection System. The reactor trip causes the turbine generator to trip at 1.42 sec. The CEAs begin to drop into the core at 1.92 seconds. At the time of the turbine / generator trip loss of offsite power is assumed to occur. The remaining RCPs begin their normal coastdown after the loss of offsite power. The loss of offsite power also causes a loss of main feedwater and condenser inoperability. The turbine trip with the Steam Bypass Control System (SBCS) and the condenser unavailable leads to a rapid buildup in secondary system pressure and temperature. This increase in pressure is shown in Figure 15.3.3-10. The opening of the MSSVs limits this pressure increase. The maximum secondary system pressure is 1248 psia which is less than 110% of design pressure. The increasing temperature of the secondary system leads to a reduction of the prunary to secondary heat transfer. Concurrently, the failed reactor coolant pump and the three reactor coolant pumps coasting down(Figure 15.3.3-9) result in a lower RCS flow which further reduces the heat transfer capability of the RCS. This decrease in heat removal from the RCS leads to an increase in the core coolant temperatures as shown in Figure 15.3.3-6. The core coolant temperatures peak shortly after the time of reaaor trip. The increase in RCS temperature leads to an increase in RCS pressure, as shown in Figure 15.3.3-5, caused by the thermal expansion of the RCS fluid. The Pressurizer Safety Valves (PSVs) open at 4.88 seconds. At 5.01 seconds the RCS pressure reaches a maximum value of 2615 psia which is less than 110% of design pressure. After this time, the RCS pressure decreases rapidly due to the declining core heat flux (see Figures 15.3.3-3 and 15.3.3-4), in combination with the opening of the PSVs and Main Steam Safety Valves (MSSVs). Opening of the MSSVs limits the peak temperature and pressure of the secondary system. The MSSV's cycling frequency decreases after the emergency feedwater begins entering the st ,am generators. , Emergency feedwater begins entering the steam generator in the unaffected loop at 605.7 seconds, ! thus, enhancing the RCS cooldown and the subsequent reduction in pressure. During the first few seconds of the transient, the combination of decreasing flow rate, and increasing RCS temperatures results in a decrease in the fuel pins' DNBR. The transient minimum DNBR and the time it occurs is indicated in Table 15.3.3-1. Figure 15.3.311 shows the variation of the minimum DNBR with time. The negative CEA reactivity inserted after reactor trip causes a rapid power and heat flux decrease which causes DNBR to increase again. The percentage of the fuel pins which are calculated for this event to experience DNB is shown in Table 15.3.3-3. All fuel pins which experience DNB are conservatively assumed to fail. At 30 minutes the operator is assumed to use the ADVs to begin cooldown. At this time one of the ADVs is assumed to stick open. The release path of the primary to secondary leakage via Approved Design heatertiel Accident Andyses Page r5.3-6 L
1: p 4 L i Sv=*=m 80 + ' Design ConeralDocenent the stuck open ADV is not desirable as it is not controllable by the operator and thus requires closing the block valve upstream of that ADV not later than in 6 minutes (Reference 30) ! i following the detection of the stuck open condition. However, as explained below, the exact timing of the detection of the stuck open ADV condition f is irrelevant to the e* of events per assumptions of this analysis which are aimed at , j creating a scenario to maximize the radiological consequences. { There are several possible scenarios of detecting the stuck open ADV condition by the operator f 4 during the course of the controlled cooldown following the seized rotor accident. The most j
- probable is that upon reaching the RCS temperature of 550 *F, which would prevent any further
. steaming via the MSSVs, the operator would attempt to reduce the cooldown rate by trying to l close the ADV. This would occur at about 2850 seconds and would lead to closing of the block valve at 3210 seconds (i.e. within 3600 seconds as indicated in Table 15.3.3-1). j i
The analysis assumption aimed at maximizing the two hour offsite doses by maintaining the ; cooldown rate of 100 'F/hr implies requiring further opening of the remaining ADVs in order. , to continue cooldown. That is, the effect of closing of the ADV will be overridden by the : i- analysis assumptions. To maximize the radiological releases beyond two hours, it is assumed that the cooldown will j t i continue through the following six hours. This requires that the release path from primary via secondary to the atmosphere remain available for the longest possible time period. However, not ! i isolating the stuck open ADV in sufficient time (at or shortly after two hours) would lead to reaching the shutdown cooling entry conditions at some time earlier and will Iesult in isolating , the release path earlier. Thus the offsite doses for eight hours will not be maximized. j l Therefore, to maximize the doses at eight hours, the release path via the open ADVs must be j maintained available throughout the eight hours. This requires that the stuck open ADV be closed in sufficient time (following the first two hour time period - in order to maximize both the two hour and eight hour doses), such that other ADVs, which have been subsequently or , concurrently opened, can be assumed to remain controllable and open until eight hours. The above indicates that the actual timing of the stuck open ADV condition has no significant , unpact on the maximized radiological releases, due to the analysis assuraptions used. i The offsite doses for this event result from steam released through the Main Steam Safc*y Valves l i (MSSVs) and Atmospheric Dump Valves (ADVs). Table 15.3.3-4 shows the integrated steam release from the MSSVs and the ADVs. The steam released during the transient results in offsite doses as shown in Table 15.3.3-5. l l The RCS peak pressure reaches 2615 psia (including the pressure difference between the RCP discharge and the surge line). This value is less than 110% of design RCS pressure. Figure l 15.3.3-13 shows the transient peak pressure. A separate analysis performed to maximize the primary and secondary system pressures shows I that the peak RCS and steam system pressures do not exceed 2635 and 1273 psia, respectively, j f
-N These values are less than 110% of design RCS and steam generator pressures, respectively. The peak RCS pressure includes the pressure difference between the cold leg at RCP discharge and j
l the surge line. The peak pressure analysis used the initial core inlet coolant temperature of j 1 Suwww mesen afeterW- AceMuW Ams%es Aspe f5. M
System 80+ Design ControlDocument 561*F, and the iuitial steam generator pressure of 1054 psia, with all other initial condition parameter values as listed in Table 15.3.3-2. 15.3.3.3.2 Radiological Consequences A. Physical Model To evaluate the consequences of the single reactor coolant pump rotor seizure with a loss of offsite power event, it is assumed that the condenser is not available for the entirety of the transient. For the first thirty minutes of the event, the cooldown is performed by the main steam safety valves. Afterwards, the atmospheric dump valves are actuated by the operator in an attempt to initiate a controlled cooldown. An ADV is assumed to stick open at 30 minutes into the event. At 60 minutes, the operator closes the block valve situated upstream of the stuck open ADV and continues the controlled cooldown at 100*F/hr using the remaining atmospheric dump valves of the steam generators and the emergency feedwater system.
- Assumptions, Parameters, and Calculational Methods The analysis is performed for 2 cases, assuming:
- a concurrent iodine spike (GIS),
a failed fuel. The major assumptions, parameters, and calculational methods used to evaluate the radiological consequences of the single reactor coolant pump rotor seizure are presented in Tables 15.3.3-3 and 15.3.3-4. Additional clarification is provided in Appendix 15A and below:
- 1. Offsite power is not available. At 1800 seconds the operator attempts to take control of the plant using the atmospheric dump valves. One atmospheric dump valve is assumed to stick open from 1800 seconds.
- 2. Credit is assumed for emergency feedwater flow. For the fluid leaked from primary to secondary, iodine is assumed to be released to the atmosphere with a decontamination factor (DF) of 100. For the failed fuel case, the primary to secondary leakage contains iodine, cesium and rubidium with the same DF applied (as described in Appendix 15A).
- 3. Table 15.3.3-4 presents the integrated mass release from the secondary system and the steam generator liquid inventory.
- 4. Calculated secondary mass releases are presented in Table 15.3.3-3.
15.3.3.4 Conclusions The maximum RCS and steam generator pressures due to a single reactor coolant pump rotor seizure event in combination with loss of offsite power coincident with turbine generator trip remain below 110% of their respective design values. Only a small fraction of the fuel pins experience DNB and are conservatively assumed to fail. The two-hour thyroid and whole-body doses at the EAB and the eight-hour thyroid and whole-body doses at the LPZ are within 10 CFR 100 guidelines (see Table 15.3.3-5). Control Room doses are provided in Section 6.4.3. Approved Desips afeterial Accichent Analyses Page 15.38
System 80 + Desian contratDocument i r 15.3.4 Reactor Coolant Pump Shaft Break with Loss of Offsite Power { i 15.3.4.1 Identification of Event and Causes A single reactor coolant pump sheared shaft could be caused by mechanical failure of the pump shaft. This is assumed to result from a manufacturing defect in the shaft. Loss of offsite power following ' turbine generator trip may be caused by a complete loss of the external electrical grid triggered by the turbine generator trip. 15.3.4.2 Sequence of Events and Systems Operation . I The sequence of events and systems operations is similar to that for the reactor coolant pump rotor ~ seizure everd, Section 15.3.3. For both the shaft break event and the pump rotor seizure event, the reactor is tripped by the RPS on a low reactor coolant flow condition. For both RS and SB, a Loss of Offsite Power (LOOP) was assumed concurrent with turbine trip. The flow coastdown for a Rotor Seizure (RS) event is faster than the coastdown for a Shaft Break (SB) event. For a shaft break, the rotor is still capable of rotating, thereby offering less resistance to flow ! during the rapid flow decrease. This results in a less severe coastdown for the shaft break event than for the rotor seizure event. The SB trip time is 0.3 seconds later than the RS trip time. Despite the later trip time, the slower SB coastdown results in a higher minimum DNBR and less fuel failure for SB with LOOP than for RS with LOOP. f 15.3.4.3 Analysis of Effects and Consequences 15.3.4.3.1 Core and Systeen Perfonnance The analysis of effects and consequences for this event is similar to that for the reactor coolant pump rotor seizure event, Section 15.3.3. The SB coastdown is slower than that of the rotor seizure event. The SB with LOOP event produces a higher minimum DNBR and less radiological release than RS with LOOP. 15.3.4.3.2 Radiological Consequences The radiological consequences due to steam release from the secondary system would be less than the consequences of the RS event as described in Section 15.3.3. Thus, the thyroid inhalation and whole-l body doses for the SB with loss of offsite power event are less than the values in Table 15.3.3-5. 15.3.4.4 Conclusions The conclusion from the SB event is that this event would be no more adverse than the RS event. For j both events the total number of fuel pins calculated in DNB, and which are consentatively assumed to fail, is presented in Table 15.3.3-3. The resultant radiological consequences which are given in Table 15.3.3-5 are within the guidelines of 10 CFR 100. l l 7 L d Destn AfsearW. AosMost Anahoes page 75.3-9
System 80+ Design ControlDocument Table 15.3.1-1 Sequence of Events for Total Loss of Reactor Coolant Flow Time (sec) Event Setpoint or Value 0.0 Loss of Offsite Power
- Turbine Trip
- Diesel Generator Staning Signal
- Reactor Coolant Pumps Coast Down
- Main Feedwater is lest 0.82 lew Pump Speed Trip Condition Reached, Fraction of Full Speed 0.95 0.97 CPC Trip Signalis Generated Iew DNBR -
1.12 Trip Breakers Open 1.62 CEAs Begin to Drop -- 3.66 Minimum Transient DNBR 1.27 4.90 Pressurizer Safety Valve Open, psia 2540 5.59 Maximum RCS Pressure, psia 2652 9.60 Main Steam Safety Valves Open, psia 1212 11.81 Pressurizer Safety Valve Close, psia 2070 14.10 Maximum Steam Generator Pressure, psia 1249 1800.0 Operator initiates Plant CooldowTi Table 15.3.1-2 Assumptions and Initial Conditions for Total Loss of Reactor Coolant Flow l Parameter Assumed Value Core Power level, MWt 3992 Core Inlet Coolant Temperature 'F 550 Pressurizer Pressure, psia 2325 Steam Generator Pressure, psia %3 6 Core Mass Flow,10 lbm/hr 154.5 Core Minimum DNBR 1.62 Maximum Radial Pealing Factor 1.66 CEA Wonh on Trip, Ig2 Ap (most reactive CEA Stuck) -8.86 Moderator Temperature Coefficient, Ap/*F -0.1 x10-' Doppler Reactivity Table 15.0-5 I Apnprend Design Afstenet- Accident Analyses Page 15.3.r0
System 80+ Design ControlDocument m Id Table 15.3.3-1 Sequence of Events for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Setpoint Time (sec) Event Setpoint or Value 0.0 Seizure of a Single Reactor Coolant Pump - 0.22 low Reactor Coolant Flow Trip Condition Reached. Fraction of 0.80 Hot leg Flow 1.27 Low Reactor Coolant Flow Reactor Trip Signal Generated - 1.42 Reactor Trip Breakers Open 1.42 Turbine Trip / Generator Trip 1.42 Loss of Offsite Power Occurs 1.92 CEAs Begin to Drop into the Core 3.40 Minimum Transient DNBR 1.09 4.88 Pressurizer Safety Valve Open, psia 2540 5.01 Maximum RCS Pressure, psia 2615 11.20 herizer Safety Valve Close, psia 2070 11.80 Main SA:s Safety Valves Open. Unaffected Loop, psia 1212 12.70 Main Steam Safety Valves Open, Affected loop, psia 1212 O V 19.2 20.1 Maximum Steam Generator Pressure Affected Loop, psia Maximum Steam Generator Pressure, Unaffected loop,, psia 1248 1247 545.7 Steam Generator Water level Reaches Emergency Feedwater 19.9 Actuation Signal Analysis Setpoint in the Unaffected loop,
% Wide Range 605.7 Emergency Feedwater Begins Entering Steam Generator, 68.7 Unaffected loop, Ibm /sec 1224.6 Steam Generator Water level Reaches Emergency Feedwater 19.9 Actuation Signal Analysis Setpoint in the Affected loop,
% Wide Range 1284.6 Emergency Feedwater Begins Entering the Steam Generator, 68.7 Affected loop, Ibm /sec 1784.6 Main Steam Safety Valves Close, Affected and Unaffected Loop, 1151 psia 1800 Atmospheric Dump Valves Opened to initiate Plant Cooldown, -100.0
'F/ hour.
One Atmospheric Dump Valve Sticks Open 3600 Block Valve Upstream of Stuck Open ADV Closed -- 28800 Shutdown Cooling Initiated, RCS Pressure / Temperature, psia /'F 330/350 A (v) Pa. : Der $ Maserie!- AccMent Ane&ser page 15.311
Design ControlDocument yttem 80+ Table 15.3.3-2 Assumptions and Initial Canditions for the Analysis of Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Parameter Value Core Power level, MWt 3992 Core inlet Coolant Temperature, 'F 550 Reactor Coolant System Pressure, psia 2337 Pressurizer Pressure, psia 2325 Steam Generator Pressure, psia %3 Core Mass Flow,106 lbm/hr 154.5 Maximum Radial Power Peaking Factor 1.66 1.62 Core Minimum DNBR 0.85 Doppler Coefficient Multiplier CEA Worth for Trip,10 Ap 3 (most reactive CEA Stuck out) -8.86 4 Moderator Temperature Coefficient, Apx10 /'F -0.1 Doppler Reactivity Table 15.0-5 O 1 I l I G: ANwoM Des > MeterW . AccMent Ana,'yses page gg,3.gg I
System 80+ oesian controlDocumart F 'N Table 15.3.3-3 Parameters used in Evaluating the Radiological Consequences of a b) Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip t Parameters Value 7 A. Data and Assumptions Used to Evaluate the Event's Radioactive Source Term
- 1. Core Power level, MWt 3992
- 2. Burnup, MWD /T 28,000
- 3. Perrent of Fuel Calculated to Experience DNB, % 1.2N
- 4. Reactor Coolant Activity Before Event Appendix 15A
- 5. handmy System Activity Before Event, pCi/gm Appendix 15A
- 6. Pnmary System Liquid Inventory, Ibm 605,000 [
- 7. Steam Generator inventory: '
- Liquid, Ibm per steam generator 197,000
- Steam, Ibm per steam generator 15,160 B. Data and Assumptions Used to Estimate Activity Released from the Secondary System
- 1. Primary-to handmy leak Rate, gpm 1.0 (total)
- 2. Total Ma= Release Through the Main Steam Safety Valves, Ibm Table 15.3.3-4
- 3. Total Mass Release Through the ADVs from 30 to 120 Minutes, Ibm Table 15.3.3-4 l
- 4. Percent of Core Fission Products Assumed Released to Reactor Coolant See App. ISA i
- 5. lodine Decontamination Factor for the Unaffected Steam Generator 100m
- 6. lodine Darnat==ination Factor for the Affected Steam Generator 100m
- 7. Credit for Radioactive Decay in Transit to Dose Point No O C.
- 8. Loss of Offsite Power Atmospheric Dispersion Factors
~
Yes i
- 1. at EAB,0-2 hr, sec/m S Table 2.3-1 l'
- 2. at LPZ,0-8 hr, sec/m2 Table 2.3-1 D. Dose Data
- 1. Method of Dose Calculation Appendix 15A
- 2. Dose Conversion Assumptions Appendix 15A l
N It! No failed fud assumed for GIS (Generated Iodine Spike) doses. l A Also, applicable to Cesium and Rubidium for the failed fuel case (see Appendix 15A). L ::Deedgra aineenin!* AccMorrt AWee (2Aps) pape rg.3-r3 , l
1 1 System 80+ Design ControlDocament Table 15.3.3-4 Secondary System Mass Release to the Atmosphere for the Single Reactor Coolant Pump Rotor Seizure vith Loss of Offsite Power Resulting from Turbine Trip Event Minimum SG Liquid Mass Cumulati7e Steam Releases (lbm) MSSVs Total Time (sec) Unaffected (Ibm) Affected (Ibm) UnalTected SG Affected SG (incl. ADV) 0.000 197021. 197021. O. O. O. I1.200 205082. 219448. O. O. O. 74.100 180933, 212331. 25977. 17918. 43895. 263.60 157739, 202082. 57455. 17918. 75373. 407.40 146831. 192151. 67292. 27689, 94981. 138161. 181875. 76411. 36938. 113349, 553.00 682.80 145915. 172793. 76411. 47032. 123443. 848.60 140345, 161723. 85395. 56016. 141412. 1038.2 140420. 149485. 94118. 64804, 158922. 1229.8 140$$6. 138010. 1U2579. 73265. 175844. 1503.2 139849. 139765. I11039. 81725. 192764.
~
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-15.4 haceivity and Power Distribution Ana==be 15.4.1' Uncestrolled Control nemend Assemibly Withdrawal froam Subedtical or IAw Power C==mda- with less of Offsite Power 15.4.1.1 Identification of Event and Causes An uncontrolled sequential withdrawal of CEAs is assumed to occur as a result of a single failure in the Control Element Drive Mechanism Control System (CEDMCS), Reactor Regulating System (RRS), or as a result of operator error. The earlier CEA withdrawal analysis did not consider a loss of offsite power (LOOP). In compliance with GDC 17, i.e., considering the event with and without LOOP, the final limiting case presented assumes a LOOP which resulted from a turbine generator trip coincident with a reactor trip.
15.4.1.2 Sequesace of Events and Systeams Operation The withdrawal of CEAs from suberitical or low power conditions adds reactivity to the reactor core, causing both the core power level and the core heat flux to increase together with correspondmg increases in reactor coolant temperatures and Reactor Coolant System (RCS) pressure. The withdrawal motion of CEAs also produces a time dapandant redistribution of core power. These transient variations in core thermal parameters result in the system's approach to the specified fuel design limits, thereby requiring the protective action of the Reactor Protection System (RPS). The total energy generated during the power excursion at low power is larger than during the subcritical case. Thus, only the low power case is presented here. Table 15.4.1-1 gives the === ace of events for the limiting CEA withdrawal transient at low power with j loss of offsite power identified in Section 15.4.1.3. A loss of offsite power was assumed to be coincident with a turbine trip. The CEA withdrawal at low power with a loss of offsite power was determined to be limiting relative to the CEA withdrawal at low power without a loss of offsite power. 15.4.1.3 Analysis of Effects and Consequences e Mathematical Model l The Nuclear Steam Supply System (NSSS) response to a CEA sequential withdrawal from subcritical or low power conditions was sinulated using the CESEC-III computer program described in Section 15.0. The :hermal margin on DNBR in the reactor core was simulated using the CETOP computer program described in Section 15.0 with the CE-1 CHF correlation referenced in Section 15.0. e input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a CEA sequential withdrawal from suberitical or low power conditions with a loss of offsite power are discussed in Section 15.0. In particular, those parameters which were unique to the analysis discussed below are listed in Table 15.4.1-2. bO-The initial conditions and NSSS characteristics assumed in this analysis have been deternuned to i be the limiting set of conditions allowed by the limiting conditions for operation (LCOs) in terms of providing the closest approach to the fuel design limits for a CEA withdrawal at low power L 4 posed asetpe assondW- AceWast AmWpoor Phee 75.4 f
System 80+ Design ControlDocument with a loss of offsite power. The initial conditions which provide the closest approach to the fuel design limits correspond to zero power, core inlet temperature of 561*F, core inlet flow of 95% and minimum RCS pressure of 2175 psia. The initial RCS pressure is chosen to be the lowest allowed pressure within the LCOs since this allows the transient response to the CEA withdrawal to proceed for a longer time by delaying actuation of the high pressurizer pressure trip. The initial core average axial power distribution assumed in the analysis corresponds to an axial shape index (ASI) of -0.3. This ASI was used as the limiting axial power shape for only DNBR calculations. A bottom peaked axial power shape (i.e., +0.3 ASI) was used to model scram reactivity insertion. A 3-D peaking factor of 5.0 including uncertainties, is also conservatively assurr.ed for this analysis. The 3-D peaking factor is the highest peak expected for any CEA configuration and time in core lifetime at low power. An initial power level of 1 x 10-3% of rated core power,0.039 MWt, results in the closest approach to the fuel design limits during the CEA withdrawal transient with a loss of offsite power. Subcritical or zero power CEA withdrawal transients initiated from below 1 x 10r3% rated power will be terminated by the high logarithmic power trip. Transients initiated from power levels above 1 x 10~3% of rated power are terminated by the variable overpower trip, resulting in less limiting consequences than the case presented here. The most positive moderator temperature coefficient allowed by the Technical Specifications 0.0 Ap/*F, is assumed for this analysis to maximize the power increase. The regulating CEA positions are initially in the fully inserted position when the CEA withdrawal is initiated. Based on calculated CEA worths and the maximum CEA withdrawal rate (30 inches / min) of the CEA drive system, the assumed reactivity insertion rate is very conservative. 4 For this analysis, the reactivity insertion is the maximum expected rate of 1.5 x 10 Ap/sec. This insertion rate deviates from the System 80 design in that the System 80+ design utilizes a 3 bank CEA regulating system versus the 5 bank system for System 80. In addition, the reactivity worth of each bank is different between the two designs. The combination of these differences accounts for the two different reactivity rates.
- Results The dynamic behavior of important NSSS parameters following a CEA withdrawal from low power conditions is presented in Figures 15.4.1-1 through 15.4.1-8.
The withdrawal of CEAs from low power conditions (0.039 MWt power) adds reactivity to the reactor core, causing both the core power and the core heat flux to increase. The power transient causes increasing temperature and pressure transients, which together with a top peaked axial power distribution, produce the closest approach to the specified acceptable fuel design limit on DNBR. Since the transient is initiated at low power, one of the normal reactor feedback mechanisms, moderator feedback, does not contribute to any appre-iable extent to the power excursion transient. At 29.30 seconds into the transient, a variable overpower trip is actuated. The CEAs begin dropping into the core and terminate the transient. The hot clumnel minimum DNBR reached during the transient is > 1.24 at 30.30 seconds. If the maximum planar radial peaking factor occurs in the region of the axial power peak, the peak linear heat generation rate during the transient remains less than 21 KW/ft. O Attwend Design Meteriel AccMent Analyses Page rSA-2
Systent 80+ oestar correrer Doewnerrt 15.4.1.4 Conclusions - .'Ihe uncontrolled CEA withdrawd from %beritical or low power conditions with or without a loss of offsite power meets General Dc ian Criteria 25 and 20. These criteria require that the specified arctahle fuel design limits are not enaeded and the protection system action is initiated automatically. The withdrawal of CEAs from low power conditions with or without a loss of offsite power meet the following fuel design limits which serve as the sccymaca criteria for this event: the transient terminates whh a hot channel minimum DNBR greater than or equal to 1.24 and the peak linear heat generation rate
. during the transient is less than 21 KW/ft.
} 15.4.2 Uncontreued Control Elanent Anas==My Withdrawal at Power with Loss of Offsite Power 15.4.2.1 Identification of Event and Causes An uncontrolled sequential withdrawal of CEAs is assumed to occur as a result of a single failure in the Control Element Drive Mechanism Control System (CEDMCS), Reactor Regulating System (RRS), or as a result of operator error. The earlier CEA withdrawal analysis did not consider a loss of offsite power (LOOP). In compliance with GDC 17, i.e., considering the event with and without LOOP, the final limiting case presented assumes a LOOP which resuhed from a turbine generator trip coincident with a reactor trip. i 15.4.2.2 Sequence of Events and Systems Operation F Table 15.4.2-1 presents a chronological sequence of events which occur during a sequential CEA group
~\ withdrawal transient. A loss of offsite power was assumed to be coincident with a turbine trip. The CEA withdrawal at power with a loss of offsite power was determined to be limiting relative to the CEA withdrawal at power without a loss of offsite power.
15.4.2.3 Analysis of Effects and Consequenn== l
- Mathematical Model j l
4 The Nuclear Steam Supply System (NSSS) response to a CEA group withdrawal at power was simulated using the CESEC-III computer program described in Section 15.0. e Input Parameters and Initial Conditions Table 15.4.2-2 lists the assumptions and initial conditions used for this analysis in addition to those discussed in Section 15.0. These initial conditions (i.e., radial power peak, core flow, and inlet temperature) were chosen in order to minimize the hot channel minimum DNBR. The initial conditions and NSSS characteristics used in this analysis yield the mimmum DNBR ! for the CEA group withdrawal with a loss of offsite power incident. The core inlet temperature, pressurizer pressure, core flow and radial peakmg factor were chosen so that the reactor was operating at a Power Operating Limit (POL) at the initiation of the event.
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System 80+ Design ControlDocument The power level from which the withdrawal is initiated was assumed to be 102 % of rated power. The initial core average axial power distribution for this analysis is a shape characterized by an axial shape index equal to -0.3. This ASI was used as the limiting axial power shape for only DNBR calculations. A bottom peaked axial power shape (i.e., +0.3 ASI) was used to model scram reactivity insenion. Other input parameters which are imponant to this analyses are the Moderator Temperature Coefficient (MTC) and Fuel Temperature Coefficient (FTC) of reactivity. A moderator temperature coefficient was assumed in this analysis which corresponds to beginning-of-life core conditions. This MTC has the smallest impact on retarding the rate of change of power, coolant temperature, and DNBR. A fuel temperature coefficient corresponding to beginning-of-life conditions was used in the analysis, since this FTC causes the least amount of negative reactivity change for mitigating the transient increases in core power, heat flux, and the reactor coolant temperatures. The uncertainty on the fuel temperature coefficients used in the analyses is listed in Table 15.4.2-2. The regulating CEA position from which the CEA withdrawal is initiated corresponds to the power dependent insertion limit. This particular insenion was selected based on the calculated CEA worth and associated uncertainties to produce the worst transient. A corresponding maximum differential wonh of 0.008% 4 per inch of rod motion was conservatively assumed in the present analysis. This corresponds, to a maximum reactivity withdrawal rate of 0.4 x IP 4 per second based on the maximum CEA withdrawal speed of 30 inches per minute, including all uncenainties. The steam bypass control system is assumed to be in manual mode because this minimizes DNBR during the transient. e Results l The dynamic behavior of important NSSS parameters following an uncontrolled CEA group withdrawal with a loss of offsite power are presented in Figures 15.4.2-1 through 15.4.2-12. The withdrawal of CEAs causes a positive reactivity change, resulting in an increase in the core power and heat flux. As a consequence, the reactor coolant temperature and pressurizer pressure increase. At 17.70 seconds after initiation of the transient, a reactor trip on CPC VOPT is actuated. At 18.25 seconds the trip breakers are opened. Also at this time, the turbine is assumed to trip resulting in an instantaneous loss of offsite power. Subsequently, the CEAs begin dropping into the core and terminate the transient. The minimum DNBR reached during the transient is well above 1.24 at 19.10 seconds. The maximum planar radial peaking factor occurs in the region of the axial power peak and the peak linear teat generation rate during the transien' remains below 21 KW/ft. Table 15.4.2-1 lists the sequence of events for the limiting DNBR case. 15.4.2.4 Conclusions The uncontrolled CEA withdrawal event with or without a loss of offsite power meets General Design Criteria 25 and 20. These criteria require that the specified acceptable fuel design limits are not exceeded and the protection system action is initiated automatically. The withdrawal of CEAs from full power AMwomf Des @n Mateniel- AccHent Analyses rege 15.4 4
System 80+ Design Canaraf Docennent
'N conditions with or without a loss of offsite power meet the following fuel design limits which serve as l the -ape
- criteria for this eventi the transient terminates with a hot channel mmimum DNBR greater i than or equal to 1.24 and the peak linear heat generation rate during the transient is less than 21 KW/ft.
l 15.4.3 Single Control Eisenant Aa==My Drop . 15.4.3.1 Identincation of Event and Causes i A single CEA drop results from an interruption in the electrical power to the Control Element Drive ; Mechanism (CEDM) holding coil of a single CEA. This interruption can be caused by a holding coil ! failure or loss of power to the holding coil. The limiting case is the CEA drop which does not cause a ; trip to occur but results in an approach to the DNBR criterion of 1.24. l 15.4.3.2 . Sequence of Eva ts and Systeins Operation The transient is initiated by the releamed subsequent drop of a control element assembly. The resultant increase in the hot pin radial peaking factor coupled with a return to 102% of full power (following a >
' tr.uprary power depression) results in a minimum DNBR of 1.31 at approximately 200 seconds.
Table 15.4.31 presents a chronological list of events that occur during the single CEA drop transient, l from initiation to the attainment of steady state conditions. l 15.4.3.3 Analysis of Effects and Consesp=== ; i ( e Mathematical Model , The Nuclear Steam Supply (NSSS) response to the single CEA drop was simulated using the l CESEC-Ill computer program referenced in Section 15.0. The time-dependent thermal margin on DNBR in the reactor core was calculated using the CETOP computer program which uses the , CE-1 critical heat flux correlation referenced in Section 15.0. l e input Parameters and Initial Conditions ; Table 15.4.3-2 lists the assumptions and initial conditions used for this analysis in addition to ! those discussed in Section 15.0. The sets of initial conditions (power, pressure, temperature, coolant flow rate, radial peakmg ! factors, and axial power distribution) were chosen such that a minimum initial thermal margin l was obtained. This initial thermal margin corresponds to a DNBR of 1.62. This information was ! then used with the maximum change in radial peaking factor. ! i The negative reactivity inserted by a dropped CEA causes the power to initially decrease everywhere in the core. The coolant inlet temperature and ;xessure will gradually decrease. i Concurrently, the radial peaking factor will increase to an asymptotic post drop value. The { assumed 0.1 second drop time produces a faster initial transient response than would actuaW be } expected. The DNBR calculation is only sensitive to "where" the CEA is dropped in the core j as opposed to "how fast" the CEA is dropped m the core. Since one of the initial conditions used t to calculate DNBR concerns radial peaking factors, the manmum radial peaking factor is- ! determined by the location of the dropped CEA and this value in turn is used in the DNBR l calculation. The decreasing coolant temperature combined with the negative doppler and j l ' i Aromed DeeQn aaneenInt. AeeMont Amheen neee 15.4-E
)
i
l i System 80+ Design ControlDocument l 1 l moderator temperature coefficients causes a positive reactivity insertion which brings the core back to 102% power at the time of minimum DNBR. To compute the minimum DNBR, the heat flux is based on the 102% power conditions and the asymptotic radial peakmg factor existing at that time. The Reactor Regulating System is assumed to be in the automatic mode. For this analysis, the choice of mode is inconsequential because there would be no regulating bank motion if the system were in manual mode; and in the automatic mode the CEA Withdrawal Prohibit (CWP), actuated on a rod drop deviation, prevents the motion of any regulating bank following the drop of a single CEA which causes the CPC calculated DNBR to approach 1.24.
- Results The dynamic behavior of important NSSS parameters following the drop of a single CEA is presented in Figures 15.4.3-1 through 15.4.3-12. The CEA drop is characterized by a prompt decrease in core average and local power followed by an increasing distortion in radial power distribution. Then the reactivity feedbacks (due to the decreasing core inlet and average temperatures) cause the power (which was initially depressed immediately following the drop) to rise. The higher radial peaking factor, coupled with the core average power returning to its initial value, causes a decrease in DNBR.
The results of parametric analyses of the change in radial peak (distortion) indicate that an increase in the integrated radial peak of 14%, in conjunction with the assumed values of other initial parameters, can be tolerated without a reactor trip. For the case in which a trip does not occur, a minimum DNBR of 1.31 is reached at approximately 200 seconds. The pressure decrease beyond this point is arrested by the return to full power and a new steady state is reached. If the maximum rod radial peaking factor occurs in the region of the axial power peak, the peak linear heat generation rate during the transient remains below 21 KW/ft, thus ensuring no centerline melt. The CPC's are programmed such that a trip will occur for certain drops. However, the DNBR values for these cases are no more limiting than those presented in this section. The earlier CEA Drop Analysis did not consider a loss of offsite power (LOOP). In compliance with GDC-17, i.e., considering the event with and without LOOP, the final CEA drop analysis evaluates a LOOP resulting from a turbine generator trip coincident with a reactor trip and found this scenario to be no more limiting than the case presented in this section. 15.4.3.4 Conclusions The single CEA drop event meets General Design Criteria 25 and 20. These criteria require that the specified acceptable fuel design limits are not exceeded and the protection system action is initiated automatically. The drop of a CEA meets the following fuel design limits which serve as the acceptance criteria for this event: the transient terminates with a hot channel mimmum DNBR greater than or equal to 1.24 and the peak linear heat generation rate during the transient is less than 21 KW/ft. O Aliproud Des &n Meterial AccMent Analyses rege r5.4 6
System 80+ Deslan controlDocanent i 15.4.4 Startup of an Inactive Reactor Coolant Pump 15.4.4.1 Identification of Event and Causes The startup of an inactive reactor coolant pump (SIRCP) is presented here with respect to RCS pressure and fuel performance criteria. The event was evaluated during Modes 3 through 6 since plant operation with fewer than all four reactor coolant pumps is permitted only during those modes. The cases considered were no more than one reactor coolant pump operating or two reactor coolant pumps operating in one loop (the other loop idle) to maximize the pressure increase. 15.4.4.2 Sequence of Events and Systems Operation SIRCP causes a sudden surge of relatively cold or hot water to enter the core which may cause a core power or RCS pressure increase. For Modes 3 and 4 the primary safety valves, main steam safety valves, and the Reactor Protection System are designed to maintain the RCS below 110% of design pressure. During Modes 5 and 6, when the Shutdown Cooling System is aligned, overpressure protection is provided by the shutdown cooling system relief valves. The shutdown cooling system design bases are presented in Section 5.4.7. 15.4.4.3 Analysis of FEects and Consequences With no more than one reactor coolant pump operating or two reactor coolant pumps operating in one loop (the other loop idle), the SIRCP may lead to an increase in RCS pressure. However, as stated in Section 5.2.2 and Appendix 5A, the overpressure protection for steam generators and the reactor coolant system is in accordance with the requirements set forth in ASME Boiler and Pressure Vessel Code, Section III. For Modes 3 and 4 the primary safety valves, main steam safety valves, and Reactor Protection System are designed to maintain the RCS below 110% of design pressure during worst pressure transients. During Modes 5 and 6, when the Shutdown Cooling System is aligned, overpressure protection is provided by the shutdown cooling system relief valves. 15.4.4.4 Conclusions Based on the design of the valves described in Section 15.4.4.3 the maximum pressure within the RCS occurring during a SIRCP will not exceed 110% design value. For Modes 3 and 4, the heat imbalance . due to the SIRCP is less limiting than that caused by the CEA withdrawal event. In Modes 5 and 6, the capacity of the shutdown cooling relief valves prevents the RCS pressure following a SIRCP from exceeding the pressure / temperature limits for these modes. Regarding the approach tc fuel design limits l for the SIRCP, the minimum DNBR in the hot channel will increase as the transient progresses; therefore l no fuel damage is expected. , i 15.4.5 How Controller Malfunction Caus ng an Increase in BWR Core Flow Rate 8 ! This event is categorized as a Boiling Water Reactor event in SRP 15.4.5 and, therefore, will not be ; analyzed. 4 i l l Aapmvent t Denkn neeneriet- Accident Ane4ses Page ts.4-7 i
System 80+ Design ControlDocument i 15.4.6 Inadvertent Deboration 15.4.6.1 Identification of Event and Causes The inadvertent deboration event is presented here with respect to time available for operator corrective action prior to the loss of minimum required shutdown margin. Fuel integrity is not challenged by this event. The inadvertent deboration event may be caused by improper operator action or by a failure in the boric acid makeup flow path which reduces the flow of borated water to the charging pump suction. Either cause can produce a boron concentration of the charging flow which is below the concentration of the reactor coolant. Analysis of the inadvertent deboration event initiated during each of the six operational modes defined in the Technical Specifications was performed. These analyses show that Mode 5 (cold shutdown with the RCS drained down) results in the least time available for detection and ternunation of the event. This is because the lowered RCS volume leads to a smaller dilution time constant and results in the fastest dilution rate and, therefore, yields the shortest time to a complete loss of shutdown margin. Since boron dilution is conducted under strict procedural controls which specify limits on the rate and the magnitude of any required change in boron concentration, the probability of a sustained and erroneous dilution due to operator error is very low. The indications and/or alanns available to alert the operators that a boron dilution event is occurring in each of the operational modes are outlined below.
- The following control room indications and corresponding pre-trip alarms are available for Modes 1 and 2: a high power or, for some set of conditions a high pressurizer pressure trip in Mode 1 or a high logaritlunic power level trip in Mode 2. Funhermore, a high Tryoalarm may also occur prior to trip.
- In Modes 3, 4 and 5 with RCS full and at least one of the Reactor Coolant Pumps (RCPs) operating, a neutron flux alarm on the startup flux channel will provide indication of any boron dilution event.
- In Modes 4 and 5 with the RCS full and all RCPs idle, the primary coolant volume available for mixing consists of only the volume of the reactor vessel up to the top of the hot legs, the volume of the shutdown cooling system, the volume of one hot leg, and the volume of two discharge legs. The rest of the RCS volume is not included because of the possibility of stagnation. In this condition, deboration is prohibited. The neutron flux alarm on the startup flux channel will provide indication of any boron dilution event.
- In Mode 5 with the RCS partially drained for system maintenance, the volume available for mixing consists of only the volume of the reactor vessel up to the mid-plane of the hot legs, the volume of the shutdown cooling system, half the volume of one hot leg, and half the volume of two discharge legs. In this condition, deboration is prohibited. The neutron flux alarm on the startup flux channel will provide indication of any boron dilution event.
O Approwd Design aesterial- Accident Analyses Pope 15A-8
- System 80+ Desipt ComrolDocument e In Mode 6, with the reactor upper head removed and the CEAs fully withdrawn, the coolant is i maintained at a boron concentration of at least 4000 ppm before entering this mode. In this }
condition, deboration is prohibited. The neutron flux alarm on the startup flux channel or the reactor makeup water flow alarm (backup only) will provide indication of any boron dilution , event. ! The neutron flux alarm is activated when the SRM (Source Range Monitoring) ratio exceeds its setpoint. The SRM ratio is defined as follows: Source Range Signal (t)- SRM ratio - Source range signal at start of dilution i For Mode 3,4, 5 and 6 operation, time is calculated from event initiation to loss of shutdown margin. j Thirty minutes is subtracted from this time to determine the latest allowable time for alarm actuation. ! In these modes, it was calculated that at 30 minutes prior to loss of shutdown the SRM ratio will have ; exceeded its setpoint. Therefore, an operator response time of at least 30 minutes is demonstrated. , i The operational procedure guidelines, in addition to these indications and/or alarms, will assure detection i and termination of the boron dilution event before the shutdown margin is lost. , i 15.4.6.2 Sequence of Events and Systems Operation , For Modes 1 and 2, the deboration will cause a high pressurizer pressure trip, a high power trip or a high logarithmic power trip and the subsequent reactor scram will bring the core to suberitical conditions with shutdown margins much higher than the Technical Specification requirements. For the remaining modes, I
- the core is initially subcritical with the shutdown margin at the minimum value consistent with the Technical Specification limits for shutdown. An inadvertent deboratign occurs which causes unborated water to be pumped into the RCS. The resulting decrease in RCS boron concentration adds positive reactivity to the core. Assuming dilution continues at the maximum possible rate, 67 minutes would elapse before the core becomes critical.
- The operator is alerted to a decrease in the reactor coolant system (RCS) boron concentration either 4
through a high neutron flux alarm on the startup flux channel, the reactor makeup water flow alarm (Mode 6 only), sampling, boronometer indications, or boric acid flow rate. The operator turns off the
- charging pump and closes the letdown control valves in order to halt further dilution. Next, the operator ,
increases the RCS boron concentration by implementing the emergency boration procedure for achieving j cold shutdown boron concentration.
~
15.4.6.3 Analysis'of Effects and Consequences e - Mathematical Model , Assuming complete mixing of boron in the RCS, the rate of change of boron concentration during dilution is described by the following equation. , l . I dC 4 M --WC (1) x { - dt i i W W M
- AW W P900 r$A9
I 4 System 80+ Design ControlDocument l where: M = RCS mass C = time dependent RCS boron concentration W = Charging mass flow rate of unborated water dC/dt is maximized by maximizing W and minimizing M. Assuming: W = Constant, equal to the maximum possible value, and choosing: M = Constant, equal to the minimum value occurring during the boron dilution incident, the solution of Equation (1) can be written C - C oe -* (2) where: r = M/W = Boron dilution time constant Co
= Initial boron concentration The time T required to dilute to critically is given by T =
rIn (Co/C en ) (3) where: C ,a = Critical boron concentration
- Input Parameters and Initial Conditions it is assumed that the inadvertent deboration proceeds at the maximum possible rate. For this to occur, the charging pump must be on, the reactor makeup water tank must be aligned with the charging pump suction, a reactor makeup water pump must be on, letdown flow must be diverted from the volume control tank, and a failure in the boric acid makeup water flow path (e.g., flow control valve, CH-210Y failing in the closed position) must terminate borated water flow to the charging pump suction.
O Anwoved Desigrt Metwiel AccMerrt Anetyses Page 15.4-10
J System 80+ Denian conear coeumont l l Analysis of inadvertent deboration events initiated during operational modes 2 through 6 (defined i
. in the technical specifications) were performed. For Mode 1 operation, the reactivity addition ,
} due to a boron dilution event is less limiting than the CEA withdrawal events. These analyses ,
- show that Mode 5 (cold shutdown) in the drained down configuration results in the shortest - ;
available time for detection and termination of the event. Therefore, the initial conditions and l 2 analysis parameters are chosen for the cold shutdown operational mode to mimmim the interval l from initiation of dilution to the time at which criticality is reached. This results in the least amount of time between detection and criticality.
! i 4
The following are the analysis assumptions for Mode 5: 3
- 1. The Technical Specification lower limit on shutdown margin for cold shutdown is assumed,5.75% 4 ,
i 2.~ The most adverse initial core condition would be for an initial K,,r coireponding to ) 5.75% 4 subcritical and assuming subcriticality is maintamed by boron concentration j only. ] l
- 3. The cold reactor coolant volume, including only the volumes for Mo% 5 drained, is 3,%1 ft S. A conservatively low reactor coolant mass was assumed by using the cold RCS internal volume. Assuming the coolant temperature of 210*F, the Technical Specification upper limit for cold shutdown, the resulting mass is 237,185 lbm.
- 4. The analysis used a maximum charging flowrate to the RCS of 160 gpm which l c ,
corresponds to 22.26 lbm/sec.
- 5. The critical boron concentration with all rods in except the largest worth rod stuck out and the inverse boron worth are 814 ppm and 66 ppm /%4, respectively, including uncertainties. The initial boron concentration for the cold shutdown mode is found by adding the product of the inverse boron worth and the minimum shutdown margin (i.e.
5.75 percent) to the critical boron concentration. The resulting minimum initial boron 2 concentration in Mode 5 is 1193 ppm. Thus, the change of boron concentration from 5.75% 4 subcritical to critical is 379 ppm. The parameters discussed above are summarized in Tabic 15.4.6-1. e Results r l Using the above conservative parameters in Equation (3), the nummum possible time interval to ! dilute from 5.75% 4 suberitical to criticality is 67 minutes. Utilizing only the redundant, ) qualified neutron flux alarm, this time period will assure detection of a boron dilution event at ! least 30 minutes prior to criticality. Boron dilution will then be terminated before loss of shutdown margin by the operator actions discussed in Section 15.4.6.2. 15.4.6.4 Conclusions . The inadvertent deboration event will result in acceptable consequences. Sufficient time is available for the operator to detect and to ternunate an inadvertent deboration event if it occurs. Fuel integrity is not
' challenged during this event.
I houewed Doeten naenen1er AeeMont Anaheen grrine) . pape :s.t.r r I
1 I System 80+ Design controlDocument 15.4.7 Inadvertent Loading of a Fuel e se-:Lly mio the Improper Position 15.4.7.1 Identification of Events and Causes i i The Inadvertent Loading of a Fuel Assembly into the Improper Position event is initiated by interchanging two fuel assemblies. The likelihood of an error in core loading is considered to be extremely remote because of the strict procedural control used during core loadmg. 1 l 15.4.7.2 Sequence of Events and Systems Operation j The fuel enriclunent within a fuel assembly is identified by a coded serial number marked on the expased surface of the top end plate of the fuel assembly. This serial number is used as a means of positive identification for each assembly in the plant. A tag board is provided in the main control room showing a schematic representation of the reactor core and spent fuel storage area. During the period of core loading, the location of each CEA, fuel assembly, and source will be shown on this tag board by a tag carrying its identification number. The tag board in the main control room will be constantly updated by a designated member of the reactor operations staff whenever a fuel assembly is being moved. This person will be in constant communication with each area where this is occurring. Alr.o, a licensed operator will be present in the area where fuel assemblies are being handled to ensure that the assemblies are moved to the correct ' i locations. Fuel assemblies will not be moved unless these lines of communication are available. In addition to these precautions, periodic independent inventories of components in the reactor core, spent fuel, and new fuel storage areas will be made to ensure that the tag board is correct. Also, at the completion of core loading, the exposed surfaces of the top end plates are inspected to verify that all assemblies are correctly located. These precautions are included in the core loading procedures which are to be reviewed by appropriate plant personnel. If, in spite of the extreme precautions described above, a fuel misloading does occur the consequences depend on the types and locations of the fuel assemblies that have been interchanged. The mistoading of a fuel assembly may affect the core power distribution only slightly, for example, if assemblies of ! similar enrichments and reactivities are misloaded. Alternatively, if assemblies having very different I enrichments or reactivities are misloaded, the core power distribution may be affected enough so that core performance would be degraded. l In the unlikely event that two assemblies of different enrichments would be interchanged. some mistoadings would be detected using ex-core startup detectors and the reactivity computer during the low power physics testing. In these tests a symmetry check is performed in which the reactivity worths of , symmetrically located CEAs are compared against one another. The interchange of two or more fuel ! assemblies with greatly different infinite multiplication factors destroys the octant symmetry of the core flux distribution and would thus produce significant variations in the worths of symmetrically located CEAs. This asymmetry would be corroborated by symmetry checks performed for other symmetric rod l groups, thereby confirming and possibly even locating a fuel assembly mistoad. In addition, many mistoadings could be detected by either the ex-core detectors directly or the in-core
- detector channels which are analyzed at power levels greater than 20 percent during the power ascension test at beginning of cycle (BOC) and periodically throughout the cycle.
l ; Thus, most of the fuel assembly misloadings that can be postulated are easily detectable both during the rod symmetry checks and during power range operation. However, there is a small number of G l Atlpronef Desty Meterial- AccMent Anetyses Page 15.4-12 l
- .i 1
I .. S v 5 = S f? + Declan contrat Doewnent I ( misiondings which are i=*ehle during the rod symmetry testing or even early in the cycle with in-core instrumentation during power range operation. Of this small class, the worst case is the interchange of a shimmed assembly with an unshunmed assembly at the center of the core. This case, although not hahle at BOC, would cause local power peaking as the shims burn out. l l Furthermore, even though these misloads may not be detected during startup at BOC, it is very probable that the anomaly would be detected early in the cycle before the maximum F,y value is attained. This 4 is because this type of interchange (i.e. shimmed with un=hima=d) tends to produce an increasingly distoned power distribution which would alert the reactor engineer to the possibility of a fuel mistoading. t Chapter 16, Technical Specifications, requires that the planar radial peaking factor (F"',y) be measured l l at least once per 31 Effective Full Power Days and that the measured planar radial peaking factor (P",y) shall be less than or equal to the planar radial peaking factor (Fe,y) used in the COLSS and in the CPC. Therefore, even if the increase in radial peak is not large enough to alert the reactor engineer to the possibility of a misloading,' the measured radial peak would be used in the COLSS and the CPC. This . would reduce the operating band to compensate for the reduction in the thermal margin caused by these midloads.- 15.4.7.3 Analysis of Effects and Consequences Following the completion of the core fuel management design, a study will be performed to assure that the maximum F,y increase during any 31 EFPD period over the F,y value used in COLSS would be less than 10% including consideration of increased measurement uncertainties due to the misloading. An increase of 14% in integrated radial peak is considered in the CEA Drop analysis and shown to result in O- a DNBR greater than 1.24 (see Section 15.4.3.3). Therefore, the consequences of this event will be less severe than those of the CEA drop event and the resultant DNBR for this event will be greater than the l I 1.24 DNBR SAFDL. 15.4.7.4 Conclusions Those inadvertent Loading of a Fuel Assembly into the Improper Position Events which are not detected during startup at BOCl do not result in fuel cladding consequence,s and are within 10 CFR 100 guidelines. 15.4.8 Control Element Ammanhly (CEA) EFdaa l l The CEA Ejection results presented represent the CEA ejection event calculation for System 80+ l configured to produce 3800 MWt at 100% power. The calculations were repeated .for System 80+
. configured to produce 3914 MWt, and due to design and related parameter changes used to obtain the increased power, the results are hm=4d by the results reported here. Therefore, it is conservative to use these results for System 80+ configured to produce 3914 MWt.
For both the earlier and the final analysis, peak RCS and Steam Generator pressure cases assumed a zero time delay between turbine trip and a loss of offsite power (LOOP). This is also the case for the analysis which calculates doses from the secondary releases. For the analysis which calculates doses based on containment releases, both amendments assumed.a LOOP _ at time zero. For the fuel performance
. analysis, a LOOP was not considered, as this was not required per NUREG-0800. Based on these assumptions utilized for the CEA Ejection analysis, both the earlier and the final analysis are in O compliance with GDC-17, eyeweemseep asseerW. AseMast Anchow Aspe rf.4 r3 w _. _ . . . _ . ~ _ _ _
System 80+ Design ControlDocument Radiological dose calculations for this event have been updated according to the current methodology outlined in Appendix 15A. These calculations use the increased steam release and core isotopic inventory values which result from the 3914 MWt core power level. 15.4.8.1 Identification of Event and Causes A CEA Ejection results from a circumferential rupture of the control element drive mechanism (CEDM) housing of the CEDM nozzle. 15.4.8.2 Sequence of Events and Systems Operation Table 15.4.8-1 presents a chronological sequence of events which occurs during a CEA ejection transient ; from the time the CEA and drive shaft are ejected until operator action is initiated. The sequence of events and systems operations represents the way in which the plant was assumed to l respond to the event initiator. Many plant responses are possible. However, certain responses are ' limiting with respect to the acceptance guidelines for this section. Of the limiting responses, the most likely one to be followed was selected. 15.4.8.3 Analysis of Effects and Consequences
- Mathematical Model The NSSS response to a CEA Ejection was simulated using the method of analysis referenced in Section 15.0.3. The procedure outlined there was used to determine the energy deposition in the fuel rod. The number of fuel pins predicted to experience departure from nucleate boiling (DNB) was calculated using the STRIKIN-II computer program referenced in Section 15.0 with the CE-1 correlation. A matrix relating the initial and ejected CEA radial peaking factors to a pin census edit is obtained from Step 6 of the C-E Synthesis method and used to calculate the number of fuel pins experiencing DNB. Further conservatism is introduced by assuming that clad failure occurs when fuel rods experience DNB.
Except for the calculation of doses from containment and recirculation leakage, the analysis of the NSSS response to a CEA ejection did not consider the leakage and the RCS depressurization which would be caused by the rupture of the primary pressure boundary. Tids approach does not affect the fuel failure calculation, but it does increase the calculated secondary steam release. Therefore, not considering the leakage and the RCS depressurization tends to maximize the resultant doses from secondary steam release. This approach is also more conservative with respect to the RCS pressure criterion since it maximizes the RCS pressure. e input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a CEA Ejection are discussed in Section 15.0. A spectrum of initial reactor states (including conditions characteristic of the beginning and end of the fuel cycle) was considered. The initial conditions for the principal process variables were varied within the reactor operating space given in Table 15.0-3 to determine the set of conditions which produce the most adverse consequences following a CEA Ejection. Various combinations of initial core inlet temperature, core inlet flow rate, pressurizer pressere and axial power distribution were
~
Approwd Design Matenfal AccHent Analyses Pope 15.4-14
i System 80+ ossion contrat oocament j 1 considered. The initial pressurizer and steam generator water level, as controlled within the l operating space, have an insignificant effect on the con ==- of the CEA ejection analysis. An axial power distribution was chosen to maximize the energy content in the hottest fuel pellet. . De remaining parrmeters were chosen based on the results shown in Chapter 4 of Reference 16 l of Section 15.0. These parameters were varied in the most adverse direction until a COLSS power operating limit was achieved.
*- Results .
A spectrum of initial states were considered. The case initiated from hot full power (HFP) initial conditions is expected to result in the greatest potential for offsite dose co=== aces (i.e., the case resulting in the largest number of postulated fuel failures). The results show that the radial , averaged fuel enthalpy is less than 280 cal /g at the hottest axial location of the hot fuel pin. ' The l' following paragraphs describe this event in detail. Refer to Table 15.4.8-2 for the initial conditions and assumptions used for this analysis. Table 15.4.8-1 contains the sequence of events that occur during a CEA Ejection initiated from i hot full power initial conditions. . Figures 15.4.8-1 through 15.4.8-5 show the reactor power, heat flux, and clad and fuel temperatures during the significant portion of transient. 4 k Ejection of a CEA causes the core power to increase rapidly due to the almost instantaneous ' addition of positive reactivity. However, the rapid increase in core power is terminated by a combination of Doppler feedback and delayed neutron effects. This increase in power results in a high power trip and the reactor power begins to decrease as the CEAs enter the core. Reactivity ~ effects are shown in Figure 15.4.8-6. In the hot channel, the increase in heat flux is such that DNB is calculated to occur, resulting in:
- 1. A rapid decrease in the surface heat transfer coefficient. ;
- 2. A rapid decrease in heat flux. l l
- 3. A rapid increase in clad temperature.
J ^ De rapid increase in clad temperature is sufficient to override the decreased surface heat transfer l coefficient, resulting in a second peak in the hot channel heat flux. At this time the CEAs are j nearly fully inserted, resulting in a rapid reduction in the core power level. The heat flux ]
- continues to decrease for the remainder of the transient.
Initial pressurizer pressure is 1900 psia. The RCS and steam generator pressure for this case is shown in Figures 15.4.8-7 through 15.4.8-12. Steam generator safety valve flow rate following a HFP CEA ejection with a postulated loss of offsite power following turbine trip is shown in Figures 15.4.8-13 and 15.4.8-14. Anproved Doetpn nenewint. AeeMont Ane&een rope 15.4 15
System 80+ Design ControlDocument The transient behavior of the NSSS following a postulated QA Ejec: ion is as follows. The steam generator pressure increases rapidly due to the closure of the turbine control valve following reactor and turbine trip. The steam bypass control system is inoperable on loss of offsite power and therefore is unavailable. The steam generator pressure reaches a maximum of 1279 psia at 8.05 seconds. The pressurizer pressure increases to a maximum of 2399 psia at 5.4 seconds due to the decreased heat removal of the steam generators. Subsequently, the reduced reactor power following the reactor trip causes the RCS pressure and temperature to decrease. The steam generator pressure fluctuates as the MSSVs open and close throughout the event. The satal steam release through the safety valves is approximately 317,100 lbm up to 1800 seconds. lollowing a postulated CEA ejection event,6.8% of the fuel is calculated to experience DNB.
,@ Regulatory Guide 1.77 recommends that the onset of DNB be used as the basis for predicting clad ye failure. It is conservatively assumed that all fuel rods experiencing DNB suffer clad failure. ./
A separate analysis was performed to maximize the RCS pressure. The initial pressurizer pressure for this case was 2400 psia. The peak RCS pressure reaches 2742 psia (including the pressure difference between cold leg at the RCP discharge and the surge line). This value is less than 120% of design pressure. Figure 15.4.8-15 shows the peak pressure transient. Radiological consequences for this event are calculated for two cases: release through containment and release through primary-to-secondary leakage. The assumptions, parameters and calculational methods used to evaluate the radiological consequences of Chapter 15 events are discussed in Appendix 15A. Assumptions and parameters that were unique to the evaluation of a CEA Ejection Event are itemized in Table 15.4.8-3. The following paragraphs provide additional clarification to some of the items contained in the table.
- 1. Activity available for release from containment at time zero The activity available for leakage from containment is based on the following Regulatory Guide 1.77, Appendix B assumption as modified by Draft NUREG-1465 for the gap activity:
The activity in the fuel clad gap is assumed to be 5% of the iodines,5% of the noble gases and 5% of the cesium and rubidium accumulated in the fuel at the end of core life, assuming coatinuous maximum full power operation. All of the activity in the fuel gap for fuel rods that are calculated to experience DNB is assumed to be instantaneously mixed throughout containment and available for leakage to the atmosphere.
- 2. Activity Release from the Secondary System Activity released from the secondary system is based upon the secondary activity initially in the steam generators plus primary activity and failed fuel gap activity resulting from technical specification steam generator tube leakage. Table 15.4.8-4 contains the tots]
mass releases from the main steam safety valves and the total primary to secondary . leakage. The mass of steam released through the ADVs is given in Table 15.4.8-3. AppwndDesrgn Atatodel Acektwt Analyses Page 15.4-16 !
System 80+ Deslan controlDocument 15.4.8.4 Conclusions The ejection of a CEA will not result in a radial average fuel enthalpy greater than 280 cal / gram at any
- axial location in any fuel rod. The radiological consequences associated with containment releases and ucondary system steam releases have been conservatively analyzed using assumptions and riodels described in the preceding sections. The whole-body dose due to immersion and the thyroid dose due to inhalation have been analyzed for the two-hour dose at the exclusion area boundary and are presented '
in Table 15.4.8-5. The 30-day doses at the low population zone have been found to be less limiting then the EAB doses. The resultant doses are less than the allowable site boundary dose set forth in 10 CFR 100. Control room doses are provided in Section 6.4.3. The peak RCS pressure for the CEA Ejection event is 2742 psia. This is less than Service Limit C value as defined in the ASME Code. i s W Deoden aneennle! AceMont Anahm rene r5.4.r7
System 80+ Design controlDocument Table 15.4.1-1 Sequence of Events for the Low Power Sequential CEA Withdrawal Event with a Loss of Offsite Power h Time (sec) Event Setpoint or Value 0.00 Withdrawal of CEAs - Initiating Event - 28.90 Core Power Reaches Variable Overpower Reactor Trip 30 Analysis Serpoint, % of Design Power 29.30 Variable Overpower Trip, Signal Generated - 29.45 Trip Breakers Open and the Turbine is Tripped / loss - of Offsite Power Occurs 30.00 Maximum Core Power, % of Design Power 51 30.25 Maximum Core Average Heat Flux, % of Full Power 26.0 Heat Flux 30.30 Minimum DNBR >1.24 34.10 Maximum Pressurizer Pressure, psia 2272 Table 15.4.1-2 Assumptions and Initial Conditions for the Low Power CEA Withdrawal Analysis with a Loss of Offsite Power Parameter Value Core Average Power Level, MWt 0.039 Core inlet Coolant Temperature, 'F 561 Core Mass Flowrate,106 lbm/hr 151.8 Pressurizer Pressure, psia 2175 Integrated Radial Peaking Factor 2.94 Steam Generator Pressure, psia 1143 Moderator Temperature Coefficient,10 4 Ap/'F 0.0 Doppler Coefficient Multiplier 0.85 Doppler Reactivity Function Table 15.0-5 CEA Reactivity Addition Rate,104 Ap/sec 1.5 CEA Worth on Trip,10-2 Ap -6.5 Steam Bypass Control System Manual CEA Withdrawal Speed, inches / min 30 0 Approved Design Material AccMent Analyses Page 15.418
System 80+ Design ControlDocument l . Table 15.4.2-1 Sequence of Events for the Sequential CEA Withdrawal Event at Power with a loss of Offsite Power Time (sec) Event Setpoint or Value 0.00 Withdrawal of CEAs - Initiating Event - 17.70 Core Power Reaches CPC VOPT Trip Analysis Serpoint, % 115 of Design Power 18.10 CPC VOPT Trip Signal Generated - 18.25 Trip Breakers Open and the Turbine is Tripped / loss of Offsite Power Occurs . t 18.40 Maximum Core Power, % of Design Power 115.6 18.40 Maximum Core Average Heat Flux, % of Full Power Heat 113.6 Flux 19.10 Minimum DNBR >1.24 22 Maximum Pressurizer Pressure, psia 2337 Table 15,4.2-2 Assurnptions and Initial Conditions for the Sequential CEA Withdrawal Analysis at Power with a Loss of Offsite Power Parameter Value Core Power I.evel, MWt 3992 Core inlet Temperature, 'F 561 Core Mass Flow Rate,106 lbm/hr 151.8 Pressurizer Pressure, psia 2175 Integrated Radial Peaking Factor 1.43 Core Minimum DNBR 1.33 Steam Generator Pressure, psia 1057 Moderator Temperature Coefficient,10 4 Ap/'F 0.0 Doppler Coefficient Multiplier 0.85 Doppler Reactivity Function Table 15.0-5 CEA Wonh at Trip,10-2 Ap -8.010 Reactivity insertion Rate,104 Apisec 0.4 Steam Bypass Control System Manual CEA Withdrawal Speed, inches / min 30 O)
'u 181 Value is conservatively less negative than the available design value of -8.86 used in other Chapter 15 analyses.
?;:.::Dee> asenerial Accident A@es Pope 15.419
System 80+ Design ControlDocument Table 15.4.3-1 Sequence of Events for the Single Full Length CEA Drop h Time (see) Event Setpoint or Value 0.0 A Single CEA Begins to Drop - 0.0 Maximum Pressurizer Pressure, psia 2175 200 Minimum DNBR 1.31 400 Minimum Pressurizer Pressure, psia 2157 Table 15.4.3-2 Assumptions and Initial Conditions for the Single Full Length CEA Drop Parameter Value Core Power Level, MWt 3992 Core inlet Coolant Temperature, 'F 561 Core Mass Flowrate,106 lbm/hr 151.8 Pressurizer Pressure, psia 2175 Steam Generator Pressure, psia 1057 Axial Shape Index -0.3 Core Minimum DNBR 1.62 Integrated Radial Peaking Factor 1.43 Dropped CEA Reactivity Worth,10-2 Ap -0.06 Time for Dropped CEA to be Fully laserted, sec 0.1 Doppler Coefficient Multiplier 1.38 Moderator Temperature Coefficient, Ap/'F -3.5x10d Doppler Reactivity Function Table 15.0-6 O Approvet Destro Meterial AccMent Analyses Page 15.4-20
l System 80+ Design ControlDocument
/~T C Table 15.4.6-1 Assumptions for the Inadvertent Deboration Analysis Parameter Assumptions Cold RCS Volume!33 (mid-loop operation), ft 3 3,%1 RCS Mass (mid-loop operation), Ibm 237,185 Volumetric Charging Rate, gpm 160 Mass Charging Rate, Ibm /sec 22.3 Dilution Time Constant, r, sec'l 10650 Initial Boron Concentration - Co, ppm 1193 Critical Boron Concentration - C,,a, ppm 814 O
O i Ov II Includes the reactor vessel up to the mid-plane of the hot legs, half of a single hot leg, half of two cold discharge legs and a shutdown cooling system.
?, .J Design neeswW. AccMurt AMysee rege 15.4 21
t System 80+ Design ControlDocument Table 15.4,8-1 Sequence of Events for the CEA Ejection Event Time Setpoint (sec) Event or Value 0.0 Mechanical Failure of CEDM Causes CEA to Eject - 0.034 Core Power Reaches Variable Overpower Reactor 130 Trip Analysis Setpoint, percent of design power 0.05 CEA Fully Ejected 0.086 Maimum Core power, % of design power 162.7 0.434 Reactor Trip Signal 0.584 Reactor Trip Breakers Open 0.584 Turbine / Generator Trip 1.384 CEAs begin to drop into core - 2.71 Main Steam Safety Valves Open, psia 1212 2.73 Maximum Clad Surface Temperature in the 1101 1086 Node,*F 3.5 Maximum Fuel Centerline Temperature in the Hot 4800 Node, 'F 3.584 Loss of offsite power occurs - 3.995 Maximum RCS pressure, psia 2380 5.4 Maximum Pressurizer Pressure, psia 2399 5.824 CEAs fully inserted; core power reduced below 15% - of design power 8.05 Maximum Steam Generator Pressure, psia 1279 565.8 Steam generator water level reaches Emergency 18.76 Feedwater actuation signal analysis setpoint in the RilSG, ft 609.7 Steam generator water level reaches Emergency 18.76 Feedwater Actuation signal analysis setpoint in the LilSG, ft ; i 625.8 Emergency feedwater begins entering RilSG, 68.7 l Ibm /sec
)
l l l l I Approved Design Material AccMent Ane&ses Page 15.4 22
System 80+ Design controlDocument ( , V} Table 15.4.8-1 Sequence of Events for the CEA Ejection Event (Cont'd.) Time Setpoint (see) Event or Value 669.7 Emergency Feedwater begins entering LHSG, 68.7 lbm/sec 1757.1 Main Steam Safety Valves Closed, psia 1151 1800 Operator begins plant cooldown, 'F/hr -100 10332 Shutdown cooling initiated, RCS 330/350 pressure / temperature, psia /*F Table 15.4.8-2 Assumptions and Initial Conditions for the Analysis of a CEA Ejection Event Par 3 meters Assumptions Core Power Level, MWt 3876 Delayed Neutron Fraction, S 0.005096 Moderator Temperature Coefficient, Ap/'F 0.0 Ejected CEA Worth,10 Ap 0.15 Doppler Coefficient Multiplier 0.85 Total CEA Worth Available for Insertion on Reactor Trip,102 3, .g,o j (Most reactive CEA stuck out and a CEA ejected) Postulated CEA Ejection Time, sec 0.05 Core Inlet Coolant Temperature. 'F 570 I Core Mass Flow Rate,106 lbm/hr 149.0 Reactor Coolant System Pressure, psia 1911 Pressurizer Pressure, psia 1900 l i O V l Page 15.4-23 AnwevedDeckn nieseniel AccMent Ane&ses l
)
i l System 80+ Design ControlDocument j i Table 15.4.8-3 Parameters Used in Evaluating the Radiological Consequences of a CEA Ejection Event l l Parameter Value A. Data and Assumptions Used to Evaluate the Event's Radioactive Source Term
- 1. General
- a. Core Power level, MW 3992
- b. Burnup, MWD /MT 28,000
- c. Percent of Fuel Calculated to Experience DNB, % 6.8
- d. Percent of Fuel Calculated to Experience Incipient 0.0 Centerline Melt, %
- e. Reactor Coolant Activity Before Event Tech Spec 3.4.15 l
Appendix 15A j f. Secondary System Activity Before Event Tech Spec 3.7.6 Appendix 15A
- g. Primary System Liquid Inventory, Ibm 605,000
- h. Steam Generator Inventory
- Liquid, Ibm per steam generator 117,000
- Steam, Ibm per steam generator 23,700
- 1. Average peaking factor 1.3 B. Data and Assumptions Used to Estimate Activity Released
- 1. Contamment leakage
- a. Containment Volume, ft' 3.34 E06 l b. Containment leak Rate, vol. %/ day Table 154.3-2
- c. Percent of Core Fission Products Assumed Released to Sectior,15.4.8.3 l
Containment
- d. Natural Deposition in Containment Yes A = 0.15 hr' for particulate A = 2.89 hri for elemental iodine
- c. Credit for Radioactive Decay lloid up in Contamment Yes
- In Transit to Dose Point No AMweved Design Meterief Acchkwet Anotynes (2/95) Pege 15.4-24 l
l 1
System 80+ Deska ComrolDocumart i A U Table 15.4.8-3 Parameters Used in Evcluating the Radiological Consequences of a CEA Ejection Event (Cont'd.) Parameter Value
- 2. Activity Release from the Secondary System
- a. Primary-to-Secondary Leak Rate, gpm 1.0(total)
- b. Total Mass Release Through the Main Steam Safety 317,100 Valves, Ibm
- c. Tctal Mass Release Through the ADVs from 30 773,300 minutes to 120 minutes, Ibm
- d. Total Mass Release Rate through the ADVs from 120 153,300 minutes to Shutdown Cooling Startup (480 minutes),
Ibm /hr
- c. Percent of Core Fission Products Assumed Released Section 15.4.8.3 l to Reactor Coolant
- f. lodine Carryover Fraction in the Steam Generators Appendix 15A
- g. Credit for Radioactive Decay in Transit to Dose Point No
- h. less of Offsite Power Yes C. Atmospheric Dispersion Factors (from Table 2.3-1)
- 1. At EAB,0-2 br, sec/m' 1.0x10-8
- 2. At LPZ,0-8 hr, sec/m' 1.35x10' d
8-24 hr 1.0x10 1-4 days 5.4x10-8 4 30 days 2.2x10-8 D. Engineered Safety Features
- 1. Contamment Spray Credit None
- 2. Annulus Building Ventilation After 30 minutes ,
- 3. Contamment Power Purge isolation
- a. Isolation Time 40 seconds
- b. Flowrate Prior to Isolation 1250 cfm E. Dose Data fs 1. Method of Dose Calculation Appendix 15A
( )
- 2. Dose Conversion Assumptions Appendix 15A Anuwedcentp,atenrW AccMorrt Ane&en (2/95) Page 15.4-25
System 80+ Deskn ControlDocument Table 15.4.8-4 Secondary System Mass Release to the Atmosphere for CEA Ejection Event Total Main Total Primary Time Steam Safety To Secocdary (Sec) Valve flow Obm) Leakage (Gallons) 0.0 0.0 0.0 5.0 2,691 0.083 50.0 76,523 0.833 100.0 97,138 1.667 200.0 122,532 3.333 300.0 141,756 5.000 400.0 159,523 6.667 500.0 174,807 8.333 600.0 192,470 10.000 700.0 207.288 11.667 800.0 214,630 13.333 900.0 229.250 15.000 1000.0 236,530 16.667 1100.0 243,870 18.333 1200.0 258,550 20.000 1300.0 265.900 21.667 1400.0 280,450 23.333 1500.0 287,790 25.000 1600.0 295.140 26.666 1700.0 309,760 28.333 1757.101 317,097 29.285 1800.0121 317,097 , 30.000 l l l
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System 80+ Design ControlDocument 1 A Table 15.4.8-5 Radiological Consequences of a Postulated CEA Ejection Event , Thyroid Dose Whole-Body Dose ; Release Pathway (rem) (rem) . Exclusion Area Boundary 2-hour consequences Via Containment 69.8 0.7 Via Wary 17 0.6 lew Population Zone 304y consequences Via Containment 14.5 0.2 Via Secondary 11.3 0.2 i sg l l l l T Anwonef Deefpn niesud Acht Ane&en Pege15.427
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System 80+ Deslan Convo! Document ; 15.5 Increase in RCS Inventory . ! 15.5.1 Inadvertent Operation of the ECCS i 15.5.1.1 Identification of Event and Causes The inadvertent operation of the emergency core cooling system, which is identified 'as the Safety 1 Injection System (SIS) for the System 80+ Standard Design, is assumed to actuate the four Safety Injection (SI) pumps and open the corresponding discharge valves. This operation occurs as a result of , a spurious signal to the system or an operator error. 4 15.5.1.2 Sequence of Events and Systems Operation Inadvertent operation of the SIS is only of consequence when it occurs below the SI pump shutoff head pressure. Above that pressure there will be no injection of fluid into the system. Below the SI pump shutoff head pressure when the shutdown cooling system is isolated the SI flow will increase RCS inventory and pressure until the pressure reaches the pump shutoff head pressure. During shutdown ! cooling system operation the increase in RCS inventory and pressure wili be mitigated by the shutdown cooling system relief valves, j 15.5.1.3 - Analysis of Effects and Consequences ; Plant operation above the SI pump shutoff head pressure will not be impacted by the inadvertent operation i- of the SIS. Below the SI pump shutoff head pressure when the shutdown cooling system is isolated, there
- 5. will be an RCS inventory and pressure increase. This increase will be terminated when the pressure rises above the shutoff head pressure. Due to the pressure increase caused by this transient at low RCS temperatures, there is an approach to the brittle fracture limits of the RCS. Examination of Figures 5.3-5a and 5.3-5b, RCS Temperature-Pressure Limitations, shows that the brittle fracture limits will not be violated for this transient. Should the SIS inadvertently actuate during shutdown cooling operation, the shutdown cooling relief valves will mitigate the pressure transient so that the limits in Figures 5.3-5a and 5.3-5b are not exceeded.
15.5.1.4 Conclusions The peak pressurizer pressure reached during the inadvertent operation of the SIS is well within 110% of design pressure. Additionally, the pressure-temperature limits for brittle fracture of the RCS are not 3 violated by this transient. The fuel integrity is not challenged by this event. ) 15.5.2 CVCS Malfunction-Pressuriser level Control System Malfunction with Loss of Offsite Power i 15.5.2.1- Identification of Event and Causes All events and events plus single failures which cause an increase in RCS inventory were examined with respect to the Reactor Coolant System (RCS) pressure and fuel eladding performance. The earlier Pressurizer' Level Control System (PLCS) Malfunction Analysis considered a loss of offsite power (LOOP) which was delayed three seconds following a turbine trip. The final limiting case assumes that the LOOP occurs simultaneously with the turbine generator trip. l Annrowent Dee@n anenenlof AceMont Amhees Page 15.51 l I
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System 80+ Design ControlDocument When in the automatic mode, the PLCS responds to changes in pressurizer level by changing charging and letdown flows to maintain the program level. Normally, one charging pump is tunning. The charging pump control system is designed with a lockout feature that prevents both charging pumps from operating at the same time. If the pressurizer level controller fails low or the level setpoint fails high, a low level signal can be transmitted to the controller. In response, the controller will operate the charging pump at the maximum flow rate and close the letdown control valve to its minimum opening resulting in the maximum rate of mass addition to the RCS. The limiting single failure was determined with respect to its impact on fuel performance and system pressure. Regarding the pressure criteria, the major factors which cause an increase in RCS pressure are:
- Increasing coolant temperature
- Decreasing core flow
- Decreasing primary to secondary heat transfer The PLCS malfunction causes a reactor trip, on high pressurizer pressure, resulting in the maximum RCS pressure in the first two to five seconds following reactor trip. Therefore, any single failure which would result in a higher RCS pressure during the transient would have to affect at least one of the above parameters during the first two to five seconds following reactor trip.
The single failures that have been postulated are listed in Table 15.0-4. The failures which affect the RCS behavior during this interval are:
- Failure of the Pressurizer Pressure Control System
- Failure of the Feedwater Control System Failure of the feedwater control system could only result in an excess cooldown resulting in a lower peak pressure. Failure of the proportional heaters to turn off does have a small adverse effect on pressurization and thus, this failure is assumed in the analysis.
Regarding the approach to the fuel design limit, the major parameter of concern is the minimum hot channel DNBR. The major factors which cause a decrease in local DNBR are:
- Increasing coolant temperature
- Decreasing coolant flow
- Increasing local heat flux (including radial and axial power distribution effects)
No single failure was identified from Table 15.0-4 which would have a significant effect on DNBR prior to the reactor trip. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first two to five seconds following trip. Approved Design Material Accident Analyses Page 15.5-2
System 80+ Desian controloccameJn ( The single failures that have been postulated are listed in Table 15.04. The failures which affect the RCS behavior during this interval are: e Failure of the Pressurizer Pressure Control System
- Failure of the Reactor Regulating System Failure of the pressurizer pressure control system or reactor regulating system cannot appreciably affect any of the major factors which determine DNBR during the first two to five seconde following trip.
Thus, none of the single failures listed in Table 15.0-4 will result in a lower DNBR than that predicted for the PLCS malfunction with a loss of offsite power coincident with turbine trip. 15.5.2.2 Sequence of Events and Systems Operation Table 15.5.2-1 presents a chronological sequence of events which occurs during a PLCS malfunction in combination with loss of offsite power until the operator stabilizes the plant and initiates plant cooldown.
-15.5.2.3 Analysis of Effects and Consesp- *. Mathematical Model The Nuclear Steam Supply System (NSSS) response to a PLCS malfunction with loss of offsite power coincident with the turbine trip was simulated using the CESEC-III computer program A described in Section 15.0.3. The minimum DNBR was calculated using the CETOP code (Section 15.0.3.1.6), which uses the CE-1 CHF correlation described in Reference 19 of Section 15.0.
- Input Parameters and Initial Conditions Table 15.5.2-2 lists the assumptions and initial condition used for this analysis in addition to those
, discussed in Section 15.0. Additional clarification to the assumptions and parameters listed in Table 15.5.2-2 is provided as follows: Since the pressure transient is primarily due to an increase in RCS coolant inventory for the significant portion of the event and not to thermal expansion, no significant power, coolant temperature, or DNB transient is produced prior to reactor trip. Therefore, the initial conditions
~ for the principal process variables, with the exception of RCS pressure and pressurizer level, have no significant effect on the consequences. Minimizing the initial RCS pressure maximizes time to reactor trip on high pressurizer pressure and maximizes the increase in RCS inventory, therefore minimizing the steam volume in the pressurizer prior to trip. An initial pressure of 1905 psia was chosen which is a conservatively low pressurizer pressure with respect to the Table 15.0-3 initial condition. The initial water volume in the pressurizer was chosen to be 60% of the total volume.
Since the charging flow through the regenerative heat exchanger exceeds the letdown flow, the temperature of the makeup water added to the RCS by the charging pumps is decreased significantly. Therefore, a negative value of MTC was selected to maximize the positive reactivity addition from injection of cold makeup water. Ag,~ewed DeeQn anneard. AceMont Ana&ees Page 15.5-3
- System 80+ Design ControlDocument l
The total maximum charging flow to the RCS due to one operating pump is 150 gpm. and 30 gpm for the letdown flow. The Pressurizer Pressure Control System (PPCS) is assumed to be in the manual mode with the proportional sprays off preventing the PPCS from suppressing the resulting pressure transient. The limiting single failure with respect to RCS pressure is failure to turn proportional heaters off. This failure is assumed in the analysis.
- Results The dynamic behavior of NSSS parameters following a PLCS malfunction with loss of offsite power at turbine trip and with the limiting single failure, is presented in Figures 15.5.2-1 through 15.5.2-12.
Failure of the Pressurizer Level Control System (PLCS) causes an increase in reactor coolant system inventory initiated by maximum charging pump flow coupled with a decrease in letdown flow to its minimum. With the PPCS in the manual mode and the proportional sprays turned off, increase in RCS inventory results in a pressurizer pressure increase to the reactor trip analysis serpoint of 2475 psia at 923.85 seconds. The increase in pressure is also aggravated by the slight power increase that results from the injection of cold charging flow. The trip breakers open at 925.0 seconds. Since the Steam Bypass Control System (SBCS) is unavailable due to the loss of offsite power and the rate of closure of the turbine stop valves is faster than the rate of control rod insertion, pressurizer pressure increases to 2540 psia which opens the primary safety valves. The decrease in primary to secondary heat transfer due to the four pump loss of flow also contributes to the pressure increase. The RCS pressure reaches a maximum of 2682 psia at 927.42 seconds. A separate set of analyses were performed to determine the rainimum DNBR during a PLCS malfunction with a loss of offsite power coincident with turbine trip. The minimum DNBR was calculated to be 1.62. Decreasing core heat flux due to reactor trip and the opening of the primary safety valves causes the pressure to eventually drop. The unavailability of the steam bypass valves causes the steam generator pressure to increase, causing the main steam safety valves to open at 930.8 seconds. The decreasing core power and the safety valves function to limit the steam generator pressute to 1266 psia. The 2713 lbs of steam discharged by the pressurizer safety valve are contained within the in- l I containment refueling water storage tank with no releases to the atmosphere. The main steam safety valves discharge 134,009 lbs of steam to the atmosphere prior to 1800 seconds. At 1800 seconds, the operator stabilizes the plant and initiates plant cooldown, using the atmospheric dump valves. ; 15.5.2.4 Conclusions l The peak RCS and steam generator pressures reached during the Pressurizer Level Control System ; malfunction with a loss of offsite power at turbine trip and the limiting single failure are 2682 psia and 1266 psia, respectively. These pressures are less than 110% of the design pressures. Since this transient is due primarily to an increase in primary inventory which causes an increase in RCS pressure, the DNBR increases until reactor / turbine trip at which time the loss of offsite power resulting in a decrease in reactor , coolant flow causes the DNBR to decrease to a minimum of 1.62. Therefore, the acceptance criterion regarding fuel performance is met. ; 1 Alvvoved Design Alaterial Accident Analyses Page 15.5-4
System 80+ Design ControlDocument An interval of thirty minutes is assured from the initiation of the event until operator action is required to prevent the primary safety valves from potentially discharging water. An absolute high level alarm at 65% level will be actuated within twenty-six minutes of the time requiM for the operator to respond to the increase in pressurizer level. Table 15.5.2-1 Sequence of Events for the PLCS Malfunction with a Loss of Offsite Power Coincident with Turbine Trip Time (see) Event Setpoint or Value 0.0 Charging Flow Maximized & Letdown Flow Minimized - 923.85 Pressurizer Pressure Reaches Reactor Trip Analysis Setpoint, psia 2475 924.85 High Pressurizer Pressure Trip Signal Generated, Turbine Trip Occurs - 925.0 Trip Breakers Open - 925.0 less of Offsite Power - 927.05 Pressurizer Safety Valves open, psia 2540 927.42 Maximum RCS Pressure, psia 2682 930.77 Main Steam Safety Valves Open, psia 1212 2070 a 933.68 937.87 Pressurizer Safety Valves Close, psia Maximum Steam Generator Pressure, psia 1266 ) l 1800.0 Operator Initiates Plant Cooldown - l i Table 15.5.2-2 Assumptions and Initial Conditions for the PLCS Malfunction with a Loss of Offsite Power Coincident with Turbine Trip Parameter Value Initial Core Power level MW 3992 Core Inlet Coolant Temperature, 'F 555.8 Core Mass Flow,106 lbm/hr 152.3 Pressurizer Pressure, psia 1905 laitial Pressurirer Water Volume, ft 3 1400 CEA Wonh on Trip,10r2 Ap -8.86 Moderator Temperature Coefficient, Ap/'F -3.5x104 Doppler Reactivity Table 15.0-5 A b ; L 4prowd Du@n hterW- Acchnt Ane&su Page 15.5-5
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System 80+ Design ControlDocument O Q 15.6 Decrease in Reactor Coolant System Inventory 15.6.1 Inadvertent Opening of a Pressurizer Safety / Relief Valve The Inadvertent Opening of a Pressurizer Safety Valve event as described in SRP 15.6.1 is a non-limiting event in the Safety injection System analyses, as shown in Section 63 of Reference 2. 1 l 15.6.2 Double-Ended Break of a Letdown Line Outside Containment 15.6.2.1 Identification of Event and Causes - Direct release of reactor coolant may result from a break or leak outside containment of a letdown line, i instrument line, or sample line. The double-ended break of the letdown line out*Me containment, upstream of the letdown line control valve (DBLLOCUS) was selected for this a6 .,ecause it is the largest line and, thus, results in the largest release of reactor coolant outside t . antainment. The single active failure of an isolation valve was not considered in the analysis because the letdown line includes three isolation valves in series situated inside the containment. Hence, failure of one isolation , valve does not make the consequences of the event more severe.
- A letdown line break can range from a small crack in the piping to a complete double-ended break. The cause of the event may be attributed to corrosion which forms etch pits, or to fatigue cracks resulting from vibration or inadequate welds.
p 15.6.2.2 Sequence of Events and Systems Operation A double-ended break of the letdown line outside containment, upstream of the letdown line control valve releases primary fluid to the nuclear annex at a rate of approximately 27 lbs/sec. This is about one and a half times the maximum expected letdown flow. The maximum break flow is limited to this value by the use of letdown line orifices located inside containment downstream of the letdown heat exchanger. The event will set off a number of alarms. Table 15.6.2-1 lists the alarms that would be noted by the reactor operator in the control room. Of the alarms listed in Table 15.6.2-1, the letdown line low pressure alarm immediately alerts the operator of the event. The high temperature, high humidity and high radiation level alarms in the nuclear annex are expected to be triggered within a few seconds after the event initiation. The pressurizer low level, nuclear annex sump high level and the volume control tank low level alarms are expected to be triggered within a few minutes after initiation of the event. The alarms listed in Table 15.6.2-1 as well as relevant parameter indications are provided through two independent and diverse systems, namely, the Discrete Indication and Alarm System (DIAS) and the Data Processing System (DPS). The hardware for the DIAS is seismically and environmentally qualified. In , addition, Class IE electrical power is provided to the protective portion of the DIAS. Multiple and diverse alarms and indications ensure that a reliable means is available for alerting the operator of a letdown line break within a short period of time, g The analysis conservatively assumes that operator action is delayed until thirty minutes after the first t t alarm, when the operator isolates the letdown line, thereby terminating any further release of primary flow to the nuclear annex. One of three valves in series inside containment will be closed to isolate the letdown line break. The design of these valves, relative to their function during a letdown line break, Annrevent Deekn Atosenie!. AccMent Analyses Page 15.6-1
i l System 80+ Design ControlDocument is detailed in Sections 9.3.4.3.2 and 9.3.4.3.5. Subsequently, the operator is assumed to take appropriate , I steps for a controlled reactor shutdown. Table 15.6.2-2 presents the chronological sequence of events following a double-ended break of the i htdown line until the operator takes action to terminate the primary system fluid loss 30 minutes after l the initiation of the event. Subsequently, the operator manually trips the plant and cools down to shutdown cooling entry conditions. 15.6.2.3 Analysis of Effects and Consequences 15.6.2.3.1 Core and System Performance
- Mathematical Model The Nuclear Steam Supply System (NSSS) response to a double-ended break of a letdown line outside containment, upstream of the letdown line control valve, was simulated with the CESEC-III computer program described in Reference 27. The analysis assumes critical flow through the break and accounts for letdown line losses and for operation of the PPCS (Pressurizer Pressure Control System) and PLCS (Pressurizer Level Control System). The model of the letdown line break used is described in Reference 27 of Section 15.0.
- Input Parameters and Initial Conditions Table 15.6.2-3 lists the assumptions and initial conditions used for this analysis in addition to g those discussed in Section 15.0. Conditions were chosen to maximize the primary system mass W release for DBLLOCUS. This, in turn, leads to the most conservative predictions of radiological releases.
The initial conditions and NSSS characteristics used in this analysis of the maximum total radiological release for the letdown line break were based on parametric studies. The parameters evaluated were initial core inlet temperature, initial power level, initial pressurizer pressure, initial core inlet flow rate, initial pressurizer liquid inventory, and break size. The maximum total mass release is obtained when the transient is initiated with the following parameters from Table 15.0-3:
- 1. Maximum core power
- 2. Maximum allowed core inlet temperature
- 3. Low core flow
- 4. Maximum pressurizer pressure
- 5. High pressurizer level i In order to maximize the break flow, a reactor trip was prevented from occurring prior to operator action at thirty minutes. Since the reactor did not trip, the value of scram rod worth used in the analysis has no impact on the consequences of the event. Similarly, since the core power and core coolant temperature do not vary significantly during the course of the event, the Approved Design Material Accident Analyses Page 15.6-2
System 80+ oestan canarolDocument choices of the moderator temperature coefficient (MTC) and Doppler reactivity functions have little impact on the event consequences. l, All control systems are assumed to be in the automatic mode to maximize the total primary mass l release. The pressurizer heaters are assumed to be operational during the letdown line break
- event. This is not a mitigative feature. Instead, the primary system pressure is maintained at a ;
higher value due to the operation of the heaters. This maximizes the break flow. The break is assumed to be the full cross-sectional area (double-ended) pipe break. [
- l. The pressurizer level control system is assumed to be in the automatic mode during the transient.
As a result of an assumed malfunction in the control system the charging flow rate is ! conservatively assumed to decrease to the minimum value of 44 gpm during the transient. The lower charging flow rate maximizes the fluid temperature at the break thereby resulting in a i higher flashing fraction for the fluid at the break. This in turn maximizes the offsite radiological ! i release due to the increased steam release at the break. The pressurizer level control system could also fail in such a way as to maximize the charging : 1 flow rate (maximum flow rate of about 150 gpm). The impact of this high flow rate is to (1) l maintain the RCS pressure slightly higher resulting in slightly larger break flow rates during the i transient, and (2) decrease the flashing fraction of the fluid at the break due to the increased heat removal realized in the regenerative heat exchanger from the increased charging flow rate and the flashing fraction. Parametric studies have concluded that the increase in the flashing fraction due to lower charging flow rate is more limiting with respect to radiological releases than the l increase in the break flow rate due to the higher charging flow rate. Consequently, the analysis i '( which assumes the minimum charging flow rate yields conservatively high offsite radiological release. e Results l The dynamic behavior of important NSSS parameters following a DBLLOCUS are presented in
' Figurea 15.6.2-1 through 15.6.2-12. The decrease in the primary system mass causes the
. pressurizer pressure to decrease from the initial 2325 psia to about 2276 psia at 1800 seconds. ;
- l. During the same time period the pressurizer liquid volume decreases from an initial value of :
about 1400 ft3 to 567 ft3. l I Thirty minutes into the transient the operator isolates the letdown line, terminating the release of primary fluid outside the containment. During this time period no more than 48,617 pounds of 6 primary system fluid is released to the nuclear annex. Some time shortly after the termination of the primary system mass release, the operator manually trips the reactor. The minimum l DNBR for the letdown line break event described herein will not decrease below the specified j acceptable fuel design limit (SAFDL) value of 1.24. This is due to the fact that the RCS pressure : decrease during this event is not sufficient to decrease all of the fuel thermal margin prior to
- operator action at 30 minutes. !
. For a letdown line break with a reactor trip and coincident loss of offsite power, the minimum {
DNBR is also expected to remain above the SAFDL. This is because (1) the rate of decrease of ! RCS pressure during a letdown line break event is bounded by the rate for a double-ended steam :
./. generator tube rupture (SGTR) event, and (2) as shown in Section 15.6.3.2 for an SGTR event
- b. .with a loss'of offsite power, the minimum DNBR remains above the SAFDL of 1.24. l 4proweat Dee6n annenrio! AceMan Anaheen page 15.6-2
System 80+ Design ControlDocument A Letdown Line Break event in combination with a loss of offsite power is less limiting. Therefore, the final analysis did not assume a loss of offsite power. 15.6.2.3.2 Radiological Consequences
- Mathematical Model The DBLLOCUS event is indicated by several alanns listed in Table 15.6.2-1. Thirty minutes after the first alarm, which takes place immediately following the initiation of the event, the letdown line is isolated by the reactor operator. During this time 48,617 pounds of primary coolant is released to the nuclear armex.
The methodology used to calculate the inhalation doses at the Exclusion Area Boundary (EAB) and the Low Population Zone (LPZ) is discussed in Appendix 15A.
- Assumptions and Parameters The letdown line break outside containment results in the discharge of radioactivity to the environment. There are some uncertainties in the calculation of resultant radiation doses. These principally arise from uncertainties in the reactor coolant activity levels, the quantity of coolant released, the fraction of radionuclides that become airborne, the fraction of airborne activity that escapes the nuclear annex, and meteorological conditions that exists at the time of the accident.
These uncertair. ties are treated by taking worst case or conservative assumptions. These are:
- 1. An iodine activity spike with a spiking factor of 500 is assumed to occur coincident with ,
the initiation of the transient.
- 2. 'he quantity of coolant released outside containment is maximized by assuming most adverse initial conditions and by assuming critical flow through the break.
- 3. A blowdown Decontamination Factor (DF) of 5.05 is assumed in the calculation. That is,19.8% of all the iodine contained in the released primary mass is assumed to be airborne. This is based on the fraction of primary fluid that flashes to steam in the nuclear annex based on the enthaply of the escaping fluid.
- 4. The nuclear annex DF is assumed to be 1. That is, no credit is taken for the retention or filtration of radioactivity.
- 5. No credit is taken for ground deposition of the activity that escapes the nuclear annex or of decay in transit to the exclusion area boundary.
- 6. Other assumptions are contained in Appendix 15A.
- Results During the 1800-second duration of the transient no more than 48,617 pounds of primary system coolant is released outside the containment. The total secondary steam mass release via the ADVs from 30 mins to 120 mins and 30 mins to 8 hrs is 1,137,450 lbms and 2,659,600 lbms, respectively. The resulting radiological consequences have been conservatively calculated using Approved Design Material- Accident Analyses Pope 15.64
System 804- Desian contrat Document i assumptions and models described in the preceding subsections and Appendix 15A. The thyroid j inhalation and whole-body doses for the EAB and LPZ are presented in Table 15.6.2-4. The control room doses are provided in Section 6.4.3.
'15.6.2.4 Conclusions i
The double-ended break of a letdown line outside containment upstream of the letdown line control valve results in gradual depressurization of the reactor coolant system. The minimum Departure from Nucleate
- Boiling Ratio (DNBR) stays above the value at which the fuel pins would be calculated to experience DNB. The whole-body and thyroid inhalation doses are a small fraction of 10 CFR 100 guidelines.
15.6.3 Steam Generator Tube Rupture ; 15.6.3.1 Steam Generator Tube Rupture Without a Concurrent Loss of Offsite Power 15.6.3.1.1 Identification of Event and Causes The Steam Generator Tube Rupture (SGTR) accident is a penetration of the barrier between the Reactor
- Coolant System (RCS) and the main steam system and results from the failure of a steam generator j U-tube. Integrity of the barrier between the RCS and main steam system is significant from a !
radiological release standpoint. The radioactivity from the leaking steam generator tube mixes with the ! shell-side water in the affected steam generator Prior to tu6ine trip, the radioactivity is transported ! ,p through the turbine to the condenser where the noncondensible radioactive materials would be released j ,d via the Main Condenser Evacuation System. Following a reactor trip and turbine trip, the steam generator safety valves open to control the main steam system pressure. The operator can isolate the damaged steam generator any time after reactor trip occurs. The cooldown of the NSSS can then be l perfonri.1 by manual operation of the emergency feedwater and the atmospheric dump valves or the MSIV and turbine bypass valves, and using the unaffected steam generator. The analysis conservatively assumes that operator action is delayed until 30 minutes after initiation of the event. 4 Experience with nuclear steam generators indicates that the probability of a complete severance of the Inconel vertical U-tubes is remote. No such double-ended rupture has ever occurred in a steam generator of this design. The more probable modes of failure result in considerably smaller penetrations of the pressure barrier. They involve the formation of etch pits or small cracks in the U-tubes or cracks in the welds joining the tubes to the tube sheet. The most limiting steam generator tube rupture event is for a leak flow equivalent to a double-ended rupture of a U-tube at full power conditions. 15.6.3.1.2 Sequence of Events and Systems Operation Table 15.6.3-1 presents a chronological list of events which occurs during the steam generator tube rupture transient, from the time of the double-ended rupture of a steam generator U-tube to the attainment of cold shutdown conditions. 1 LThe sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event.
- Anwowed Deewe neeenner- Aecnont Annwee rene ss.s.s >
System 80+ Design ControlDocument 15.6.3.1.3 Analysis of Effects and Consequences 15.6.3.1.3.1 Core and System Performance e Mathematical Model The thermal-hydraulic response of the Nuclear Steam Supply System (NSSS) to the steam generator tube rupture without a concurrent loss of offsite power was simulated using the CESEC III computer program described in Reference 27 of Section 15.0. The thermal margin on DNBR in the reactor core was determined using the CETOP computer program described in Section 15.0.3 (Reference 29) with the CE-1 critical heat flux correlation described in CENPD-162 (Reference 19).
- Input Parameters and Initial Conditions The initial conditions and parameters assumed in the analyses of the system response to a steam generator tube rupture without a concurrent loss of offsite power are listed in Table 15.6.3-2.
Additional discussion on the input parameters and the initial conditions are provided in Section 15.0. Conditions were chosen to maximize the primary releases to atmosphere during the SGTR transient. This, in turn, leads to the most conservative predictions of radiological releases. The initial reactor operating conditions were varied over the operating space given in Table 15.0-3 to determine the set of conditions which would produce the most adverse consequences following a steam generator tube rupture without a concurrent loss of normal ac power. Various combinations of initial operating conditions were considered. These included, initial core inlet temperature, initial power level, initial RCS pressure, initial core coolant flow rate, initial pressurizer liquid level, initial steam generator liquid level, and fuel rod gap thermal conductivity. Decreasing the initial core inlet temperature increases the primary to secondary leak rate and integrated leak, but reduces the releases via the main steam safety valves. Since the steam generator pressure and temperature would be initialized at lower values compatible with the lower core inlet temperature, the steam generator pressure may not increase enough to challenge the main steam safety valves. Decreasing the core inlet flowrate results in a higher enthaply for the fluid entering the steam generator, resultant increased flashing fraction, and higher releases from the main steam safety valves. Thus, the parametric studies indicated that the maximum radiological release is obtained when the transient is initiated with the maximum allowed RCS pressure, maximum initial pressurizer liquid volume, maximum initial steam generator liquid volume, maximum core power, minimum core coolant flow, maximum core coolant inlet temperature, and a low fuel rod gap thermal conductivity. Prior to reactor trip, during a steam generator tube rupture event, the RCS temperature does not vary significantly. Therefore, there are no reactivity feedback effects and the choice of the moderator temperature coefficient (MTC) and Doppler reactivity feedback functions are not important considerations. In the SGTR analysis, the minimum value of scram rod worth of
-8.86% As was conservatively used.
The radiological consequences of the SGTR transient are also dependent on the break size. As the break size is decreased from that of a double-ended rupture, the integral leak is reduced for the 30-minute operator action interval and the radiological consequences will be less severe. The radiological consequences of a small tube rupture without the intervention of the reactor protection system and/or the operators would be well within the limits of 10 CFR 100, since the Eyarsmf l Design Material- Accident Anotyses Page 15.6-6
. System 80+ Design ConeralDocument i steam from the affected steam generator (SGs) flows through the turbine and condenses in the condenser and is cycled back as feedwater to the SGs. The major release point for radioactive ,
gases would be the condenser air-ejectors for which a decontamination factor of 100 would be .j ~ applicable. Along with this factor, a partition factor of 100 would be applicable in the affected SGs. Thus a factor of 10,000 would be applied on the steam releases to obtain the radiological releases, resulting in significantly small doses. ' Therefore, the most adverse break size is the largest assumed break of a full double-ended rupture of a steam generator tube. . I a : p :o Results 1
. }
The dynamic behavior of important NSSS parameters following a' steam generator tube rupture l is presented in Figures 15.6.3-1 through 15.6.3-16. For a double-ended rupture, the primary to secondary leak rate exceeds the capacity of the ! charging pump. As a result, the pressurizer pressure gradually decreases from an initial value of 2375 psia. The prunary to secondary leak rate and drop in pressurizer pressure cause the :
! charging pump to increase the charging flow, it is conservatively assumed that the charging flow j remains at 250 gpm throughout the transient. Even with this charging pump flow the pressurizer !
i pressure and level continue to drop. At the secondary side, the steam generator liquid level l increases due to the break flow. At 0.4 second a reactor trip signal is generated due to reaching ; the high steam generator water level trip condition. The pressurizer heaters are de-energized at j 623 seconds due to the continued drop in the pressurizer level. i i . i' p Following the reactor trip and with the turbine bypass assumed to be unavailable (i.e., in the manual mode), the main steam system pressure increases until the main steam safety valves open , at 5.4 seconds to control the main steam system pressure. A maximum main steam system pressure of 1273 psia occurs at 8.77 seconds. Subsequent to this peak in the pressure, the main steam system pressure decreases, resulting in the closure of the main steam safety valves 3 (MSSVs) temporarily. However, in the absence of feedwater flow, due to an MSIS on high steam generator level at the initiation of the event, the MSSVs cycle open and close to remove ; decay heat until operator action occurs at 30 minutes. I Prior to the reactor trip, the feedwater control system is assumed to supply feedwater to the steam I generators to match the steam flow through the turbine. Following the reactor trip, the feedwater flow is terminated on the MSIS which is generated on the high steam generator level at the initiation of the event. After 1800 seconds, the operator identifies and completes isolation of the affected steam generator by securing the reactor coolant pumps in the affected loop. The operator then initiates an orderly , cooldown via the atmospheric dump valves (ADVs), or by using the MSIV bypass valves
. associated with the unaffected steam generator and the turbine bypass valves. After the pressure and temperature of the reactor coolant are reduced to 330 psia and 350'F respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator.
i The maximum RCS and secondary pressures do not exceed 110% of design pressure following : a steam generator tube rupture event without a concurrent loss of offsite power, thus, assuring ; the integrity of the RCS and main steam system. No violation of the fuel thermallimit occurs, l l since the minimum DNBR remains above the 1.24- value throughout the event (see ; h Figure 15.6.3-16). j i
^
Approwear Deoden neeennw Aeommet Anaheen none 15.6-7 l
Syrtem 80+ Design ControlDocument i i Figures 15.6.3-1 through 15.6.3-16 represent the results for an SGTR event without a loss of offsite power at an initial core power level of 3876 MWt (102% of 3800 MWt). The results for , the case with 3% higher initial core power level (3992 MWt instead of 3876 MWt) are expected I to be similar. This is because, after reactor trip and prior to operator action at 1800 seconds, the decay heat (which is 3 % higher than that for the 3876 MWt power case) is removed via the MSSV. The MSSV steam releases and the steam releases via the ADV of the unaffected steam generator for cooldown to shutdown cooling entry condition are expected to be about 3% higher to accommodate the larger decay heat for the 3992 MWt core case. Since the MSSVs cycle open and close to remove the decay heat, it is expected that the RCS pressure and temperature variation and the SG pressure transient behavior prior to operator action at 30 minutes for the 3992 MWt case would be similar to those for the 3876 MWt core power case. Figure 15.6.3-11 gives the main steam safety valve integrated flow versus time for the steam generator tube rupture event without a concurrent loss of offsite power. At 1800 seconds, when operator action is assumed, no more than 161,397 (166,239 for 3992 MWt case) lbm of steam from the damaged steam generator and 120,742 (124,364 for 3992 MWt case) lbm from the intact steam generator are discharged via the main steam safety valves. Also, during the same time period, approximately 78,583 lbm of primary system fluid is leaked to the damaged steam generator. Subsequently, the operator begins a plant cooldown at the technical specification cooldown rate (100*F/hr) using the atmospheric dump valves of the unaffected steam generator, or by using the MSIV bypass valves associated with the unaffected steam generator and the turbine bypass valves. For the first two hours following the initiation of the event, a total of 1.219 x 106 (1.256 x 10 6for 3992 MWt case) lbm of steam flows from the steam generator. For 6 6 the two to eigh' hour cooldown period, an additional 1.514 x 10 (1.56 x 10 for 3992 MWt case) , Ibm of steam is discharged. 15.6.3.1.3.2 Radiological Consequences
- Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture ;
without a coincident loss of offsite power assumes a complete severance of a single steam l generator tube while the reactor is operating at full rated power. Occurrence of the accident leads J to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of a high steam generator level at approximately 0.4 second after the event initiation. The reactor trip automatically trips the turbine. Subsequent to reactor trip the steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator, i.e., the steam generator which experiences tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. Since the main feedwater flow is terminated on an MSIS, the steam generator pressure fluctuates around the MSSV opening setpoint resulting in the opening and closing of the MSSVs to remove the decay heat. After 1800 seconds the operator is assumed to initiate a plant cooldown at the technical specification cooldown rate (100*F/hr) using the ADVs of the unaffected steam generator. The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary system activity as well as primary system activity leaked from the tube break. The inventory of iodine and noble gas fission product activity available for Approwd Design Aiatorial- Accident Analyses Page 15.6-8
_..____! ? System 80-f Deslan Coneof Document t release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core, and the mass of steam discharged to the environment.
' Conservative assumptions are made for all these parameters. :
- Assumptions and Conditions ;
c The following assumptions and parameters are employed to determine the activity releases and - offsite doses for a Steam Generator Tube Rupture (SGTR). j 4' l. Accident doses are calculated for two different assumptions: (a) assumes a generated
- iodine spike (GIS) coincident with the initiation of the event and (b) assumes a pre- ;
accident iodine spike (PIS). ; - t
- 2. Following the accident, no additional steam and radioactivity are released to the j environment when the Shutdown Cooling System is placed in operation. l l 3. Thirty minutes after the accident, the affected steam generator is isolated by the operator.
No steam and fission products activities are released from the affected steam generator 4 thereafter.
- 4. A spiking factor of 500 is employed for the event-generated iodine spiking (GIS) j calculations.
~i
- _ 5. A fraction of the iodine in the primary-to-secondary leak is assumed to be immediately l airborne, if a path is available, .with a partition coefficient of 1 (Maximum fraction
~ 5 %).
- 6. The total amount of primary-to-secondary leakage through the rupture is 78,583 lbm.
- 7. For the 3876 MWt power level, the two hour steam flew through the ADV is l.219 x 1@ lbm, and an additional 1.514 x 1@ lbm of steam flows through the ADV i I
during the two to eight hour time period. For the 3992 MWt power level, the two hour steam flow through the ADV would be 3% higher (1.256 x 1@ lbm). Similarly, for this power level, during the two to eight hour time period an additional 1.56 x l@ Ibm of steam flows out through the ADV. I 8. Other assumptions are contained in Appendix 15A. e Mathematical Model The mathematical model employed to analyze the activity released during the course of the I transient is described in Appendix 15A. e Results
- The two-hout Exclusion Area Boundary (EAB) inhalation and whole-body doses and the eight-hour Low Population Zone (LPZ) boundary inhalation and whole-body doses are presented in Table 15.6.3-3. The calculated EAB and LPZ doses are well within the' acceptance criteria.
The control room doses are provided in Section 6.4.3. L = omen anoww. Aeaume am noe 1s.s-s i i
Syctem 80+ Design ControlDocurnent 15.6.3.1.4 Conclusions The radiological releases calculated for the SGTR event without a concurrent loss of offsite power are a small fraction of the 10 CFR 100 guidelines. The RCS and secondary system pressures are well below 110% of the design pressure limits, thus, assuring the integrity of these systems. Additionally, no violation of the fuel thermal limits occurs, since the minimum DNBR remains above the 1.24 value . throughout the duration of the event. The plant is maintained in a stable condition due to automatic actions, and after thirty minutes, the operator employs the plant emergency procedure for the steam generator tube rupture event to cool down the plant to shutdown cooling entry conditions. 15.6.3.2 Steam Generator Tube Rupture With a Concurrent Loss of Offsite Power 15.6.3.2.1 Identification of Event and Causes The significance of a steam generator tube rupture accident is described in Section 15.6.3.1.1. As a result of the loss of normal ac power, electrical power would be unavailable for the station auxiliaries such as the reactor coolant pumps. Under such circumstances the plant would experience a loss of load, normal feedwater flow, forced reactor coolant flow, condenser vacuum, and steam generator blowdown. The plant is operating at full power initially before the assumed reactor trip. An early reactor trip maximizes radiological releases, since tb main steam safety valves open more frequently prior to operator action, releasing radioactive materia's to the atmosphere. 15.6.3.2.2 Sequence of Events and Systems Operation For the SGTR event with a loss of offsite power, two separate analyses were performed. The first case, discussed in Section 15.6.3.2.2.1, was chosen to maximize the impact of the event on fuel performance, thereby realizing the lowest minimum DNBR during the event. The second case, discussed in Section 15.6.3.2.2.2, maximizes the offsite radiological doses. 15.6.3.2.2.1 Minimum DNBR Case For this case, conditions were chosen to initiate the tube rupture from a power operating limit (POL). During the SGTR event, the pressurizer pressure continuously decreases while the core power, core flow rate and core average temperature remains constant until a reactor trip is realized. As a result, the DNBR also continuously decreases, thus eroding the thermal margin to DNB. Consequently, a CPC trip is generated on low pr surizer pressure / low DNBR. The turbine / generator trips due to the reactor trip and a loss offsite pc is assumed concurrent with the turbine / generator trip. This is a change from the earlier analysis wuch assumed a 3 seconds delay in loss of offsite power. Subsequent to the reactor trip, the core heat flux begins to decrease. The core flow rate also decreases due to the coastdown of the reactor coolant pumps. Since the core flow rate decreases faster than the core heat flux, the DNBR decreases very rapidly during a brief period of time subsequent to reactor trip and loss of offsite power. 15.6.3.2.2.2 Maximum Offsite Radiological Release Case For this case, the initial conditions and assumptions are chosen to maximize the offsite radiological releases. ApprosedDesmn Materket- AccMent Anotyses Page 15.G-10
System 80 + Design ControlDocument Table 15.6.3-4 presents a chronological list of events which occur during the steam generator tube rupture (V) event with a loss of offsite power, from the time of the double-ended rupture of a steam generator U-tube to the attainment of cold shutdown conditions. As a result of the reactor trip, the turbine / generator trips within one second after the high steam generator level reactor trip signal. Subsequently, offsite power is assumed to be lost due to grid instability. A 3-second delay between the time of turbine trip and the time of loss of offsite power is assumed in the analysis. This assumption does not impact the magnitude of the offsite radiological releases, since no fuel failure is calculated for the SGTR event with a loss of offsite power. Subsequent to a reactor trip, stored and fission product decay energy must be dissipated by the reactor coolant and main steam systems. In the absence of forced reactor coolant flow, heat removal from the reactor core is facilitated by natural circulation reactor coolant flow. Initially, the residual water inventory in the steam generators is used and the resultant steam is released to atmosphere via the main steam safety valves. With the availability of standby power, emergency feedwater is automatically initiated on a low steam generator water level signal. The operator can isolate the damaged steam
. generator and cool the NSSS using manual operation of the emergency feedwater system and the atmospheric steam dump valves of the unaffected steam generator any time after reactor trip occurs. The analysis presented herein conservatively assumes operator action is delayed until 30 minutes after first indicetion of the event.
The primary source of the emergency feedwater is the emergency feedwater storage tanks. The minimum capacity of each storage tank is 350,000 gallons which is more than enough to maintain the plant at hot ,f 3 standby for 8 hours. Each emergency feedwater storage tank is provided with an atmospheric vent to
) maintain atmospheric pressure inside the tank.
15.6.3.2.3 Analysis of Effects and Consequences 15.6.3.2.3.1 Core and System Performance e Mathematical Model The mathematical model used for the evaluation of core and system performance is identical to that described in Section 15.6.3.1.3.1, except for the minimum DNBR calculation. The thennal margin on DNBR in the reactor core was determined using the TORC computer program. This computer program is described in References 18 and 21. e input Parameters and initial Conditions i) Minimum DNBR Case The initial conditions and input parameters for this case were chosen to obtain the closest approach to the fuel design limit. Several parametric cases were analyzed to determine the most limiting conditions and parameters. These were as follows: maximum core power (3992 MWt), maximum cote inlet temperature (561 *F), maximum core mass flow rate (185.8 x 106 lbm/hr), and maximum pressurizer pressure (2325 psia). The value of one pin integrated radial peaking factor (F,) was iterated upon until power operating limit ('S (POL) conditions were obtained. The value of F, thus obtained and used in the analysis () was 1.8005. Aptwoved Design hinterial. AccMent Analyses Page 15.6-11
System 80+ Design ControlDocument ii) Maximum Offsite Radiological Release Case The input parameters and initial conditions used for the evaluation of core and systems performance are identical to those described in Section 15.6.3.1.3 and are given in Table 15.6.3-5.
- Results i) Minimum DNBR Case Figure 15.6.3-32 shows the variation of the minimum DNBR during the most limitirg SGTR event with a loss of offsite power with respect to fuel performance. The thermal margin to DNB decreases continuously as a result of the decrease in RCS pressure during the event. The continuous decrease in RCS pressure is caused by the loss of primary coolant through the ruptured steam generator tube.
A CPC trip is generated on low pressurizer pressure / low DNBR at 542.75 seconds. The turbine / generator trips as a result of the reactor trip. It is assumed that a loss of offsite power occurs concurrent with the turbine / generator trip. The reactor trip causes the control rods to drop resulting in a decrease in the core heat flux. The reactor coolant pumps (RCPs) begin to coastdown in response to the loss of offsite power. Since the core flow rate decreases faster (as a result of the RCP coastdown) than the core heat flux initially there is a short time period during which the DNBR decreases very rapidly (see Figure 15.6.3-32). The core heat flux decreases further and the imbalance between the heat flux reduction and core flow rate decrease is eliminated. The DNBR increases sharply subsequently as the core heat flux is significantly reduced due to the control rods reaching the bottom of the core. As can be seen from Figure 15.6.3-32, the minimum DNBR stays above the specified acceptable fuel design limit (SAFDL) of 1.24 throughout the transient. Hence, no fuel failure is predicted to occur for the SGTR event with a loss of offsite power. ii) Maximum Offsite Radiological Release Case The dynamic behavior of important NSSS parameters following a steam generator tube rupture with a loss of normal AC power are presented in Figures 15.6.3-17 through 15.6.3-31 for the maximum offsite radiological release case. At 0.4 seconds after the initiation of the tube rupture a reactor trip signal is generated due to a high steam generator level condition. Subsequent to the reactor trip, the RCS pressure begins to decrease rapidly, and the pressurizer empties at about 1090.4 seconds due to the continued primary-to-secondary leak. After the pressurizer empties, the reactor vessel upper head begins to behave like a pressurizer and controls the RCS pressure response. Due to the loss of offsite power, the reactor coolant pumps begin to coast down reducing the core coolant flow rate, and the mass flow into the upper head region. This region becomes thermal-hydraulically decoupled from the rest of the RCS, and due to flashing caused by the depressurization and boiloff from the metal structure to coolant heat transfer, voids form in this region at about 894 seconds. The void formation is enhanced by the decoupling effect, since the RCS pressure reduction due to primary system cooling is felt in this region, while the RCS temperature reduction is not. The significant impact of voids in the upper Approved Design Material. AccMent Analyses Pope 15.6-12
t 1 o System 80+ Desinrs ComrolDocumerrt . head region is a slower RCS pressure decay resulting in the generation of the Safety Injection i
~ Actuation Signal (SlAS) at 1415.8 seconds and the initiation of the safety injection flow. _
Following turbine trip and loss of offsite power, the main steam system pressure increases until , i ] the main steam safety valves open at about 5.4 seconds to control the main steam system pressure. A maximum main steam system pressure of 1275 psia occurs at aboit 9 seconds. I Subsequent to this peak in pressure, the main steam system pressure decreases resulttag in the i closure of the safety valves temporarily. However, in the absence of feedwater flow, the MSSVs j cycle open and close to remove decay heat until operator action at 30 minutes. I' Prior to the turbine : rip, the feedwater control system is assumed to supply feedwater to the steam generators to match the steam flow. Following reactor trip and loss of offsite power,- the feedwater flow ramps down to zero. Consequently the steam generator water levels decrease due 1 to the steam flow out through the main steam safety valves, and a low steam generator level signal is generated at 1467 seconds for the intact steam generator. Subsequently, at 1527
- secor.ds, emergency feedwater flow is initiated, and the intact steam generator water level begins to recover.
After 1800 seconds, the operator identifies the affected steam generator. The operator then initiates an orderly cooldown by means of the atmospheric dump valves and emergency feedwater flow to the unaffected steam generator. After the pressure and temperature are reduced to 330 e psia and 350*F, respectively, the operator activates the shutdown cooling system and isolates the unaffected steam generator. The maximum RCS and secondary pressures do not exceed 110% of design pressure following a steam generator tube rupture event with a concurrent loss of offsite power, thus, assuring the integrity of the RCS and the main steam system. Figures 15.6.3-17 through 15.6.3-31 represent the results for an SGTR event with a loss of offsite power at an initial core power level of 3876 MWt (102% of 3800 MWt). The results for , the case with 3% higher initial core power (3992 MWt instead of 3876 MWt) are expected to be I similar. This is because the initial RCS and SG pressures, RCS temperature, and flow rates . .would be similar and only the RCS pressure is decreasing prior to the reactor trip as a result of J the tube rupture. The rate of RCS pressure decrease would also be similar since critical flow occurs through the break prior to a reactor trip. The major difference between the 3876 MWt and 3992 MWt power level cases would be the increased steam release for the 3992 MWt case ! during the cooldown period because of the increased decay power. This increase in steam release is expected to be about 3% in order to cool down to shutdown cooling entry conditions. Figure 15.6.3-27 gives the main steam safety valve integrated flow rates versus time for the steam generator tube rupture event with a loss of offsite power. At 1800 seconds, when operator action is assumed, no more than 147,657 (152,087 for the 3992 MWt case) lbm of steam from the damaged steam generator and 123,110 (126,803 for the 3992 MWt case) lbm from the intact steam generator are discharged through the main steam safety valves. Also, during the same time period approximately .71,715 lbm of primary system mass is leaked to the damaged steam generator. Subsequently, the operator begins a plant cooldown at the Technical Specification cooldown rate '(100*F/hr) using the intact steam generator, atmospheric dump valves and emergency fedwater system.' For the first two hours following the initiation of the event, about Os 6 6 1.033 x 10 (1.064 x 10 for the 3992 MWt case) lbms of steam are released to the environment through the atmospheric dump valves. For the two to eight hour cooldown period an additional n r aseen anseerW Assent AWyses Pope 75.513
System 80+ Design ControlDocument 6 1.714 x 106 (1.765 x 10 for the 3992 MWt case) Ibms of steam are released via the atmospheric dump valves. 15.6.3.2.3.2 Radiological Consequences
- Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power and a loss of offsite power three seconds after the turbine trip. Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of a high level in the affected steam generator at approximately 0.4 seconds after the event initiation. The reactor trip automatically trips the turbine.
The steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator, i.e., the steam generator which experiences tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. After 1800 seconds, the operator initiates a plant cooldown at the technical specification cooldown rate (100*F/hr) using the unaffected steam generator, atmospheric dump valves, and the emergency feedwater system. The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary activity as well as primary system activity leaked from the tube break. The inventory of iodine and noble gas fission product activity available for release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core, and the mass of steam discharged to the environment. Conservative assumptions are made for all these parameters.
- Assumptions and Conditions The assumptions and parameters employed for the eval ation of radiological releases are identical to those described in Section 15.6.3.1.3.2 with the following exceptions and/or additions.
- 1. For steam release through the atmospheric dump valves, a Decontamination Factor (DF) of 1 is assumed..
- 2. The total amount of primary-to-secondary leakage through the rupture is 71,715 lbm.
- 3. For the 3876 MW! core power level, the half hour to two hour steam flow through the 6
atmospheric dump valves is 1.033 x 10 lbms. An additional 1.714 x 106 lbms of steam are discharged to the environment through the atmospheric dump valves during the two to eight hour time period. For the 3992 MWt power level, the half hour to two hour 6 steam flow through the ADV would be 3% higher (1.064 x 10 lbm). Similarly for this power level, during the two to eight hour time period an additional 1.765 x 106 lbm steam flows out through the ADV. O Asvvoved Design Material- AccMent Analyses Page 15.6-14
. _ . - _ - __ - - _ _ _ _ _ __ . - . . . __ ~ . _ _ . _ .
l
; Sv? tem 80+ Design ControlDocanent I o - Mathematical Model' The mathematical model employed in the evaluation of the radiological consequences during the course of the transient is described in Appendix 15A.
t e Results 4 The two-hour Exclusion Area Boundary (EAB) and the eight-hour Low Population Zone (LPZ) i a boundary inhalation and whole body doses are presented in Table 15.6.3-6. The calculated EAB l and LPZ doses are well within the acceptance criteria.
- The control room doses are provided in Section 6.4.3.
]
j 15.6.3.2.4 Conclusions The radiological releases calculated for the SGTR event with a loss of offsite power are a small fraction of 10 CFR 100 guidelines. The RCS and secondary system pressures are well below the 110% of the l design pressure limits, thus, assuring the integrity of these systems. Additionally, no violation of the fuel .l i thermal limits occurs, since the minimum DNBR remains above the 1.24 value throughout the duration : , of the event. 4 Voids form in the reactor vessel upper head region during the transient, due to the thermal hydraulic
- decoupling of this region from tN RCS. The upper head region liquid level remains well above the top of the hot leg throughout the trandent. Therefore, natural circulation cooldown is not impaired during g the transient. Furthermore, the uppet head voids begin to collapse upon actuation of the safety injection flow, indicative of stable plant conditions. - After thirty minutes, the operator employs the plant
- emergency procedure for the steam generator tube rupture event to cool down the plant to shutdown cooling entry conditions.
15.6.3.3 Steam Generator Tube Rupture with a Loss of Offsite Power and Single Failure 15.6.3.3.1 Id-tification of Event and Causes I i in addition to the tube rupture with a loss of offsite power, as evaluated in Section 15.6.3.2, this event also assumes the most limiting single failure with respect to radiological releases. The systems used to mitigate the consequences of this event are: o Safety Injection System (SIS) e-Emergency Feedwater System (EFWS) e Atmospheric Dump Valves (ADVs) The single failures which may impact the radiological consequences of the SGTR event are: o Failure of an ADV to close in the affected steam generator after the operator initially opens it. e Failure of a diesel generator to start following the loss of offsite power. c 1 AssensweetDesipo asseenW Acaddent AmWysse Aspe 75.8 75 '
System 80+ Design ControlDocument The failure of an ADV to close in the affected steam generator will result in aJdit onal steam release until the operator is able to isolate the ADV by closing the associated block valve. The failure of the diesel generoor to start will leave the following components inoperable: two SI pumps, one charging pump, one motor-oriven emergency feedwater pump, and one half of the pressurizer backup heaters. The partial loss of the heat removal capabilities of the safety injection flow and emergency feedwater flow may require the o;erator to steam from the affected generator in order to maintain the RCS in a subcooled state. Steaming also would be required to prevent overfilling of the affected steam generator. The excess steaming due to the failure of the ADV to close is larger than that resulting from the failure of a diesel generator. Therefore, the failure of an ADV to close in the affected steam generator is the most limiting single failure with respect to radiological releases. 15.6.3.3.2 Sequence of Events and Systems Operation Table 15.6 3-7 presents a chronological list of events which occur during the steam generator tube rupture event with a loss of offsite power and stuck open ADV, from the time of the double-ended rupture of a steam generator U-tube to the attainment of shutdown cooling entry conditions. The sequence presented demonstrates that the operator can cool the plant dom to shutdcwn cooling entry conditions during the event. All actions required to stabilize the plant and perform the required repairs are not described here. The operator actions assumed in this analysis are consistent with the ABB-CE Emergency Operations Guidelines (EOGs) documented in Reference 35 of Section 15.0. The major operator actions assumed in the analysis are summarized below and listed in Figure 15.6.3-48.
- The operator opens one Atmospheric Dump Valve (ADV) in each steam generator in order to cool the RCS at a cooldown rate of 100*F/hr. The initial cosidown of the RCS is aimed at preventing reopening of the MSSVs on the affected steam generator by cooling down the RCS to 10*F below the saturation temperature corresponding to the MSSV opening pressure setpoint.
An additional 5'F is employed to account for instrument uncertainties. The technical specification cooldown rate of 100*F/hr is used in lieu of a plant procedure specific cooldown rate. This rapid cooldown rate requires a relatively large valve opening area and results in more steam flow out the stuck open ADV. The failed ADV is assumed to be open about 12% to achieve the Technical Specification limited cooldown rate of 100*F per hour. Since this cooldown rate is tech spec controlled, it would take an operator error, which is classified as a failure, to result in the full opening of the ADV. Thus, inclusion of a stuck ADV plus an operator error to cause it to open to 100% is equivalent to considering multiple failures. Hence the analysis considers only the limiting single failure of a stuck ADV which is assumed ta be partially open (about 12%) for achieving the tech spec controlled cooldown rate of 100*F.
- The time delay for the first operator action identified above is consistent with the guidelines of Reference 36 which recommends a 5 minute operator action delay time for a steam generator tube rupture, and an additional two minutes for completion of a discrete operator manipulation. Thus, a 7 minute operator action time with reference to the reactor trip time is assumed for completion of the first action, namely, opening of the ADVs to cool down the RCS to 550*F which is about 15'F below saturation temperature at the MSSV opening pressure setpoint.
O Approved Design Materie! AccMent Ana&ses Page 15.6-16
.. - .. . .. - -. - - . - . . - - - . . . - -- - - . - ~.
l
. System 80+ Dessen coneet occammut .
e. O The operator attempts to isolate the affected steam generator when the RCS temperature is below 550*F. At this time it is assumed that the ADV in the affected steam generator sticks open. The operator will be alerted to the fact that the ADV has not closed by the following signals. j
- 1. . Continued alarming from the area radiation monitors. 1
- 2. Continued indication of steam flow through the flow measuring venturis on the steam l
' generator. j
- 3. . Decreasing steam generator level in spite of the attempted isolation which should have l caused the level to increase.
l o The operator closes the block valve associated with the stuck open ADV on the affected generator 'l 30 minutes after the attempted isolation. This delay is consistent with the criteria for operator j actions outside of the control room as stated in Reference 36. The time delay includes the time ; it takes to get to the location' of the block valve, and the time required to completely close the . valve. s e . The operator opens the pressurimr gas vent in order to regain pressurizer level two minutes after , the block valve is closed. The timing of this action is consistent with the guidelines of j Reference 36. The operator will use the SI system, the pressurizer backup heaters, and the ; pressurizer gas vent to control RCS inventory and subcooling. ; e The operator continues to cool down the RCS using the unaffected generator at 20'F/hr. This O analytical assumption to' reduce the cooldown rate from 100*F/hr to 20*F/hr maximizes the l radiological release during the long-term cooldown by: j
- 1. Delaying entry into shutdown cooling until 8 hours after event initiation, thereby, :
maximizing the primary heat to be removed through the ADVs within the 0-8 hour time I period.
- 2. Maximizing the primary-to-secondary leak, thereby, increasing the operators' use of the operable ADV in the affected steam generator to prevent its overfilling.
- 3. Maintaining the primary-to-secondary leakage at a higher enthaply, thereby, maximizing the flashing fraction of the leakage at the secondary side.
e The operator maintains approximately a 20*F subcooling margin as per Reference 35. e The operator will use the unisolated ADV on the affected SG in order to prevent its overfilling . due to the primary-to-secondary leak. The potential for boron' dilution during the recovery phase of a SGTR event is considered to be insignificant since the System 80+ Emergency Operations Guidance will include steps to prevent backfill from the secondary system through the ruptured tube. < This is accomplished by maintaining a positive pressure difference between the primary and D secondary sides. Furthermore, backfill is not necessary to prevent overfilling of the large System N j 80+ steam generator as a result of the SGTR event. ) i Anwoweef Dee4pr aseeend AceMont Anervene rare rs.6-r1 1
System 80+ Design ControlDocument 15.6.3.3.3 Analysis of Effects and Consequences 15.6.3.3.3.1 Core and System Performance
- Mathematical Model The thermal-hydraulic response of the Nuclear Steam Supply System (NSSS) to the steam generator tube rupture with a loss of offsite power and stuck open ADV was simulated using the CESEC-III computer program up to the time the operator takes control of the plant and a CESEC-Ill based cooldown algorithm thereafter. The CESEC-III computer program is described in Reference 27. The thermal margin on DNBR in the reactor core was evaluated using the CETOP computer program (Reference 29) as described in Section 15.0.3 with the CE-1 critical heat flux correlation described in CENPD-162 (Reference 19).
- Input Parameters and Initial Conditions The initial conditions and input parameters employed in the analyses of the system response to a steam generator tube rupture with a concurrent loss of offsite power and stuck open ADV are listed in Table 15.6.3-8. Additional discussion on the input parameters and the initial conditions are provided in Section 15.0. Conditions were chosen to maximize the radiological releases.
The initial reactor operating conditions were varied over the operating space given in Table 15.0-5 to determine the set of conditions which would produce the most adverse consequences following a steam generator tube rupture with a loss of offsite power and stuck open ADV. Various combinations of initial operating conditions were considered in order to determine the reactor trip time which would result in the most adverse radiological releases. The parametric studies indicated that the maximum offsite mass release is obtained when the transient is initiated with the maximum allowed RCS pressure, maximum initial pressurizer liquid volume, minimum initial steam generator liquid volume, maximum core power, minimum core coolant flow, and maximum core coolant inlet temperature. The minimum initial steam generator liquid volume results in a delayed reactor trip signal.
- Results The dynamic behavior of important NSSS parameters following a steam generator tube rupture is presented in Figures 15.6.3-33 through 15.6.3-47.
For a double-ended rupture, the primary-to-secondary leak rate exceeds the capacity of the charging pumps. As a result, the pressurizer pressure gradually decreases from an initial value of 2375 psia. Even with the maximum charging pump flow of 180 gpm, the pressurizer pressure and level continue to drop. In addition, the affected SG water level continued to increase due to the primary to secondary leakage. At 1758 seconds a reactor trip signal is generated due to exceeding the high steam generator water level trip setpoint. The pressurizer empties at approximately 1783 seconds (Figure 15.6.3-37). At 2418 seconds a safety injection actuation signal is generated, and the safety injection flow is initiated. After the pressurizer empties, the reactor vessel upper head begins to behave like a pressurizer, and controls the reactor coolant system pressure until the pressurizer begins to refill at approximately 5583 seconds. Due to flashing caused by the depressurization, and the boil off due to the metal structure to coolant heat Approved Design Materia!. AccMent Analyses Page 15.6-18
-t
)
i Syrtem 80+ Design ConvalDocument - l l gQ transfer, the reactor vessel upper head begins to void at about 1794 seconds (Figure 15.6.3.38). !
-(/ Consequently, the RCS pressure (Figure 15.6.3-34) begins to decrease at a lower rate at this j time. .
- i Following reactor trip and with turbine bypass unavailable, the main steam system pressure !
increases until the MSSVs open at 1762 seconds to control the main steam system pressure. A. j maximum main steam system pressure of 1272 psia occurs at 1765 seconds. Subsequent to this l
' peak in the pressure, the main steam system pressure decreases, resuning in the closure of the l Main Steam Safety Valves (MSSVs) at 1849 seconds. The MSSVs cycle two additional times l in this manner prior to the operator taking control of the plant.
Prior to reactor trip, the main feedwater control system is assumed to supply feedwater to match flow through the turbine. Following reactor trip, the main feedwater flow is terminated due to the loss of offsite power. As the level in the steam generators decrease an Emergency Feedwater , Actuation Signal (EFAS) is generated resulting in, emergency feedwater flow which acts to I restore the SG level.
]
l At 2178 seconds the operator takes contw! cf me plant and opens one ADV on each SG to cool down the plant. This is consistent with the EOGs. At 3663 seconds the RCS has been cooled to 550*F. The operator then isolates the emergency feedwater to the affected generator, closes the main steam isolation valves of both steam generators, and attempts to close the ADV of the affected generator. The operator recognizes that the ADV did not close and has the appropriate block valve closed within 30 minutes. The operator then initiates an orderly cooldown by means of the atmospheric dump valves and the emergency feedwater flow to the unaffected steam O' - generator. Thereafter, the operator will steam the affected steam generator only for preventing overfilling due to the leak flow. After ik. piessure and temperature are reduced to 330 psia and 350*F, respectively, the operator sativates the shutdown cooling system and isolates the unaffected steam generator. I The potential for SG overfilling cxists due to the continued break flow from the primary side to the secondary side of the af6ed SG even after isolation of this SG. However, the System 80+ design can accommodate the SG level buildup more easily due to the larger SG volume in comparison to that for the System 80 design (about 25% more volume). During the SGTR event, the operator monitors the SG level to ensure that the level does not go much above the steam separators (around the upper level indication nozzle). This is accomplished by (1) minimizing the differential pressure between the primary and secondary sides of the steam generator (to control the break flow) and (2) by selectively steaming the affected SG via one of its two ADVs. Figure 15.6.3-42B shows that, after about 15000 seconds, the break flow rate drops from 1 approximately 35 to 12 lbm/sec. At this time, the operator is expected to use SG level control to prevent potential SG ' overfilling. Based on critical flow of steam through one ADV at the steam pressure, a flow rate of about 70 lbm/sec can be achieved. -.This suggests that the break flow rate of 12 to 35 lbm/sec can be accuiiuuodated by partial opening of one ADV (17 to 50%) to maintain an essentially stable steam generator level. 1
% Figures 15.6.3 33 through 15.6.3-47 represent the results for an SGTR event with a loss of I offsite power and stuck open ADV at an initial core power level of 3876 MWt (102% of 3800 -
MWt). These results are expected to be in general applicable to the SGTR event initiated at a l l Anmd Denko aenendah AceMont Ane&oes _ Page 15.6-19 l
System 80 + oesign controlDocument 3% higher power level of 3992 MWt. This is because the initial RCS and SG pressures, RCS temperature, and core flow rates would be similar. Only the RCS pressure is decreasing prior to the reactor trip, as a result of the tube rupture. The rate of RCS pwssure decrease would also be similar since critical flow occurs through the break prior to the reactor trip. The major difference between the 3876 MWt and 3992 MWt power level cases would be the increased steam release for the 3992 MWt case during the cooldown period because of the increased decay power. This increase in steam release is expected to be about 3% in order to cool down to shutdown cooling entry conditions. Figure 15.6.3-46 gives the main steam safety valve integrated flow rates versus time for the steam generator tube rupture event with a loss of offsite power and a stuck open ADV. At 2178 seconds, when operator action is assumed, no more than 83,333 (85,833 for the 3992 MWt case) Ibm of steam from the damaged steam generator and 40,490 (41,705 for the 3992 MWt case) Ibm from the intact steam generator are discharged via the main steam safety valves. Also, during the same time period approximately 109,940 lbm of primary system mass is leaked to the damaged steam generator, Subsequently, the operator begins a plant cooldown at the technical specification cooldown rate (100*F/hr) using both steam generators, the atmospheric dump valves, and the emergency feedwater system. Once the affected steam generator is isolated, it is assumed that the operator reduces the cool down rate to 20*F/br. For the first two hours fo!!owing the initiation of the event,294,000 (302,820 for the 3992 MWt case) Ibms of steam are released to the environment through the atmospheric dump valves. For the two to eight hour 6 cooldown period an additional 993,000 (1.023 x 10 for the 3992 MWt case) lbms of steam are released via the atmospheric dump valves. 15.6.3.3.3.2 Radiological Consequences e Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power, a loss of offsite power three seconds after turbine generator trip, and a stuck open ADV Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result'of approaching a high liquid level condition in the affected steam generator at approximately 1758 seconds after the event initiation. The reactor trip automatically trips the turbine generator. The steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator, i.e., the steam generator which experiences the tube rupture, continues until the secondary system pressure is below the main steam safety valve setpoint. After 2178 seconds, the operator initiates a plant cooldown at the technical specification cooldown rate (100*F/hr) using the steam generators, atmospheric dump valves, and the emergency feedwater system. The cooldown rate of 100*F/hr is used in lieu of a plant procedure specific cooldown rate. This rapid cooldown rate requires a larger valve opening area and results in more steam flow through the stuck open ADV. Upon isolation of the affected generator the cooldown continues at 20*F/hr using the unaffected generator. The operator may steam the affected steam generator to prevent its overfilling. The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary activity as well as primary system activity leaked via the tube Attwowwt Design Meteria! AccMent Analyses Page 15.6 20
' System 80+ Desinn ControlDocument ,
i t 1 break. The inventory of iodine and noble gas fission product activity available for release to the ; environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core and the mass of steam discharged to the environment. Conservative - assumptions are made for all these parameters. e Assumptions and Conditions The assumptions and parameters employed for the evaluation of radiological releases are: i i
- 1. Accident doses are calculated for two different assumptions: (a) an event Generated ;
Iodine Spike (GIS) coincident with the initiation of the event, and (b) a Pre-accident [ lodine Spike (PIS). '; I
- 2. Followirg the accident, no additional steam and radioactivity are released to the environnent when the shutdown cooling system is placed in operation.
- 3. A spiking factor of 500 is employed for the GIS. l
- 4. The tube leakage which flashes to steam is assumed to be released to the atmosphere with i
a Decontamination Factor (DF) of 1.0. (See Figure 15.6.3-44.) The 0-2 hour and 2-8 hour primary-to-secondary leakage through the rupture is 316,300 ! 5. lbm and 671,300 lbm, respectively. l
- 6. Dilution of primary and secondary systems due to SI flow and emergency feedwater flow .
is accounted for in the dose calculation. i
- 7. Other assumptions are contained in Appendix 15A.
i e Mathematical Model 5 . The mathematical model employed in the evaluation of the radiological consequences during the . course of the transient is described in Appendix 15A. j
- Results The two-hour Exclusion Area Boundary (EAB) and the eight-hour Low Populath 7.one (LPZ) inhalation and whole-body doses are presented in Table 15.6.3-9. The calculmea EAB and LPZ doses are well within the acceptance criteria. ,
The control room doses are provided in Section 6.4.3. 15.6.3.3.4 Conclusions The radiological releases calculated for the SGTR event with a loss of offsite power and a stuck open
. ADV are well within the 10 CFR 100 guidelines. ~ The RCS and secondary system pressures are well below the 110% of the design pressure limits, thus, assuring the integrity of these systems. Additionally, no violation of the fuel thermal limits occurs, since I the minimum DNBR remains above the 1.24 value throughout the duration of the event.
AnmewedDee> aseeuw- A*eanun Ane+nen reen rs.s-2r
System 80+ Design ControlDocument Voids form in the teactor vessel upper head region during the transient, due to the thermal-hydraulic ' decoupling of this region from the rest of the RCS. The upper head region liquid level remains above the top of the hot leg throughout the transient. 15.6.4 Radiological Consequences of Main Steam Line Failure Outside Containment (BWR) s The event of BWR steam system piping failures outside of containment does not apply to the System 80+ Standard Design and therefore, is not presented. 15.6.5 Loss-of-Coolant Accident 15.6.5.1 Identification of Event and Causes Regulatory Guide 1.4 describes a design basis Loss-of-Coolant Accident DBA (LOCA) as one of the hypothetical accidents used to evaluate the adequacy of various plant structures, systems, and components used to protect the public health and safety. Such an evaluation is required in Section 50.34 of 10 CFR 50 and is the subject of this analysis. LOCA analysis for the purpose of demonstrating the satisfactory performance of the Safety Injection System is given in Section 6.3.3 for a full spectrum of pipe break sizes. The analytical models and parameters used to determine the radiological doses are presented in Appendix 15A and the results are given below. In this analysis it is assumed that the Safety Injection System is ineffective in the initial phase of the accident resulting in a damaged core and a release of radionuclides from the reactor coolant system to the containment. The pipe break size being used in this analysis is a full double-ended rupture (DER) of one of the two hot legs. This is a very conservative assumption resulting in a release of gap activity and an onset of fuel damage much earlier than would be possible for a plant such as System 80+ which has been designed with leak-before-break (LBB) included as a design consideration. Both References 55 and 56 recognize this fact, and call for a small-to-medium LOCA (e.g., 6" equivalent diameter) to be used as the basis for performing this analysis on LBB-approved plants. Nevertheless, for the design basis analysis presented here the large break has been analyzed. In Section 15.6.5.5 a second analysis is presented which evaluates the likelihood of the Environmental Protection Agency (EPA) Protective Action Guidelines (PAGs) being exceeded by a LOCA which is similar to the one analyzed here as part of the design basis. In this second analysis the loss of the Safety injection System is assumed to be permanent (as explained in Section 15.6.5.4), resulting in a severe accident (reactor vessel failure), and the release of additional radionuclides to the containment atmosphere. This second analysis is chosen to represent a severe accident with a large release of radioactivity from the core to the containment an intact containment and the containment sprays operational. Unlike the DBA LOCA, however, the analysis of this event is intended to be closer to "best-estimate". 15.6.5.2 Sequence of Events and Systems Operation - DBA LOCA The sequence of events and systems operations are as follows: t =0 to t =30 see This is the power purge release phase. The power purge release consists of coolant activity assuming instantaneous and complete blowdown of reactor coolant at the Technical Specification coolant activity Approved Desbyn Material. Accident Anatneses Page 15.6-22
System 80+ Design ControlDocument O V augmented by a pre-accident iodine spike, and 16000 cfm through the power purge due to the elevated containment pressure. Although the power purge isolation actually requires 32 seconds to be completed (30 seconds to isolate following a two-second delay CIAS), it is assumed that the averare flowrate would not exceed the 16000 cfm for 30 seconds. Additionally, a LOOP is assumed to occur at t=0. Consequently, the Control Room is assumed to have no intake but to experience unfiltered inleakage due to loss of pressurization. Containment isolation functions are discussed in Sections 6.2.4. t = 30 see to t= 80 see This is the first part of the gap release phase during which containment sprays are not operating. According to Draft NUREG-1465, the gap release phase lasts 1800 seconds, with a start time of approximately 30 seconds for ABB-CE designs. It has been assumed that the start of the gap release and the end of the power purge are coincident at t=30 seconds. During this first part of the gap release the annulus building is above atmospheric pressure and is assumed to be bypassed. Additionally, power is restored to the Control Room ventilation at t =35 seconds after which time the Control Room air supply ) is assumed to be filtered. I 1 l t =80 see to t= 110 sec This is the second part of the gap release. The sprays are now operating. The spray system is described in Section 6.5. The annulus building continues to be bypassed. A (v) t = 110 see to t = 1000 sec This is the third part of the gap release. The sprays continue to operate, and the annulus building exhaust filters are now assumed to be effective with an exhaust flowrate of 16000 cfm. The annulus building bypass is now assumed to be correspondingly reduced to 10 percent of the containment leakage. It should be noted that the annulus building exhaust filter operation actually becomes effective at 104 sec; it is conservative to represent that time as 110 sec in this analysis. t = 1000 see to t = 1830 see This is the founh and concluding part of the gap release. The sprays continue to operate, and the annulus filters continue operating with a flowrate of 18000 cfm, but the exhaust is reduced to 1000 cfm with the balance recirculated to the manulus. The annulus building bypass fraction continues to be 10 percent of the containment leakage. This exhaust rate and bypass fraction will continue for the duration of the remainder of the analysis. However, the containment leakage is reduced by a factor of two at t = 86400 sec. t = 1830 see to t = 6630 see This is the fuel release phase. According to Reference 55, the fuel release phase occurs over the first 80 minutes following the gap release phase. The sprays continue to operate and will continue to operate for the remainder of the analysis, p The control room operators are expected to take control of the control room intakes to minimize the X/Q V by t=1800 sec. For conservatism it is assumed that the action is not taken until the beginning of this period. ApprovedDesign Afsterse! Accident Analyses Page 15.6-23
System 80+ Design ControlDocument t=6630 see to t=7230 see she radionuclide release to containment is now complete, and the assumed reflood and arresting of core damage has been partially completed; i.e., the Safety injection System is now assumed to be functional. The two-hour EAB dose is reported as of 7230 sec, two hours after the start of the gap release. t=72.30 see to t=7530 see The core reiicod and quench is now assumed to be complete. t =7530 see to t=86400 see The sprays continue to operate, the containment is assumed to continue to leak at the design leak rate of 0.5%/ day, and 10% of this leakage is assumed to continue to bypass the annulus. t = 86400 see to t =2592000 see The sprays continue to operate, the containment is assumed to continue to leak, but now at ene-half the design leak rate or 0.25%/ day, and 10% of his t leakage is assumed to continue to bypass the annulus. The 30-day LPZ dose is reported as of the end of this interval, and this interval concludes the analysis. 15.6.5.3 Analysis of Effects and Consequences - DBA LOCA A LOCA is defined as a hypothetical break in a pipe in the reactor coolant pressure boundary resulting in the loss of reactor coolant at a rate in excess of the capability of the coolant makeup system. Core damage and a release of a portion of the core's radioactive inventory to the containment building is assumed. A LOCA will, therefore, result in radiation doses in the control room and at various offsite locations due to radionuclide dispersal through the following paths: e Discharge of iodine spike activity initially present in the RCS coolant A pw ,n of this activity is assumed to pass into the containment atmosphere and then through the power purge valves to the outside atmosphere prior to valve closure. The magnitude of the initial RCS iodine spike activity is equal to 60 pCi/gm of I-131 (dose equivalent). The calculation of iodine spike activity within the containment building does not credit removal by either radioactive decay or operation of the sprays.
- Direct containment leakage and filtered discharge from the containment annulus ventilation system It is assumed that the containment leaks at the maximum rates allowed by the technical specification (as required by Regulatory Guide 1.4). These rates are equal to 0.5 vol %/ day for the first 24 hours and half of that rate thereafter. Initially, the containment leaks directly to the outside atmosphere. At approximately two minutes after the start of the LOCA the containment annulus ventilation system is fully operational and all subsequent leakage is into the annulus ventilation system with tiltered discharge to the outside atmosphere with exception of an assumed ten-percent bypass. -
Approvmf Design Material Accident Analyses Page 15.6-24
, System 80+ Desfgn Control Document l
- t Within the containment, the spray is credited for removal of non-organic iodine and other !
radionuclides in particulate form from the containment atmosphere. No credit is taken for spray l removal of organic iodine in the containment atmosphere. The effectiveness of the spray removal i , 'of iodine is based on recirculation of sump solution as described in Section 6.5. In Section 6.5 plots of calculated containment mixing rate and particulate spray lambda are presented as l functions of time out to 500 mirrates. Beyond 500 minutes the values are two per hour and 0.4 !
- per hour, respectively. These values are consistent with Reference 57. l e
{ 1 Discharge from the emergency safeguards features rooms i
. This consists of iodine, cesium, rubidium and tellurium activity which passes from the IRWST into the ESF rooms through leaks in the pump seals and valves. A portion of this leakage enters the ESF rooms atmosphere and is discharged to the outside atmosphere through filters. ;
The parameters used in evaluation of the radiological consequences of the DBA LOCA are presented in ! Table 15.6.5-2. The total doses to an individual offsite, following a LOCA, are given in Table 15.6.5-1. l The total doses to a control room operator are given in T>le 6.4-1. 1 15.6.5.4 Sequence of Events and Systems Operation - PAG Evaluation The LOCA used for the EPA PAG evaluation described in Section 15.6.5.1 is similar to the DBA LOCA j in the following ways: i I I e Same assumptions with respect to power purge release and isolation l e Same assumptions with respect to the gap release and early in-vessel release of radioactivity to ! the containment l. e Same assumptions with respect to containment leak rate, sources of containment leakage and containment mixing e Same assumptions with respect to annulus building exhaust filter operation and annulus building f bypass it differs from the DBA LOCA in the following ways: -l e The spray system is assumed to be operating at the time of the start of the gap release f i e At the end of the fuel release the reactor vessel is assumed to fail due to melt-through of the ; lower head, and the debris quench occurs ex-vessel rather than in-vessel leading to an ex-vessel _l and late in-vessel release of radioactivity to the containment ; There are several important differences in analytical inputs and assumptions which are discussed in the following section. These differences in analytical inputs and assumptions have greater significance to the
. EPA PAG comparison results than do the differences in event definition.
i l
.) Nr Anemoneeton aseewnnt. Aeoment Ane&een rope 15.s.25
System 80+ Design ControlDocument I 15.6.5.5 Analysis of Effects and Consequences - PAG Evaluation The important modeling differences between this analysis and that presented in Section 15.6.5.3 for the DBA LOCA are as follows:
- The release paths included in the PAG comparison case are not the same as those identified in Section 15.6.5.3. The power purge is a small contributor to offsite doses for the DBA LOCA as shown on Table 15.6.5-1 (6 % of the EAB thyroid dose and I % of the LPZ thyroid dose), and can be neglected. Similarly, the ESF room discharge is important over a period of several weeks, but in the shon term (the period of interest for comparison to the EPA PAGs) it is of little imponance (1% of the EAB thyroid dose) and can be neglected.
- This analysis includes the radionuclide release from the core debris ex-vessel and the contribution of the post-vessel failure revaporization of some radionuclides previously retained within the reactor coolant system. The specification for the release magnitude and timing of these releases is taken from Reference 55.
These releases were not addressed in Reference 56 since that report was directed toward improvement of the DBA LOCA release assumptions where such releases are not included. Also, that report was, in fact, a status report which has been since superseded by additional ARSAP work in several areas. As is the case for the gap release and the in-vessel low-volatile releases (which m part of the DBA LOCA releases), this further work by ARSAP has led to radionuclide release magnitudes being specified for the ex-vessel and revaporization releases that are lower than those of Reference 55. For conservatism in the case of the DBA LOCA analysis, the gap releases and the in-vessel low-volatile releases were taken from Reference 55. That conservatism has been extended into the PAG comparison calculation covered in this section, and to add to that conservatism, the ex-vessel and revaporization releases have also been taken from Reference 55. Use of these releases shou'.d not be taken to mean that they are viewed as being the most nearly correct for System 80+; that is not the case. Low-volatile releases, specifically, were commented on by the industry as part of comments solicited by the NRC on Reference 55. The low volatile releases developed by ARSAP and referred to in EPRI comments on Reference 55 are viewed as more nearly correct for System 80+, although they have conservatively not been used in this analysis.
- The spray removal coefficients and mixing rates are based on the Reference 56 report mentioned above. The mixing rate of 10 unsprayed volumes per hour for the first two hours of the release is approximately the same as the DBA LOCA values calculated specifically for System 80+ as shown on Figure 6.5-4. However, the spray lambdas, which have been taken from the ARSAP Licensing Design Basis Source Term Update report and adjusted for the difference in the effective spray droplet size (300 micron diameter in the report versus 1000 micron for System 80+) are significantly greater. These lambdas are compared on Figure 15.6.5-1. The principal reason for the greater lambdas used in the PAG comparison analysis is that these lambdas include the effects of hygroscopicity. The hygroscopicity of the CsOH released from the primary system into the saturated containment atmosphere increases the airborne particle size distribution and makes the sprays more effective.
O Approwd Design Materia! Accident Analyses Page 15.6-26
I Sv emm 80+ Design ControlDecanent l 4 : L I The PAG offsite dose calculation is done with the MACCS computer code (References 60,61, 62 and !
- 63) according to the following set of assumptions
; o The reported dose is the Committed Effective Dose Equivalent (CEDE) since this is the way in j j which the revised (October 1991) EPA PAGs are specified. l e A median dose is reported independent of direction. Since the event itself represents a worst-case !
severe accident (given an intact containment and sprays operating), the reporting of the median , dose, independent of direction, establishes that most severe accidents with an intact containment i and sprays operating will result in lower offsite doses. l ) e The meteorological data base is the same as that used to generate the X/Q values used for the f
; DBA LOCA analysis. !
e 50-year dose commitment is used. ! e The following values of "a" and "b" are used for the expression signg = ax 6- ! Stability a h i A 2.47E-4 2.118
. B 0.078 1.085 I i C 0.144 0.911 D 0.368 0.6764 E 0.2517 0.6720 F 0.184 0.6546 e The time base for plume meander is three minutes with a 24-hour release duration.
e The release is assumed to be a cold, ground level release. e Doses include a 24-hour exposure to ground contamination. 4 e Doses include shielding factors of 0.75 for plume exposure and 0.33 for ground exposure. o The breathing rate is 3.3 x 104m3/second with an inhalation protection factor of 0.4 o The dry deposition velocity is 1.0 cm/sec for iodine and 0.1 cm/see for other particulates. The results of this analysis are as follows: List Dose Result CEDE PAG 1 rem 0.33 rem Thyroid PAG 5 rem 2.7 rem t
- b)
- t. :
' Sw Dee@n neeeuw- Acement Andpeee rope rs.s.27 i , ? j .- . . . ' . - , , ,
System 80+ Design controlDocument 15.6.5.6 Conclusions The limiting criteria for offsite doses are given in 10 CFR 100. These are 25 rem to the whole body and 300 rem to thyroid. These apply to both the two-hour dose at the exclusion area boundary and to the thirty-day dose at the low population zone. Table 15.6.5-1 shows that the offsite doses are within the criteria limits. The limiting criteria for control room doses are given in Reference 58. Those limits are 5 rem gamma to the whole body,30 rem to the thyroid and 30 rem beta to the skin. These limits are met as discussed in Section 6.4. The EPA PAG limits are 1 rem CEDE and 5 rem to the thyroid. These limits are met as discussed in Section 15.6.5.5. Table 15.6.2-1 Alarms that will be actuated the DBLLOCUS Event l
- 1. U'down line low pressure alarm (downstream of the break)
- 2. Nuct .ar annex high radiation alarm
- 3. Nucles annex high temperature alarm
- 4. Nuclear annex high humidity alarm
- 5. Pressurizer low level alarm
- 6. Nuclear annex sump high level alarm >
- 7. Volume control tank low level alarm Table 15.6.2-2 Sequence of Events for a Double-Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve Time (sec) Event Setpoint or Value 0.0 letdown Line Rupture Occurs Setting Off Alarms Listed in -
Table 15.6.2-1 157 Full Output of Proponional Heaters Obtained, psia 2300 330 2275 Pressurizer Backup IIcaters Tutq On, psia 498 Pressurizer Backup Heaters Turned Off, psia 2300
> 660 Pressurizer Backup licaters Cycle On and Off, osia 2275/2300 1800 Minimum Pressurizer Pressure Prior to Manual Reactor Trip, 2276 psia 1800 Minimum Pressurizer Liquid level, ft 11.3 1800 Operator Isolates the letdown Line And Takes Steps For A -
Controlled Shutdown Of The Reactor Astroved Design Material- Accident Analyses Page 15.628
1 System 80+ Deslan controlDocument Table 15.6.2-3 Assumed Input Parameters and Initial Conditions for The Double-Ended Break of the Letdown Line Outside Containment Upstream of ~ the Letdown Line Control Valve Parameters Assumed Value Core Power level. MWt 3992 Core inlet Temperature, 'F 561 Pressurizer Pressure, psia 2325 Core Mass Flow,10'lbm/hr 152.2 ; Pressurizer Liquid Volume, ft 5 1400 Steam Generator Pressure, psia 1047 Doppler Coefficient Multiplier 0.85 CEA Worth at Trip,10r240 (most reactive CEA fully withdrawn) -8.86 Break Size (double-ended), ft: 0.01556 Moderator Temperature Coefficient, Ap/*F 0.0 Doppler Reactivity Feedback Function See Table 15.0-6 0 Radiological Consequences of a Double-Ended Break of the Letdown Table 15.6.2-4 Line Outside Containment Upstream of the Letdown Control Valve
~.
Location Doses From Primary System Release, rem Exclusion Area Boundary (0-2 hours) Thyroid 26.72 Whole-body 0.7 law Population Zone (0-8 hours) Thyroid 3.82 Whole-body 0.11 ANwesed Design nietariel Accident Arme&ses Page 15.6-29
System 80+ Design ControlDocument Table 15.6.3-1 Sequence of Events for the Steam Generator Tube Rupture Time (Sec) Event Setpoint or Value 0.0 Tube Rupture Occurs 0.4 High Steam Generator Level Trip Signal Generated 0.55 Trip Breakers Open 0.55 Turbine Trip: Stop Valves Start to Close 5.4 Main Steam Safety Valves Open, psia 1212 5.75 Main Steam and Feedwater Isolation Valves Closed 8.77 Maximum Steam Generator Pressure, psia 1273 16.5 Backup Heaters Energized, psia 2325 623 Pressurizer IIcaters Deenergize due to low Pressurizer Liquid 297 Volume, ft' 1800 Operator Isolates the Damaged Steam Generator and Initiates Plant Cooldown at 100*F/hr for the 1.5 hour time period 28,800 Shutdown Cooling Entry Conditions are Assumed to be reached; 330/350 l RCS Pressure, psia / RCS Temperature, 'F O Table 15.6.3-2 Assumptions and Initial Conditions for the Steam Generator Tube Rupture Parameters Assumed Value Core Power level, MWt 3876 Core Inlet Coolant Temperature 'F 563 Pressurizer Pressure, psia 2375 Core Mass Flow Rate,106 lbm/hr 151.9 One Pm Integrated Radial Peaking Factor, with Uncertam7 1.46 Steam Generator Pressure, psia 1057 Moderator Temperature Coefficient,10d Ap/*F 0.0 Doppler Coefficient Multiplier 1.0 CEA Wonh at Trip, % Ap (most reactive CEA fully withdrawm) -8.86 Doppler Reactivity Function See Table 15.0-6 O Approved Desips Meterial- Accident Anotyses (2/951 Pope 15.6-30
Sy tem 80+ Design ControlDocument O Table 15.6.3-3 Steam Generator Tube Rupture Radiological Consequences ; L) Thyroid Inhalation Doses ti Offsite Dosest21 (rem) Location GIS PIS
- 1. Exclusion Area Boundary; 0-2 hr, Thyroid 7.05 27.6
- 2. Low Population Zone, Outer Boundary; 0-8 hr, Thyroid 3.25 4.48 Whole-Body DosesIll Offsite Dosest21 (rem)
Location GIS PIS
- 1. Exclusion Area Boundary; 0-2 hr, Whole-Body 0.07 0.09
- 2. Low Population Zone, Outer Boundary; 0-8 hr, Whole-Body 0.015 0.016 O
fil Radiological consequences were determined for a core power of 3992 MWt by increasing the steam O , N_.) releases for the 3876 MWt core power case by 3% 121 GIS - Generated lodine Spike PIS - Pre-accident Iodine Spike ANuovent Des # aenterW Accieient Ane&see Pope 15.6-31
System 80+ ossign controlDocument Table 15.6.3-4 Sequence of Events for a Steam Generator Tube Rupture with a Lost of Offsite Power Time (See) Event Setpoint or Value 0.0 Tube Rupture Occurs - 0.4 liigh Steam Generator level Trip Signal Generated - 0.55 Trip Breakers Open - 0.55 Turbine Trip: Stop Valves Start to Close - 3.55 Loss of Offsite Power - 5.4 Main Steam Safety Valves Open, psia 1212 5.75 Main Steam and Feedwater Isolation Valves Closed - 9.0 Maximum Steam Generator Pressure, psia 1275 1090.4 Pressurizer Emptics - 1467 Intact Steam Generator Water level Reaches Emergency 19.9 Feedwater Actuation Signal Analysis Setpoint, percent of wide range 1415.8 Pressurizer Pressure Reaches Safety Injection Actuation Signal 1555 Analysis Setpoint, psia 1455.8 Safety injection Flow initiated -- 1527 Emergency Feedwater Flow Begins to intact SG -- 1710 Pressurizer Begins to Refill - 1800 Operator Isolates the Damaged Steam Generator and Initiates - Plant Cooldown 28,800 Shutdown Cooling Entry Conditions are Assumed to be Reached, 330/350 RCS Pressure, psia / Temperature 'F O AppnevedDesign Morenal AccMent Analyses Page 15.6-32
System 80+ Design ControlDecanent e Table 15.6.3 Assumptions and Initial Conditions for the Steam Generator Tube < Rupture with a Loss of Offsite Power 3 4 Parameter Assumed Value [ Core Power Level, MWt 3876 4 Core Inlet Coolant Temperature, 'F 563 Pressurizer Pressure, psia 2375 Core Mass Flow Rate,10' lbm/hr 151.9 One Pin Integrated Radial Peaking Factor, with Uncertamty 1.46 Steam Generator Pressure, psia 1057 d 0.0 Moderator Temperature Coefficient,10 4/'F l Doppler Coefficient Multiplier 1.0 CEA Worth at Trip, % b (most reactive CEA fully withdrawn) -8.86 Doppler Reactivity Feedback Function - See Table 15.0-6 i Table 15.6.3-6 Radiological Cm==quences of the Steam Generator Tube Rupture with a Loss of Offsite Power Thyroid Inhal=*1aa Doses t3 "# Offsite Doses8 'l (rem) l Location GIS PIS j
- 1. Exclusion Area Boundary; 0-2 hr, Thyroid 9.53 38.6
- 2. Low Population Zone: 0-8 hr, 'Ihyroid 4.23 5.98 l l l Whole-Body Dosest 'l Offsite Doses" (rem) ,
! IAcation GIS PIS I 1. Exclusion Area Boundary; 0-2 hr, Whole-Body 0.112 0.143 4- 2. Low Population Zone: 0-8 hr Whole-Body 0.019 0.02 l l tu Radiological releases were determmed for a core power of 3992 MWt by increasing the steam releases for
. the 3876 MWt core power case by 3%
. 123 GIS - Generated Iodine Spike ,
PIS - Pre-accident Iodine Spike Annmenoenn aneeenw. Asement Amenen 12/ssi rare 1s.s-22 3
.ar.-r-
System 80+ Design ControlDocument Table 15.6.3-7 Sequence of Events for a Steam Generator Tube Rupture with a Loss of Offsite Power and Stuck Open ADV Time Event Setpoint or Value 0.0 Tube Rupture Occurs - 194.3 Backup Heaters Energized, psia 2325 1450 Pressurizer Heaters De-energized due to Low Pressurizer Liquid 297 Volume, ft' 1756.97 High Steam Generator level Condition, % Narrow Range 95 1757.97 High Steam Generator Level Trip Signal Generated - 1758.12 Trip Breakers Open - 1758.12 Turbine Generator Trip - 1761.12 less of Offsite Power - 1762 LH Main Steam Safety Valves open, psia 1212 1762 RH Main Steam Safety Valves open, psia 1212 1764.88 Maximum Steam Generator Pressures Both Steam Generator, psia 1272 1783.16 Pressurizer Empties - 1783.68 Steam Generator Water level Reaches Emergency Feedwater 26.9 Actuation Signal (EFAS) Analysis Setpoint in the Unaffected Generator, % wide range 1843.68 Emergency Feedwater Initiated to Unaffected Steam Generator -- 1849.26 Main Steam Safety Valves Closed, psia 1151.4 2178 Operator Initiates Plant Cooldown by Opening One ADV on each - SG 2179 Operator initiates Safety injection Flow -- 1 3663 Operator Attemots to Isolate the Damaged Generator, RCS 550 Temperature, 'F 5463 Operator Closes the ADV Block Valve - 5583 Operator Opens Pressurizer Gas Vent -
#00 Operator Closes Pressurizer Gas Vent and Controls Backup 20 )
Aessurizer Heater Output, and SI Flow to Reduce RCS Pressure and Contrcl Subcooling, 'F l 28,800 Shutdown Cooling Entry Conditions Reached; RCS Pressure, psia / 330/350 Temperature. *F O I Attwend Desips Meteriel- Accident Analyses (2/95) Page 15.6-34
)
System 80+ Design ControlDocumart (n") Table 15.6.3-8 Assumptions with Initial Conditions for the Steam Generator Tube Rupture with a Loss of Offsite Power and Stuck Open ADV Parameter Assumed Value Core Power level, MWt 3876 Core Inlet Coolant Temperature, 'F 563 Pressurizer Pressure, psia 2375 Core Mass Flow Rate,10' lbm/hr 151.9 One Pin Integrated Radial Peaking Factor, with Uncertainty 1.46 Steam Generator Pressure, psia 1057 Moderator Temperature Coefficient,1&' Ap/*F 0.0 Doppler Coefficient Multiplier 1.0 CEA Worth at Trip, % Ap (most reactive CEA fully withdrawn) -8.86 Doppler Reactivity Feedback Function See Table 15.0-6 Table 15.6.3-9 Radiological Consequences of the Steam Generator Tube Rupture with a Loss of Offsite Power and Stuck Open ADV Thyroid Inhalation Dosesul Offsite DosesA (rem) Location GIS PIS
- 1. Exclusion Area Boundary; 0-2 hr Thyroid 62.4 93.1
- 2. Iow Population Zone, Outer Boundary; 0-8 br, Thyroid 47.9 30.9 Whole-Body DosesN Offsite Dem (re m) location GIS PIS
- 1. Exclusion Area Boundary; 0.2 hr, Whole-Body 7.42 7.5
- 2. Imw Population Zone, Outer Boundary; 0-8 hr, Whole-Body 1.082 1.061 N Radiological consequences were determined for a core power of 3992 MWt by increasing the steam releases for the 3876 MWt core power case by 3%
C A GIS - Event Generated Iodine Spike PIS - Pre-Accident Iodine Spike Anwed Deafpn atenwW- AccMent Andt ru rege 15.6 35
System 80+ Design ControlDocument Table 15.6.5-1 Offsite Doses Resulting from a LOCA h lecation & Paths Thyroid Dose Whole-Bo@ Dose (rem) (reus l Exclusion Area Boundary (EAB) (2-hour doses)
- 1. Power Purge 11.2 0.02
- 2. Containment Leakage and Annulus Ventilation 158.0 2.57 System Discharge
- 3. ESF Rooms Discharge 2.5 0.04 TOTAL 171.7 2.63 1.aw Population Zone (LPZ) (30 day doses)
- 1. Power Purge 1.5 0.003
- 2. Containment leakage and Annulus Ventilation 85.6 6.91 System Discharge
- 3. ESF Rooms Discharge 46.7 2.00 TOTAL 133.8 8.91 O
F O AmwoM oesten Merwint . Accuent Ane&ses gy g,yg, p,,, yg gge
f System 80+ onian controlcocument Table 15.6.5-2 Parameters used in Evaluating the Radiological Consequences of a l Loss of Coolant Accident (LOCA) Parameter Value
- 1. Core Data Power level, MWt 3992 Core Average Burnup, MWD /MTU 28,000 2 Accident Releases The radioactivity released following a LOCA are from the following sources:
- Blowdown of primary coolant .
- 100% of the gap activity
- Fraction of the Core Activity due to melted fuel Blowdown of Primary Coolant Primary Coolant Technical Specification Concentrations Table 15 A-4 Primary coolant activity with a Pre Accident lodine Spike Table 15A-6 Duration of RCS blowdown via break, secs 20 Normal Primary coolant mass, Ibm 630,198 RCS Flash Fraction, % 54 Power Purge Rate, cfm 16000 Purge Duration, secs 30 Credit taken for Containment low purge filter No O() Chemical species of the iodines in RCS (i.e. a I-spike release) elemental Gap Release Gap activity released (based on 5% of the core Noble Gases, lodines, Cs & Rb) Table 15A 3 i l
Chemical species of iodines in the gap, %
- - Inorganic elemental 4.75 particulate 95
- Organic 0.25 Duration of gap release, secs 1800 release starts, secs 30 release ends, secs 1830
^ ,. ..; Dennyn atesernial. Acensent A@en Pope 15.6-37
System 80+ Design ControlDocument Table 15.6.5-2 Parameters used in Evaluating the Radiological Consequences of a , Loss of Coolant Accident (LOCA) (Cont'd.) Parameter Value Fuel Release Core Inventory Table 15A-1 Fraction of the core released for the 9 groups discussed in Section 15.6.5 Group 1 (Noble Gases) 0.95 Group 2 (Iodines) 0.35 Group 3 (Cesiums, etc) 0.25 Group 4 (Tc!!uriums, etc) 0.15 Group 5 (Strontiums, etc) 0.03 Group 6 (Ruthenium, etc) 0.008 Group 7 (Lanthanum, etc) 0.002 Group 8 (Cerium, etc) 0.01 Group 9 (Barium) 0.04 Chemical species of iodines in the fuel release
- Inorganic elemental 4.75 particulate 95
- Organic 0.25 Duration of fuel release, hrs 1.3 release starts, secs 1830 release ends, secs 6630
- 3. Containment Parameters Minimum containment Free Volume, cu ft 3.34 E + 6 Containment Leak Rate, % vol/ day
- 0-24 hrs 0.5 1-30 days 0.25 Duration of containment leakage, days 30 Containment spray effective stan time, secs 80 Unsprayed region, % vol 0.18 Sprayed region, % vol 0.82 Spray removal Lamda (applicable to all isotopes in particulate form as well as elemental iodines), per hr 80-110 secs 1.4 110-600 secs 1.4 600-1000 secs 1.4 1000-1830 secs 1.7 18304230 secs 10.3 4230-6630 secs 13.2 6630-7230 secs 5.9 7230-7530 secs 3.9 7530-9930 secs 2.9 9930-28800 secs 0.9
> 28800 secs 0.4 Natural deposition lambda applicable to all isotopes in particulate form as wc!! as elemental iodines for the entire duration of the accident, 0.15 per hr Approved Deslyn Material AccMent Analyses Page 15.6-38
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- 4. Containment Annulus Ventilation System Parameters:
Initiation Signal CSAS Initiation time / operation Fig. 6.2.1-39 Time after which credit is taken for Annulus Ventilation System operation, secs 110 Total Ventilation flow, cfm 18000 Exhaust flow rate vs time, cfm Fig. 6.2.1-39
- 108 secs to 1000 secs 16000
- 1000 secs to 30 days 1000 Recirculation flowrate, cfm 18000 - exhaust flowrate Minimum Annulus Bldg. volume, cu ft 617,000 Percentage credit taken for mixing in the annulus volume, % 50 Annulus Building exhaust / recirculation filter Efficiency
- Elemental 0
- Organic 0
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- 5. ESF System Parameters Total Sump Water Volume is made of the following sources:
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- Minimum water volume in 4 SI Tanks, cu ft/ tank 1600 l
- Primary Coolant mass inventory, Ibm Liquid 664,328 Steam 7662 Sump water temperature, 'F 212 Percentage of iodines that evolve out of the ESF leakage and is available for release, % 10 ESF leak Rate (includes factor of 2), cu ft/sec 0.2572E-03 ESF leak initiation time, secs - 75 ESF ventilation Exhaust Filter efficiency, %
Particulate 99 Elemental 0 Organic 0
- 6. Atmo,tpheric Dispersion Data Table 2.3-1
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System 80,'- Desian controlDocument (n 15.7 Radioactive Material Release from a Subsystem or Component 15..1 Radioactive Gas Waste System Failure This section of the Standard Review Plan has been deleted (Reference 26 of Section 15.0). 15.7.2 Radioactive Liquid Waste System Leak or Failme This section of the Standard Review Plan has been deleted (Reference 26 of Section 15.0). 15.7.3 Postulated Radioactive Releases due to Liquid-Containing Tank Failures 15.7.3.1 Identification of Event and Causes The most limiting radioactive tank failure is the uncontrolled release of liquid from the Boric Acid Storage Tank (BAST). The BAST is part of the Chemical and Volume Control System (CVCS) described in Section 9.3.4. The BAST is an ASME III Class 3, Seismic Category I tank. A failure resulting from a seismic event which instantaneously releases 80% of its contents is postulated. t The BAST is located in the yard. A seismically designed dike, constmeted in accordance with Regulatory Guide 1.!43, contains the contents of a tank failure resulting from a seismic event. In compliance with the Standard Review Plan Section (SRP) 15.7.3, no credit is taken for the dike because it is not lined with Q stainless steel. It is assumed that if there were a seismic event, the basin within the diked area would ; develop cracks through which the liquid from the failed tank could be released to the plant discharge and eventually to the nearest potable water supply. Gaseous releases are considered in Section 11.3 as part , of routine releases. Since these tanks are vented during normal operation, no buildup of gases in these ! tanks is expected. Therefore, only the consequences of a liquid release will be considered in this section. 15.7.3.2 Sequence of Events and Systems Operation i The event is characterized by a rapid release of the BAST contents to the enviromnent. A seismic event causes the failure of the BAST and the release of its contents into the seismic basin surrounding the tank. The liquid migrates through the cracks in the basin to the plant discharge where it is diluted prior to reaching the potable water source. 15.7.3.3 Analysis of Effects and Consequences j
- Mathematical Model In lieu of su cecific parameters, such as potable water dilution factors, the maximum allowable value of a dilution factor is calculated based on normal system operation. The dilution factor reflects the minimum extent to which the radioactive liquid released from the failed BAST will be diluted prior to reaching the potable water supply.
O V To calculate the maximum dilution factor (i.e., ncinimum dilution of released liquid), the following equation was utilized: ANwo5t. 4eekn Menenin!. AccMant Analyser Page 15.7-1 l
System 80+ Design CortvelDocument C,(i) = Cp(i)/Dg
=
EC(i)/Df where: C,(i) = Concentration of the i-th isotope in the tank (pCi/ml) Cp(i) = Concentration of the i-th isotope at the nearest potable water supply ( Ci/ml) EC(i) = Effluent Concentration of the i-th isotope (pCi/ml) Dr
= Dilution factor
= 3 (1/ Dilution Volume)(1/ft ) 0.80 V,(gal) 3 Conver:; ion Factor (ft / gal)
V, = Volume of liquid initially in the tank (gal) The concentration in the liquid flowing into the Boric Acid Concentrator from the Holdup Tank is calculated by utilizing the following equations: CWi) = C,(i)/[DF(i) i DF2 (i) - .DF(i)]j where: Car (i)
= Concentration of the i-th isotope in the holdup tank (pCi/ml)
C,(i) = Concentration of the i th isotope in the composite flow stream (pCi/ml) as a function of PCC DF(i) j = DF of the j-th component in the purification process for the i-th isotope C, is calculated as follows: J J C, = E(F) x C3 )/E(F) j 1 I where: Fj = Flow Rate of the j-th flow stream (gpm) C3 = Concentration of the i-th isotope in the j-th flow stream (pCi/ml) The concentration of the fluid in the BAST after the influent fluid from the holdup tank is concentrated is calculated as follows: Cusr(i) = CF(i) x Cnr(i)/DF(i) ApprovedDesign ntaterial Accident Analyses Pope 15.7 2
\
l System 80+ Deslan coneet Documarr i s-i ') where: i Candi) = Concentration of the i-th isotope in the BAST ( Ci/ml) !
= Concentrating Factor between the bottoms and the distillate processed in j CF(i) the Boric Acid Concentrator (BAC) l
= 1.00E+04 (See Section 9.3.4) f Cgfi) = Concentration of the i-th isotope in the Holdup Tank ( Ci/ml) l
. DF(i) = Decontamination Factor for i-th isotope. All isotopes are considered to j be non-volatile; therefore, the DF for the non-volatile isotopes is used.' l The concentration of each isotope in the BAST is shown in Table 15.7.3-1. Then, the maximum - allowable dilution factor (Dr) is calculated. To verify that this is the maximum dilution factor, the calculated concentration for each isotope at the nearest potable water source using the dilution j factor is ratioed to the EC(i) and summed This process is repeated with additional values of dilution factor until the summation of the fractions, FEC(i), is less than or equal to 1. j i
*- Input Parameters and Initial Conditions l
- 1. The concentration at the nearest potable water supply is equal to the Effluent f Concentration (EC(i)) for each isotope.- :
The concentration in the BAST is calculated for the batch processing mode of operation ; 2. described in Section 9.3.4 and shown in Figure 9.3.4-1. l 1
- 3. Credit is taken for dilution by only the main flow path from the letdown through the ;
purification process in the CVCS to the recycle evaporator. The concentrate is sent to j the BAST.
- 4. The concentration of the flow streams are specified as a fraction of the Prunary Coolant j Concentration (PCC). The PCC is obtained from the output of the computer code !
DAMSAM for 1% failed fuel fraction (See Section 11.1). 1
- 5. No additional credit is taken for radioactive decay during the purification process or ;
during the transport of the liquid effluent to the nearest potable water source. . i
- 6. The Decontamination Factors (DF i) for the i-th isotope for each component were obtained )
from NUREG-0017 and Section 9.3.4. l
- 7. System parameters such as flow rates and tank volumes were obtained from Section 9.3.4. l
- 8. 80% of the volume is assumed to be released per SRP Section 15.7.3.
A
! 9. For conservatism, all radionuclides are assumed to be in the insoluble form.
Annreweet Den @n neeenriet. Aeonnent Anekeen rege rs.7 2 .l l
1 l Syntem 80+ oesign controlDocument e Results The results of the iterative process are shown in Table 15.7.3-2. The maximum allowable l dilution factor was determined to be 2.55 x IP. 15.7.3.4 Conclusions , I This analysis assumes a catastrophic failure of the BAST. Although the BAST is a Seismic Category I ] ASME II." Class 3 tank equipped with an overflow line, this analysis is considered to envelope any j potential failure of a radioactive liquid containing tank located outdoors. ; ((The results of this analysis should be used to establish site acceptance criteria for the minimum dilution flow required to limit the concentration at the nearest potable water source to less than 10 CFR Part 20, Appendix B of Sections 20.1001 - 20.2402, Table 2, Column 2 limits.))3 This analysis is based on the once through purification of the letdown flow and liquid from the Equipment Drain Tank and Reactor Drain Tank. Also, average values for the concentration of the distillate and concentrate are assumed to determine the concentration factor in the Boric Acid Concentrator (BAC). The concentration of the , influent stream to the BAC must be sampled to verify the concentration factor used is valid. 15.7.4 FuelIIandling Accident 15.7.4.1 Identification of Event and Causes The Fuel liandling Accident that is considered resulted from the dropping of a single fuel assembly during fuel handling. Interlocks and procedural and administrative controls involved in fuel handling are described in Section 9.1.4. 15.7.4.2 Systems Operation The transport of heavy loads in the containment building and the spent fuel building is controlled by restrictions placed on plant layout and equipment design. Features are s lected to ensure that heavy loads are restricted to preassigned travel zones and that they are not carried over stored fuel assemblies. Equipment interlocks and procedures are also used to ensure that load transport is accomplished in a predictable manner. Containment and fuel building systems required to mitigate the consequences of the Fuel Ifandling Accident are described in Chapters 6 and 9. Restrictions on the cask handling crane are listed in Section 15.7.5.2. 15.7.4.3 Analysis of Effects and Consequences e Mathematical Model If a dropped assembly were damaged to the extent that one or more fuel rods were broken, the accumulated fission gases and iodines in the fuel rod gaps would be released to the surrounding water. Release of the solid fission products in the fuel would be negligible because of the low fuel temperature during refueling. The methods of Regulatory Guide 1.25 were used to quantify O I COL information item; see DCD Introduction section 3.2. Approved Design Atatorial- Accident Analyses Page 15.7-4
1 System 80+ Design ControlDocument
~T the fission product releases to the containment and fuel building. The calculational methods and
[V assumptions described in Regulatory Guide 1.25 and modified by Draft NUREG 1465 for the gap activity apply smce. 1
- 1. the values for maximum fuel rod pressurization, i
- 2. the peak linear power density for the highest power assembly discharge, and i
- 3. the maximum center;ine operating fuel temperature for the assembly in item (2) above j are less than the corresponding values in Regulatory Guide 1.25. The fission product release fractions were obtained from Draft NUREG 1465. The calculation assumes an assembly with an average burnup of 28,000 MWD /MTU.
The methodology used to calculate offsite doses resulting from fuel failures is provided in Appendix 15A. The methodology used to determine the number of potential fuel failures is described below. The fuel assemblies are stored within the spent fuel rack at the bottom of the spent fuel pool. The top of the rack extends above the tops of the stored fuel assemblies. A dropped fuel assembly could not strike more than one fuel assembly in the storage rack. Impact could occur only 4 between the ends of the involved fuel assemblies, the lower end fitting of the dropped fuel assembly impacting against the upper end fitting of the stored fuel assembly. Analytical methods used to calculate the impact velocity and the resulting inpact stress in the fuel rod cladding for h3 O
) the vertical drop are described below.
The analysis of the fuel assembly vertical drop employed a summation of the forces acting on the fuel assembly in the vertical direction to determine the equation of motion of the fuel assembly. The resulting equation of motion is given below: ; F. = M a = Fo + F3- Fw where: M = mass of a fuel assembly a = acceleration Fo = drag force of a fuel assembly (i.e., (Drag Coefficient) - (velocity)2j Fa
= buoyant force of a fuel assembly Fw = weight (dry) of a fuel assembly e
The analysis assumed the fuel assembly drop distance was sutticient for the fuel assembly to
. reach its terminal velocity (acceleration equals zero in the above equation), thus making the results conservative or applicable for any drop height. For this worst case, the terminal velocity, O and therefore the assumed impact velocity of the fuel assembly, is 254.4 inches per second, and Q the resulting stress in the fuel rod cladding is 24,000 psi.
Amrovent Design Motorial- Accialent Anotyses page 15.7 5
Sy~ tem 80+ Design ControlDocument The equation employed in calculating the above impact stress in the fuel rod clad is as follows: a = VEp i where: og = impact stress V = impact velocity E = modulus of elasticity p = mass density The yield stress of the fuel rod cladding is 49,000 psi. This is the minimum yield stress value for unirradiated Zircaloy-4 and is conservative for irradiated fuel. Thus, for the fuel assembly vertical drop, the impact stresses which result from absorbing the kinetic energy of the drop are below the yield stress of the clad and no fuel rod failures will occur. Horizontal impact of a fuel assembly could result from a dropped fuel assembly falling in the horizontal position, or from a vertical fuel assembly rotating to the horizontal position. As in the vertical drop described above, worst case assumptions are made for the horizontal impact velocity (based on the terminal velocity) and the rotational impact velocity (based on an initial angular velocity of 5 radians per second). The worst case is the horizontal drop, since the kinetic energy at impact is greater for the horizontal drop than for the rotational impact (3629 ft-lbs versus 2375 ft-lbs, respectively). During this horizontal drop, it is postulated that the assembly strikes a protruding structure. For this analysis, a localized loading of one grid span has been assumed. An analysis of the fuel assembly drop has revealed that the most severe impact location is between the top two spacer grids since that impact area is within the fuel rod upper plenum region and the fuel pellets do not provide support for the cladding. To obtain an estimate of the number of fuel rods which might fail, the fuel assembly's grid span was modeled and calculations performed to relate the assembly's kinetic energy at impact to the resulting strain energy in the fuel rods and guide tubes.
- Input Parameters and Initial Conditions The analysis is performed for two cases; a fuel handling accident (FHA) occurring in the containment and a FHA occurring in the fuel building. Assumptions and parameters used in evaluating the fuel handling accident are listed in Table 15.7.4-1. Input data for the drop analysis that described material properties and pool conditions were kept consistent with the circumstances of the event (i.e., irradiated fuel assembly material properties, water, and fuel rod cladding temperatures corresponding to spent fuel pool conditions).
The determination of the iodine activity released to the environment from the containment atn osphere credited the operation of the containment purge ventilation system and associated O Alvwond Design Material- Accident Analyses (11/96) Page 15.7-6
System 80+ - Densors cetrat Document i
~ filters (Section 9.4.5). Similarly, the iodine released to the environment from the fuel building
. atmosphere credited the operation of the fuel building ventilation system and associated filters (Section 9.4.2). For the noble gases, no credit for filtration is assumed in the determination of releases from the containment or the fuel building. ;
i
- Results As a result of the fuel assanbly horizontal drop, no more than four rows of fuel rods (60 rods) would fail due to the strain resulting from the fuel rods and guide tubes absorbing the bundle's i kinetic energy at impact. Fuel rod cladding failure was assumed to occur if the maximum clad [
strain reached the ultimate strain of irradir.:ed Zircaloy. The use of irradiated fuel rod properties is conservative because of the greater energy absorbing capability of unirradiated Zircaloy. As described in the above presentation, the failure of all 236 fuel rods in one spent fuel assembly ! is not credible. However, the evaluation of the failure of all fuel rods in a fuel assembly (236 , fuel rods) has been performed to demonstrate consistency with the recommendations of Regulatory Guide 1.13. The radioactive inventory is obtained by multiplying the activity of the ! most radioactive fuel rod 72 hours after shutdown by a factor of 236. The total body gamma dose due to immersion and the thyroid dose due to inhalation were , calculated for 0 to 2 hours at the EAB and for 0 to 8 hours at the LPZ outer boundary using the l analysis assumptions contained in Table 15.7.4-1. The doses listed in Table 15.7.4-2 are ; applicable to the fuel handling accident occurring either in the containment or the fuel building and are well within the guidelines of 10 CFR 100. The control room doses are provided in O Section 6.4.3. 15.7.4.4- Conclusions The potential radiological consequences of a postulated fuel handling accident have been conservatively analyzed, using assumptions and inodels described in the preceding subsections. The calculated doses are well within the guidelines of 10 CFR 100. 15.7.5 Spend Fuel Cask Drop Accidents 15.7.5.1 Identificathan of Event and Causes A spent fuel cask handling accident must be evaluated if the spent fuel cask can be dropped from a height
- exceeding 30 feet onto a hard unyielding surface, or if it can be dropped or tipped onto stored irradiated fuel.
15.7.5.2 Systems Operation ] The fuel handling system and plant layout have been designet. to meet the following criteria: 1
- All spent fuel cask lifts from the cask transporter to the cask laydown area have been limited to !
less than 30 feet. )
*- The spent fuel cask handling crane operating procedures establish the requirements for operator
\ training, crane inspections; and approved cask handling procedures.
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System 80+ Design control Document
- The cask handlu, crane is provided with mechanical stops and electrical interlocks to prevent its movement near the spent fuel pool after the pool contains irradiated fuel.
- The spent fuel building is arranged so that the spent fuel cask does not pass over critical components during passage from the cask transporter to the cask laydown area.
- The relevant requirements of GDCs 2,4,5,61 and References 37 through 44 of Section 15.0 have been considered.
15.7.5.3 Analysis of Effects and Consequences Radiological evaluations for a cask handling accident are not required, since plant design features and cask handling procedures meet all applicable criteria. O I
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System 80+ oesign controlDocument
/-
. . Table 15.7.3-l' Concentration of Isotopes in BAST Isotope (i) Primary Coolant Concentration in BAST Concentration in BAST Concentration (pCilgm) (pCi/ml) (pCi/ml)
Na-24 5.08E-02 3.60E-01 PCC 1.83E-02 P-32 0.00E+00 3.60E-01 PCC 0.00E+00 Cr-51 3.67E-03 3.60E-01 PCC 1.32E-03 Mn-54 1.90E 03 3.60E-01 PCC 6.84E-04 Fe-55 1.43E-03 3.60E-01 PCC 5.15E41 Fe-59 3.56E-04 3.60E-01 PCC 1.28E 04 Co-58 5.46E-03 3.60E-01 PCC 1.97E-03 Co-60 6.30E-04 3.60E-01 PCC 2.27E-04 Ni-63 0.00E+ 00 3.60E-01 PCC 0.00E+00 __ Zn-65 6.06E-04 3.60E-01 PCC 2.18E-04 W-187 2.77E-03 3.60E-01 PCC 9.97E-04 Np-239 2.52E-03 3.60E-01 PCC 9.07E-04 Sr-89 4.91E-04 3.60E-01 PCC 1.77E-04 Sr-90 1.71E-05 3.60E-01 PCC 6.17E 06 Y-91 7.03E-05 3.60E-01 PCC 2.53E-05 ! Y-93 1.74E-05 3.60E-01 PCC 6.26E-06 Zr-95 7.66E-05 3.60E-01 PCC 2.76E-05 i Nb-95 7.59E-05 3.60E-01 PCC 2.73E-05 Mo-99 4.23E-02 3.60E-01 PCC 1.52E-02 Tc-99m 2.44E-02 3.60E-01 PCC 8.78E-03 Ru-103 2.61E-05 3.60E-01 PCC 9.41E-06 Ru-106 9.55E-06 3.60E-01 PCC 3.44E-06 Rh-103m 0.00E+00 3.60E-01 PCC 0.00E+00 Rh-106 0.00E +00 3.60E-01 PCC 0.00E+00 Ag-110m 0.00E+00 3.60E-01 PCC 0.00E+00 Ag-110 0.00E+00 3.60E-01 PCC 0.00E+00 Te-129m 8.94E 04 3.60E-01 PCC 3.22E-04 Te-129 9.51E44 3.60E-01 PCC 3.42E-04 Te-131m 4.23E-03 3.60E-01 PCC 1.52E-03 Te-131 1.65E-03 3.60E-01 PCC 5.94E-04 Te 132 2.94E-02 3.60E-01 PCC 1.06E-02 1-131 3.70E-01 3.51E-01 PCC 1.30E-01 1-132 1.00E-01 3.51E-01 PCC 3.52E-02 7'T I133 5.31E-01 3.51E-01 PCC 1.87E-01 : 'd-
~demd A Deelen wwM- Accidmt Analyses Page 15.7-9
=
i System BG + Design ControlDocument Table 15.7.3-1 Concentration of Isotopes la BAST (Cont'd.) g Isotope (i) Primary Coolant Concentration in BAST Concentration in BAST Concentration ( Ci/gm) (pCi/ml) (pCi/ml) 1-134 2.93E-01 3.51E-01 PCC 1.01E-01 1-135 2.99E-01 3.51E-01 PCC 1.05E-01 Cs-134 2.60E-02 3.00E+00 PCC 7.80E-02 Cs-136 7.05E-03 3.00E+00 PCC 2.12E-02 Cs-137 4.58E-02 3.00E+00 PCC 1.37E-01 Ba-137m 4.31E-02 3.60E-01 PCC 1.55E-02 Ba-140 6.00E-04 3.60E-01 PCC 2.16E-04 La 140 2.03E44 3.60E-01 PCC 7.29E-05 Ce-141 2.25E-05 3.60E-01 PCC 8.10E-06 Ce-143 6.29E-05 3.60E-01 PCC 2.26E-05 Cc-144 5.74E-05 3.60E-01 PCC 2.07E-05 Pr-143 8.08E-05 3.60E-01 PCC 2.91E-05 Pr 144 5.71E-05 3.60E-01 PCC 2.06E-05 11-3 1.00E +00 8.50E-01 PCC 8.50E-01 O O Apprend Des &n Material Accident Analyses Page 15.710
--.---. . .. - -. . - . . . . . - - - . - - . - . - . . - . - - ~ . . . - . - . . ~
Sviterst 80+ Deslan contrat Document Table 15.7.3-2 Results of Iterative Process to Determine Dilution Factor Dr = 2.55E-06 Isotope (i) EC(i) (pCi/ml) Conc.in BAST Conc. at Petable Fraction of EC(i) (pCi/ml) Water (pCi/ml) PEC(i) Na-24 5.00E-05 1.83E-02 4.67E-08 9.33E-04 i P-32 9.00E-06 0.00E+00 0.00E+00 0.00E+00 ; Cr-51 5.00E-04 1.32E-03 3.37EU9 6.74E-06 Mn-54 3.00E-05 6.84E-04 1.75E-09 5.82E-05 Fe-55 1.00E-04 5.15E-04 1.31E-09 1.31E-05
; 3.27E-05 Fe-59 1.00E-05 1.28E44 3.27E-10 Co-58 2.00E-05 1.97E-03 5.02E-09 2.51E-04 i Co-60 3.00E-06 2.27E-04 5.79E-10 1.93E-04 Ni-63 1.00E-04 0.00E+00 0.00E+00 0.00E+00 Zn-65 5.00E46 2.18E-04 5.57E-10 1.11E-04 W 187 3.00E-05 9.97E-04 2.54E-09 8.48E-05 Np-239 2.00E-05 9.07E-04 2.32E-09 1.16E-04 St-89 8.00E-06 1.77E-04 4.51E-10 5.64E-05 O' St-90 5.00E-07 6.17E-06 1.57E-11 3.15E-05 I Y-91 8.00E 2.53E-05 6.45E-11 8.07E-06 Y 93 2.00E-05 6.26E-06 1.60E-11 7.98E-07 i
2.76E-05 7.04E-11 3.52E-06 i Zr-95 2.00E-05 f L l Nb-95 3.00E-05 2.73E45 6.97E-11 2.32E-06 ; Mo-99 2.00E-05 1.52E-02 3.88E-08 1.94E-03 l Tc-99m 1.00E-03 8.78E-03 2.24E-08 2.24E-05 Ru-103 3.00E45 9.41E-06 2.40E-11 8.00E-07 , Ru-106 7.00E-05 3.44E-06 8.77E-12 1.25E-07 Rh 103m 1.00E-02 0.00E+00 0.00E+00 0.00E+00 l Rh 106 -- 0.00E+00 0.00E+00 - , Ag-110m 6.00E-06 0.00E+00 0.00E+00 0.00E+00 l Ag-110 -- 0.00E+00 0.00E +00 - Sb-124 7.00E-06 0.00E +00 0.00E+00 0.00E+00 l Te-129m 7.00E-06 3.22E-04 S.21E 1.17E-04 Te-129 4.00E-04 3.42E 8.74E-10 2.18E-06 Te-131m . 8.00E-06 1.52E-03 3.88E-09 4.85E-05 li Te-131 8.00E-05 5.94E-04 1.52E-09 1.89E-05
~ Te-132 9.00E-06 1.06E-02 2.70E-08 3.00E-03 4preventDeatpr naneerder Acoment Anemeen rare 15.7-11 2
g ,
Syntem 80+ Despin ControlDocument Table 15.7.3-2 Results of Iterative Process to Determine Dilution Factor (Cont'd.) Dr = 2.55E-06 Isotope (i) EC(l) (pCl/ml) Cone.in BAST Cone. at Potable Fraction of EC(i) (pCi/ml) Water (pCi/ml) FEC(i) 1131 1.00E-06 1.30E-01 3.32E-07 3.32E-01 1-132 1.00E44 3.52E-02 8.98E-08 8.98E-04 I-133 7.00E-06 1.87E-01 4.76E-07 6.81E-02 1-134 4.00E-04 1.03E-01 2.62E-07 6.55E44 I-135 3.00E-05 1.05E-01 2.68E-07 8.93E-03 Cs-134 9.00E-07 7.80E-02 1.99E-07 2.21E-01 Cs-136 6.00E-06 2.12E-02 5.40E-08 9.00E-03 Cs-137 1.00E-06 1.37E-01 3.50E-07 3.50E-01 Ba-137m 0.00E+ 00 1.55E-20 3.98E-08 0.00E+00 Ba-140 8.00E-06 2.16E44 5.51E-10 6.89E-05 La-140 9.00E-06 7.29E-05 1.86E-10 2.07E-05 Cc-141 3.00E-05 8.10E-06 2.07E-11 6.89E-07 Cc-143 2.00E-05 2.26E-05 5.78E-11 2.89E-06 Cc-144 3.00E 06 2.07E-05 5.27E-Il 1.76E-05 Pr-143 2.00E-05 2.91E-05 7.42E-11 3.71E-06 Pr-144 6.00E44 2.06E-05 5.25E-11 8.75E-08 11-3 1.00E-03 8.50E-01 2.17E-06 2.17E-03 Total 1.00E +00 O ApprovedDestyn Material AccWent Analyses Page 15.712
System 80+ Design ControlDocument l (G 'y Table 15.7.4-1 Parameters Used in Evaluating the Radiological Consequences of a Fuel Handling Accident in the Containment or in the Fuel Building Design Basis Parameter Value I Source Data-1 Radial peaking factor 1.65 ) Core average burnup,3 full-power years at 80% plant factor, MWD /MTU 28K Decay time, hr. 72 Number of failed rods 236 Fraction of fission product gases assumed in the gap region of fuel rods, % lodines 5% Cesiums a Rubidiums 5% Noble gases 5% Percentage of gap activity released to pool 100 ,O Pool decontammation factor for noble gases 1.0 ! Effective pool decontammation factor for iodines, Cesiums & Rubidiums 100 Filter efficiency for iodine removal (percent) Particulate 99 Iodine chemical form released to the containment or the fuel building, percent inorganic iodine 75 . l Organic iodine 25 Fuel building emergency ventilation system Operating Containment purge ventilatio 2 system Operating Time to isolate containment building No isolation credited End time of activity release to the environment (hours) 2 l Atmospheric dilution factors Table 2.3-1 O T) Annresed Design nieterial. Accident Ane&ses Page t5.7-13 i j
System 80+ Design ControlDocument Table 15.7.4-2 Radiological Consequences of a Postulated Fuel Handling Accident in the Fuel Building or Containment Location Dose (rem) EAB (0-2 hr) Thyroid 53 Total-body gamma 0.9 LPZ (0 - 8 hr) Thyroid 7.2 Total-body gamma 0.12 O 9 I l O\ l l I AMwoved Design Meterial Accident Analyses Page 15.7-14 j I I
n.- . . . - - - . . . . . . . - . . . . . . . . - . . . . . _ . . . . . - - . . _ _ . . _-.-. . _. i r
' Syrt?m'80 + Desian controlDocument .
O s tre<<ive e se tisti = Appendix 15A i Pages Date j i,il 1/97 lii, iv 11/% , 15A-1 through 15A-28 11/% b l I e i A i l i l 9 l l i
, tj <
I
- -..-.n ,,,,, ,,
V . . l Srtem 80 + Deslan contrat Document - 1 i m . Q
- Appendix 15A l
i i Analytical Models for Determinhag Radiological _!, 1 Consequences of Accidents i i 1 Contents Page
-1.0 Introduction . . . . . . . . . . . . . . . . . . . . ...................... .. 15A-1 2.0 Source Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... 15A-2 )
- 2. I ' Activities in Core . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 A-2
~2.1.1 Activities in the Fuel Pellet Clad Gap . . . . . . . . . . ........... ....... 1." 2 2.2 Primary and Secondary Side Coolant Activities . . . . . . . . . . . . . . . . . .. . 13A-2 j 2.3 lodine Spiking Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15A-2 j 3.0 Dose Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... .. 15A-3 3.1 Assumptions ....................... .. . . . . . . .......... 15A-3 3
3.2 Gamma Dose . . . . . . . . . . . . . . . . . . . . . ............. ........ 15A-3
% 3.3 Thyroid inhalation Dose' . . . . . . . . . . . .......... . . . ........... 15A-4 3.4 Control Room Dose . . . . . . . . . . . . . . . . . ...... . . . . ....... ... 15A-4 4.0 Computer Codes Used in Accident Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . 15A-6 4.1 DRAGON............................................... 15A-6 4.2 PERC2................................................. 15A-7 4.3 ORIGEN il . . . . . . . . . . . . . . . . . . . . . ........................ 15A-7 5.0 Analytical Models for Loss-of-Coolant Accidents . . . . . . . . . . . . . . . . . .... 15A-8 5.1 Assumptions for LOCA Doses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F A-8 6.0 Analytical Models for Non-LOCA Events . . . . . . . . . . . . . . . . . . . . . . . . . . 15A-10 6.1 Assumptions for Non-LOCA Dose Calculations . . . . . . . . . . . . . . . . . . . . . . . 15A-10 6.2 - Steam Release Calculation for Cooldown via Secondary System . . . . . . . . . . . . . 15A-12 7.0 References . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... . . . . . . 15 A-14 Tables 1
.15A-l ' Core Inventory (Ci) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15A- 16 l 15A-2A. Gamma and Beta Average Energies per Nuclide (MeV/ dis) . . . . . . . . . . . . . . . 15 A-19 l 15A-2B Thyroid Dose Conversion Factors (DCF) . . . . . . . . . . . . . . . . . . . . . . . . . . . 15A-20
} 15A-3 Gap Activities (Curies) . . . ._ . . . . . . . .:. . . . . . . . . . . . . . . . . . . . . . . . .
15A-20 15A-4 : Primary Coolant Technical Specification Concentrations ( Ci/gm) . . . . . . . . . . 15 A-21 y' (e :15A-5. Initiallodine and Noble Gas Concentrations in the Steam Generator . . . . . . . . . 15A-23 s 115A4 Pre-Accident lodine Spike Concentration in Reactor Coolant . . . . . . . . . . . . . . 15A-23 215A-7; : Generated Iodine Spike Appearance Rztes . . . . . . . . . . . . . . . . . . . . . . . . . . . 15A 1 W W H A00Mant Ana& 9 nee (11/96) Page R }
'- \,( d
Sy t m 80 + Dis /gn ContnlDocument Tables (Cont'd.) 15A-8 Breathing Rates for Adults . . . . .. ... . . 15A-24 15A-9 Containment Data . . .. . . . .... . .... 15A-24 15A-10 Control Room Data ... . . .. . .. . . . 15A-25 Figures 15A-1 Activity Transfer Following LOCA . . .. . . . . . . 15A-26 15A-2 Decay Power Fractions with Uncertainty vs Time After Shutdown . . 15A-27 15A-3 Integrated Fiactional Power vs Time After Shutdown . . . . .. . 15A-28 O O Approved Design Material Accident Analyses (11/96) Pageiv
i l System 80+ Design ControlDocument l O 1.o 1 irea ciie-This appendix identifies the models used to calculate offsite radiological doses that would result from releases of radioactivity due to various postulated accidents. The postulated accidents are:
- Steam System Piping Failure Outside Contammen:
- Single Reactor Coolant Pump Rotor Seizure
- Control Element Assenhly Ejection
- Letdown Line Break Outside Containment
- Steam Generator Tube Rupture
- Feedwater Line Break
- Fuel Handling Accident
- Loss of Coolant Accident The radiological consequences of each of the design basis accidents (DBA) listed above were analyzed based on assumptions discussed in the respective sections. Specific parameters used in these analyses are tabulated in the corresponding sections.
Initial core and core gap activities, coolant Technical Specification equilibrium concentrations, pre-accident iodine spike primary coolant concentrations, and concurrent iodine spiking appearance rates are discussed in Section 2.0 below. Coolant concentrations at design basis and expected fuel defects arc given in Tables 12.2-5 and 11.1.1-2 respectively. The releases to the environment resulting from each accident are presented in the respective sections. Accident atmospheric dilution factors (x/Q) for the exclusion area boundary and low population zone were used to calculate the potential offsite doses. The sector-dependent x/Q values were de: ermined as described in Section 2.3.4 and are tabulated in Table 2.3-1. Main control room x/Q values are discussed in Section 2.3.6 and given in Tables 2.3-2 through 2.3-5. These main contro! x/Q values (or any site-specific x/Q values calculated using Ramsdell methodology as described in Section 2.3.6) must be used in conjunction with Reference 9 thyroid dose conversion factors which are d:veloped based on Reference 4 and summarized on Table 15A-2B. This will ensure adequate conservatism in control room dose calculations. The atmospheric releases given in each accident section are used in conjunction with the appropriate x/Q values to calculate the potential offsite and control room doses for the corresponding accidents. The methodology for determining the doses is discussed in Section 3.0 of this Appendix. The resulting EAB and LPZ doses are presented in the corresponding sections for all the postulated accidents. The potential doses to main control room personnel are presented in Table 6.4-1. n For all cases the potential offsite doses are within the limits of 10 CFR 100, while the potential doses for Q the main control room are within the limits of GDC 19 of Appendix A to 10 CFR 50. ) I Approved Den &n Materiel AccMent Analyses (11/96) Page 15A.1 l l
)
System 80+ Design ControlDocument 2.0 Source Terms h 2.1 Activities in Core The core fission product inventories and other nuclides, which are important from a health hazards point of view, are calculated as described in Section 11.1 using the computer program ORIGEN. This program is widely used in the industry and a short description is provided in Section 4.0. The resulting inventories are presented in Table 15A-1. The nuclides included in Table 15A-1 are those considered for calculating organ doses and for direct doses due to immersion. 2.1.1 Activities in the Fuel Pellet Clad Gap For accident analysis, the core gap activities are based on the guidance provid:d in Draft NUREG-1465 (Reference 1). The noble gas, iodine, cesium, and rubidium inventory in the fuel gap region is assumed to be 5% of the core inventory. The values are presented in Table 15A-3. The chemical species of the iodine in the gap are based on the guidance of Draft NUREG-1465, i.e.,95 % paniculate and 5% gas. 2.2 Primary and Secondary Side Coolant Activities The equilibrium concentrations in the RCS and the secondary coolant system have been calculated assuming full power operation for the following cases: 1) 0.25 % fuel defects,2) normal operations using the guidelines of NUREG-0017 (USNRC 1976), and 3) plant Technical Specification concentrations. The Technical Specification activities are used in the analysis of the main steam line break (MSLB), the locked rotor accident, the rod ejection accident, the failure of small lines carrying priman coolant outside containment, feedwater line break and the steam generator tube rupture. The Technical Specifications restrict the concentration in the primary and secondary systems to 1.0 and 0.1 Ci/gm I-131 dose , equivalent, respectively and to 100/8 pCi/gm for other isotopes in the primary system. The resulting iodine and noble gas concentrations in the primary coolant and steam generator liquid and steam phases are presented in Tables 15A-4 and 15A-5, respectively. 2.3 Iodine Spiking Concentrations The analysis of an MSLB, locked rotor accident, steam generator tube rupture, feedwater line break and the failure of small lines carrying primary coolant outside containment include equilibrium coolant iodine l concentrations augmented by iodine spiking. Both pre-accident and concurrent iodine spiking models are l considered. The pre-accident iodine spiking concentrations are determined by increasing the primary coolant iodine concentrations to 60 times (References 2 and 3) the maximum value described in the Technical Specifications. The resulting primary coolant iodine concentrations are given in Table 15A-6. The concurrent iodine spike is modelled by increasing the iodine release rates from fuel rods into the primary coolant to a value which exceeds 500 times the equilibrium iodine concentration release rates. Table 15A-7 presents the iodine release rates for concurrent iodine spiking. G ANweved Design Atatorial- AccMent Analyses (11/96) foge 15A 2 u___ _. _ __ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
1 System 80+ Design ControlDocanent T The chemical speciation and physical form of the iodine released due to the spinx are conservatively assumed to be 100% gaseous; that is, no credit is taken for deposition in particulate form once iodine tran these sources becomes airborne. 3.0 Dose Analyses 3.1 Assumptions The following assumptions are basic to the model for the gamma and beta dose due to immersion in a cloud of radioactivity and the model for the thyroid dose due to inhalation of radioactivity. ! e The dose contribution of direct radiation from sources other than the leakage cloud is negligible compared to the dose due to immersion in the leakage cloud.
- All radioactivity releases are treated as ground level releases regardless of the point of discharge. e e The dose receptor is a standard man as defined by the International Commission on Radiological !
Protection (ICRP) (Reference 4).
- Radioactive decay from the point of release to the dose receptor is neglected.
* 'IsNopic beta and gamma decay energies are taken from Table of Isotooes (Reference 5) and from References 6 and 7.
Os e Atmospheric dispersion factors used in the analyses are presented in Section 2.3. j I i e The analyses use dose conversion factors based on following guidance documents: l l t
- gamma and beta - Regulatory Guide 1.4 (Reference 8),
i
- thyroid - TID-14844 (Reference 9),
j - other organs - EPA 520/1-88-020 (Reference 11). 3.2 Gamma Dose The gamma dose is obtained by considering the dose receptor to be immersed in a radioactive cloud which is infinite in all directions above the ground plane, i.e., a semi-infinite cloud. t The concentration of radioactive material within this cloud is taken to be uniform and equal to the maximum centerline ground level concentration that would exist in the cloud at the appropriate distance from the point of release.
- The whole-body dose is a result of exposure to external gamma radiation. The whole-body dose due to immersion in a semi-infinite cloud is given by (Reference 8):
-D, = 0.25 x/Q g3 +59 [3-1]
E. A ,
'1 A0\ proved Dee&rt a008arinf- ACsilinett Ana&ses (11/96) Page 15A4 l
System 80+ Design controlDocument where: D, = is the whole-body gamma dose from immersion in a semi-infinite cloud for a given time period, rem. Am = is the activity of isotope i released during a given time period, curies 3 x/Q = is the atmospheric dilution factor for a given time period, sec/m 89 = is the average gamma radiation energy emitted by isotope i per disintegration, MeV/ dis The gamma energies presented in Table 15A-2A include the X-rays and annihilation gamma rays if they are prominent in the electromagnetic spectrum. 3.3 Thyroid Inhalation Dose The thyroid inhalation dose is obtained from the following expression (Reference 9): DmY = x/Q B E Q, - (DCF)3 [3-2] where: Dmy = thyroid inhalation dose, rem 3 x/Q = atmospheric dilution factor for a given time period, sec/M B = breathing rate for a given time period t, m 3/sec Q3
= total activity of iodine isotope i released in time period t, curies (DCF), = dose conversion factor for iodine isotope i, rem / curie inhaled The thyroid inhalation dose conversion factors and offsite breathing rates used in the above model are given in Table 15A-2B and Table 15A-8, respectively.
3.4 Control Room Dose The thyroid inhalation, whole-body gamma, and beta skin dose models for the major contributors to the Control Room dose are described below. The dose to the Control Room occupants due to a postulated accident is calculated on the basis of source strength, atmospheric transport, dosimetry and Control Room emergency pressurization and filtration considerations as illustrated in the following equations and used in References 6 and 7. The thyroid inhalation dose is obtained from the following expression: DmY - E E BR DCF, ' #3 A(t)i dt [3-3] ij . T3-. Argoved Design Afsterial- Accident Analyses (11/96) Page 15A-4
Svstem 80+ Design ControlDocument I o, i -v) ( where: l t
'DmY = thyroid inhalation dose, rem i = isotope index .
j = time interval index l BR = breathing rate, m 3/sec DCF, = dose conversion factor for iodine isotope i, rem / curie inhaled A(t) = airborne concentration of iodine isotope i at time t (sec), in the ' :rol Room, i , curies /m3 The thyroid inhalation dose conversion factors and Control Room breathing rate used in the above model are presented in Table 15A-2B and Table 15A-8, respectively. The whole-buly gamma dose due to inleakage is calculated using the following equation: Da - (R/2) E A, (K,), [3-4] i f3 where: i a Da = whole-body gamma doce, rem R = radius of an equivalent hemispherical control room, m ; A3 = time integrated concentration of nuclide i, Ci-hr/m3 (Kg), == dose coliversion factor for nuclidc 1, Rem m2 /Ci hr defined by equation 3-5 6 (Kg), - 3.7 x 10 E S yC) [3-5) b Sg = gamma energy emitted per disintegration for nuclide i at energy Ej , Mev/ dis flux to dose rate conversion factor for gamma energy Ej , rem-cm2-sec/Mev-hr, C3 = Reference 10 3.7 x 10 6 = Units conversion factor, dis-m2/Ci-sec-cm2
*Ihe gamma energies Ej , are presented in Table 15A-2A.
*!he beta skin dose due to inleakage is calculated using the following equation (Reference 8):
.f (3 )
\d D, = 0.23 E A, E,3 [3-6]
i e Anand Doeipe m AeeMant Anekees it tas) roen 15A-5 i
System 80+ Design ControlDocument where:
= beta skin dose from immersion in a semi-infinite cloud, rem Da 3
Ai = time integrated concentration of nuclide i, Ci-sec/m Es,i = average beta energy emitted by isotope i, MeV/ dis The beta energies include conversion electrons if they are prominent in the electromagnetic spectrum and are computed as one-third the maximum beta energy for a given spectrum. The values of Es are presented in Table 15A-2A. The whole-body gamma dose to Control Room personnel due to a cloud external to the Control Room is calculated using the following equation: D, = E (x/Qj CF)i [3-7] Ei Ad J where: D, = whole-body gamma dose due to extemal cloud shine, rem x/Q, = atmosph-i: dispersion factor for the time period j, calculated at various locations at the Control Room (such as the air intakes control room doorway or center of 3 control room roof) assuming a ground level release, sec/m Ag = total activity of nuclide i released during time period j, Ci 2 CF, = a dose rate response function for a unit concentration of nuclide i, rem-m /Ci-sec 4.0 Computer Codes Used in Accident Analysis The computer programs described below have been used to calculate design-basis source terms and radiological consequences of design basis accidents. 4.1 DRAGON (Reference 6) Program DRAGON evaluates the activities, dose rates, and time-integrated dose in the reactor building and control room of a nuclear facility or at an adjacent site following release of halogens and noble gases from some control volume. The fission product release to the atmosphere, together with the activities and time-integrated activity concentrations of the halogens which are accumulated in the system, are also computed. Site dose calculations performed by DRAGON employ the semi-infinite cloud models suggested by Regulatory Guide 1.4. The gamma dose in the control room is computed based upon a , finite cloud model. Average beta and gamma energies are used in all dose calculations. O Approved Design Meterial. AccMent Analyses (11/96) Pope 15A-6 1
System 80+ Design ControlDocument
/^
4.2 PERC2 (Reference 7) Program PERC2 is identical to DRAGON in terms of the environmental transport and dose conversion, but it includes the following:
- Provision of time-dependent releases from the actor coolant system to the containment i atmosphere
- Provision for airbome radionuclides other than noble gas and iodine, including daughter in-growth
- Provision for calculating organ doses other than thyroid
- Provisions for tracking time-dependent inventories of all radionuclides in all control regions of the plant modei
- Provision for calculating energies as well as activities for the inventoried radionuclides to permit direct equipment qualification and vital access assessment These provisions are necessary to treat the kind of source term described in Draft NUREG-1465 (Reference 1) which involves time-dependent release from the primary system to the containment and seven radionuclide groups in addition to the two groups for iodine and noble gases.
I 4.3 ORIGEN II (Reference 12) 0'3 . 1 The ORIGEN 11 code calculates the fission product and transmission sources and isotopes for irradiated fuel as a function of operating history and dxay time. ORIGEN 11 computes time-dependent concentrations and source terms of a large number of isotopes, which are simultaneously generated or depleted through neutronic transmutation, fission, radioactive decay, input feed rates and physical or chemical removal rates. The calculations may pertain to fuel i irradiation within nuclear reactors, or the storage, management, transportation or subsequent chemical l processing of removed fuel elements. The matrix exponential expansion tnodel of the ORIGEN code is { unaltered in ORIGEN II. Essentially all features of ORIGEN were retained, expanded or supplemented j within new computations. The primary objective of ORIGEN II, as requested by the Nuclear Regulatory Commission, is that the calculations may utilize the multi-energy-group cross sections from any currently processed standardized ENDF/B data base. This purpose has been implemented through the prior execution of codes within either the SCALE System or the AMPX System, developed at the Oak Ridge National Laboratory. These codes compute flux-weighted cross sections, simulating conditions within any given reactor fuel assembly, I and convert the data into a library that can be input to ORIGEN II. Time-dependent libraries may be produced, reflecting fuel composition variations during irradiation. Some of the other objectives included in ORIGEN 11 are: the convenience of free-form input; the flexible dimensioning of storage to avoid size restrictions on libraries or problems; the computation of gamma source spectra in any requested energy-group-stmeture, applying a more complete standardized data base; the determination of neutron absorption n rates for all nuclides; and the integration of fission product energies and sources over any decay interval,
] by applying the Volterra multiplicative integral method.
AMwownt Design Meter 6el AccMetrt Analyses (11/96) Page 15A-7
System 80 + Design ControlDocument ORIGEN II is a functional module in the SCALE System and will be one of the modules invoked in the SAS2 Control Module, presently being developed, or may be applied as a " stand alone" program. It can be used in nuclear reactor and processing plant design studies, radiation safety analyses, and environmental assessments. 5.0 Analytical Models for Loss-of-Coolant Accidents (LOCAs) This section describes the analytical models used in the calculation of radiation doses resulting from a LOCA. The doses are for the following locations:
- Exclusion Area Boundary (EAB)
- Low Population Zone (LPZ)
- Within Control Room (CR)
The dose is computed to the critical organ due to inhalation, to the skin due to the emission of beta particles and to the whole-body due to the emission of photons from the radioisotopes. The doses at the exclusion area boundary are based on the total activity released over the first two hours following a LOCA. The doses at the low population zone and within the control room are based on the total activities released over a period of thirty days. This is in accordance with the requirements identified in References 13 and 14. The total dose at a given locsica (EAB, LPZ and control room) is based on a summation of activities from various release paths to the atmosphere. These paths are:
- Contairunent leakage, including the discharge from the containment arumius ventilation system (Reference 15).
- Containment discharge, of iodine spike activity, through the power purge valves prior to closure (Reference 15).
- Post LOCA leakage from ESF systems outside containment (Reference 16).
5.1 Assumptions for LOCA Doses The assumptions used for the LOCA dose models are consistent with those given in References 8,15 and 16 to the extent not superseded by Reference 1. These include:
- The mdionuclide release from the primary system is divided into three phases. These are as follows:
Coolant release phase, from t=0 to t =0.0083 hours (30 seconds)
- Gap release phase, from t=0.0083 houts to t=0.5083 hours Fuel release phase, from t =0.5083 hours to t = 1.8416 hours O
Apprend Design heeterni- AccMent Analyses (11/96) Page 15A4
t System 80+ Design ControlDocument Therefore, the release to the containment is assumed to end at 110.5 minutes after the stan of the (#n) \ accident. This is consistent with Reference 1. The release magnitudes are as follows for the gap and fuel release phases (as fractions of core inventory, from Reference 1): Gap Release Fuel Release Duration (Hours) 0.5 1.3 Noble Gases 0.05 0.95 Iodine 0.05 0.35 Cesium 0.05 0.25 Tellurium 0 0.15 Strontium 0 0.03 Barium 0 0.04 Ruthenium 0 0.008 Cerium 0 0.01 Lanthanum 0 0.002 O V The release is assumed to be uniform over the duration given. The two-hour exclusion area boundary dose and the thiny-day low population zone dose are calculated from the stan of the gap release. e The chemical and physical form of the release to containment is discussed in Reference 1. Based on Reference 1, the entire release is as particulate except for the noble gases and five percent of the (iodine and other halogens). Per Reference 17,0.15% of this 5% is organic. The dose analyses conservatively assume that 0.25% is organic.
- Airborne radionuclides are removed by the operation of the containment sprays as described in Section 6.5, and the activity removed is assumed to mix into the IRWST inventory. This liquid is circulated through the various safety pumps in the ESF rooms. Leakage through the pump seals and valves results in an activity in the ESF rooms which vents to the atmosphere.
- No credit is taken for depletion of the effluent plume due to either deposition on the ground or to radioactive decay during transpon to the locations of interest.
e Dose calculations are performed with the computer program PERC2 (15A.4.2) using inputs for breathing rate, containment parameters, and control room parameterr. on Tables 15A-8 through 15A-10, respectively. ,q Anvoved Des &n Metenial. Accident Ane&ses (11/96) Page 15A 9
System 80+ Design ControlDocument 6.0 Analytical Models for Non-LOCA Events $ This section provides a brief description of aralvtical models for calculating offsite radiological doses resulting from non-LOCA events. The models described below incorporate the SRP (Reference 18) guidelines for calculating offsite radiological consequences and through the use of conservative assumptions maximize the offsite radiological doses. The non-LOCA doses are calculated for the following locations:
*s Exclusion Area Boundary (EAB)
- Low Population Zone (LPZ)
For each of the above locations, the dose is calculated to:
- the thyroid due to inhalation of radioion. ies, and
- the whole body due to gamma radiation from radioiodines, cesiums, rubidiums and noble gases.
The cesiums and rubidiums are included only for events resulting in fuel failure. In accordance with the guidelines of Reference 13, the doses at the exclusion area boundary are calculated based on the total activity released over the first two hours following the initiation of the event. Similarly, the doses at the low population zone are determined on the basis of the total activity released over the entire event (in general, about eight hours from the initiation of the event, by which time the shutdown cooling system is placed in operation). The total doses at a given location are derived from activities from various release paths to the atmosphere. These include:
- Main Steam Safety Valves (MSSVs)
- Atmospheric Dump Valves (ADVs)
- Nuclear Annex
- Contairunent 6.1 Assumptions for Non-LOCA Dose Calculations The following assumptions are employed in the non-LOCA (except for Sections 15.7.3 and 15.7.4) dose calculations to conservatively maximize offsite radiological consequences.
- Accident doses are calculated for three different scenarios, as applicable, consistent with the guidelines of Reference 18:
- An event generated iodine spike (GIS) coincident with the initiation of the event is considered,
- a pre-accident iodine spike (PIS) is assumed, or
- a failed fuel condition in the core is considered.
Approved Design Meterial AccMent Analyses (11/96) Page 15A.10 m
t 5 System 80+ Design 8:entrolDoewnent
+
- e. A spiking factor of 500 is employed for the GIS calculations per the guidelines of Reference 18. l The spike is conservatively assumed to start at time zero. l 4
e For the PIS case, the technical specifications maximum full power' LCO limit of 60 Ci/gm f
. Iodine-131 dose equivalent concentration is assumed to be present in the RCS. l
. The technical specification limits are employed for the initial iodine activity concentrations for ;
1 .* the primary system (1.0 Ci/gm I-131 dose equivalent) ane secondary system (0.1 Ci/gm I-131 'l dose equivalent). The initial primary side overall noble gas concentration is assumed to be at the ! 4 Technical Specification limit of 100/8 pCi/gm. The initial secondary side iodine and noble gas '
! concentrations are provided in Table 15A-5. .
t a e e Timmg of operator action may vary from event to event. It is generally assumed that no operator action will take place in the first 30 minutes unless an earlier operator action results in more , t adverse c=aq=nces. i e An overall steam generator tube leakage of I gpm (Technical Specification limit) is assumed for the duration of the transient. i it is assumed that after the shutdown cooling system entry conditions (350*F, 330 psia) are l e reached, there are no more releases of steam and radioactivity to the atmosphere. l e A controlled cooldown at the maximum Technical Specification rate (100'F/hr) is assumed to
- /^ begin at approximately 30 minutes after initiation of the transient. This cooldown maximizes the 2-hour dose release.
l e Steam Bypass Control System (SBCS) is assumed to be unavailable subsequent to a reactor trip. Following a reactor trip, but prior to operator action, steam is discharged to the atmosphere through Main Steam Safety Valves (MSSVs). After operator action, cooldown is performed using the Atmospheric Dump Valves (ADVs). E e Conservative Decontamination Factors (DF), as shown below, are assumed for various occurrences. i DF=1 for the portion of primary to secondary Ir.al: age that flashes to steam in the steam r generator (SG) during a steam generatter tube tupture (SGTR) event; - applicable to!odines 4 DF= 100 for the ucflashed portion of primary to secondary leabge (SGTR only); -
) applicable to todines DF=1 for the duration of steam releases from a SG that has dried out; - applicable to lodines, Cesiums and Rubidiums DF= 100 for the duration of steam releases from a SG that has not dried out; - applicable to lodines, Cesiums and Rubidiums DF= 100 for secondary releases inside and outside containment; - applicable to lodines,
' Cesiums and Rubidiums 4 pound Due> AIsewest. Aesthe /.nsfree (f r/ Del pape 754-77
.,, , - , - - . . - , . ~ . , ~ . - - . - , . . , . - , _ - . , , - , - - -
i l System 80+ D un Control Document DF = 100 for releases evolving out of the Fuel Pool; - applicable to Iodines, Cesiums and ' Rubidiums.
- Any primary or secondary breaks outside containment are assumed to be isolated by 30 minutes (start of cooldown). For the case of a steam line break upstream of the MSIV, further steam releases are included beyond this time period. j
- Atmospheric Dispersion Factors (r!Q) are provided in Section 2.3.
- With the exception of the Control Element Assembly Ejection Accident, the maximum integrated radial pesking factor (Fa) of 1.58 is assumed for all accidents that have failed fuel. The peaking factor used for the CEAE is 1.3.
- The overall core inventory of all significant isotopes is provided in Table 15A-1. A 15%
uncertainty factor is added to be conservative.
- The RCS metal temperature remains the same as the average coolant temperature throughout cooldown.
- The RCS heat loss to the containment is not credited during the cooldown calculation.
- The specific heat of the coolant and the RCS metal is assumed to remain at their initial values throughout the cooldown for added conservatism.
- The cooldown analysis does not take credit for the subcooling of the feedwater.
- In the decay tieat calculation, if the time after shutdown is less than 1000 seconds, then a 20%
uncertainty factor is added and if the time after shutdown is longer than 1000 seconds, then a 10% uncertainty factor is added. (Reference 19) i
- For the cooldown analysis, the initial plant condition is assumed to be at 102 % power and $87'F for the average RCS temperature. A higher initial power level maximizes the steam release, and hence maximizes the radiological releases.
- The whole-body dose caused by isotopes whose half lives are less than 4 minutes are neglected from the calculation.
- No credit is taken for the in-transit radioactive decay of the isotopes that are considered in the calculation.
6.2 Steam Release Calculation for Cooldown via Secondary System l The long term cooldown via the secondary side is accomplished by releasing steam through the l Atmospheric Dump Valves. The maximum Technical Specification cooldown rate of 100*F/hr is assumed to maximize the steam release, and hence maximizes the radiological dose release. The energy l that needs to be removed comes from two different sources-l
- The internal energy stored in the RCS metal and coolant, called sensible heat, and
- Ttr decay heat caused by the decay of the fission products.
r - .-._,- , , , - . .,a ;
Svsener 80+ Desiers CorrtrolDocumerrt - i: :
\
) The following describes how these two items are calculated for non-LOCA events (Sections 15.7.3 and -
' 15.7.4 are excluded): [
t a r e Sensible Heat Calculation: ; d-To facilitate calculation of the sensible heat, the following conservative assumptions are made: l . . . i
- The RCS metal t-wigare remains the same as the average coolant temperature during - J cooldown, e.g., when coolant temperature is reduced by 100'F per hour, the RCS metal j temperature is reduced at the same rate.
-- The RCS heat loss to the containment will not be accouned for f.e., assuming heat !
transfer is only in one direction, towards the coolant. i t
-- The specific heat of the coolant and of the RCS metal remain conrimt at their initial !
higher values throughout the cooldown. q The sensible heat is then calculated as: .. i ! ii
- I !
Q, a,ie(T) - [ E M,,,,,, I C,w,i (T) + M.
- C,,m (T)] - At [6-1]
.i E M ,,,,i C,w,i (T) - M ay C,,my (T) + Map C p.RP (T) 4 1 Cr.so (T) [6-2]
Mrza
- C p.rza (T) + Mm Where, T '= RCS metal or coolant temperature in 'F C, = specific heat in Bru/lbm *F
- t = time in hours RV = Reactor Vessel !
l i RP = RCS piping PZR- = Pressurizer I' .SG =- Steam Generator 1 l W asse assement. Aessdent Ans@es (f fas/ .page f54-73 i
System 80+ Design ControlDocument e Decay Heat Calculation: The decay heat is calculated on the basis of NRC recommended decay heat fractions for long term cooldown calculations (Reference 19). Using this information, the decay heat expressed in fractional power is plotted against time after shutdown in Figure 15A-2. In addition, an integrated fractional power expressed in watt-sec/ watt is plotted against time after shutdown in Figure 15A-3. It should be noted that as a conservative measure, a 20% uncertainty factor is added to the decay power when time after shutdown is less than 1000 seconds; a 10% uncertainty factor is assumed when time after shutdown is greater than 1000 seconds. 7.0 References
- 1. Draft NUREG 1465, Accident Source Terms for Light Water Nuclear Power Plants, June 1992.
- 2. CENPD-180P, Iodine Spiking, Radioiodine Behavior in the Reactor Coolant System During Transient Operations, March 1976.
- 3. CENPD-180P, Supplement IP, Iodine Spiking, Radioiodine Behavior in the Reactor Coolant System During Transient Operations, March 1977.
- 4. ICRP Publication 2, Report of Committee II on Permissible Dose for Internal Radiation (1959).
The International Commission on Radiological Protection.
- 5. Table of Isotopes, sixth edition, by C.M. Lederer, J.M. Hollander, I. Perlman: University of California Berkeley Lawrence Radiation Laboratory.
- 6. DRAGON, SWEC proprietary computer code NU-115, Version 05, Level 00, October 1987.
- 7. PERC2, SWEC proprietary computer code NU-226, Version 00, Level 00, May 19,1993.
- 8. Regulatory Guide 1.4, Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors, Revision 2, June 1974, U.S.
Nuclear Regulatory Commission.
- 9. TID-14844, Calculation of Distance Factors for Power and Test Reactor Sites, by J.J. DiNunno, F.D. Anderson, P.E. Baker and R.L. Waterfield, Division of Licensing and Regulation, U.S.
Nuclear Regulatory Commission.
- 10. TID-7004, Reactor Shielding Design Manual, March 1956.
- 11. EPA-520/1-88-020. " Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion and Ingestion", September 1988.
- 12. ORNL-TM-7175, A Users Manual for the ORIGEN 11 Computer Code, A. G. Cross, July 1980.
- 13. 10 CFR 100.11. Detenrination of Exclusion Area, Low Population Zone and Population Center Distance, Code of N1eral Regulations, January 1,1979.
- 14. NUREG-0800, Standard Review Plan 6.4, Revision 2, Control Room Habitability Systems, O July 1981.
Amme oeson nonnnet. Accuent Anemsee is sim rege rsA.st
1 I
. System 80+ Deden Contnd Document l O 15. NUREG-0800, Standard Review Plan 15.6.5, Appendix A, Revision 1, Radiological Consequences of a Design Basis Loss of Coolant Accident Including C&*=iamear Leakage Contribution,-July 1981.
- 16. NUREG-0800, Standard Review Plan 15.6.5, Appendix B, Revision 1, Radiological CoPM-M of a Design Basis Loss of Coolant Accident: Leakage From Engineered Safety .
Features Components Outside Cnntamment, July 1981.
- 17. " Licensing Design Basis Source Term Update for the Evolutionary Advanced Light Water Reactor," Advanced Reactor Severe Accident Program (ARSAP) Source Term Expert Group, September 1990.
- 18. NUREG-0800, Standard Review Plan, USNRC, July 1981. )
- 19. NRC Branch Technical Position APCSB 9-2, Residual Decay Energy for Light Water Reactors for Long Term Cooling, Rev. 2, July 1981. 1
- 20. NUREG-0017, Rev.1, Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Pressurized Water Reactors, USNRC, April 1985.
O l
)
i l s O weent Doetpn neenwner- Aeement Ann %ees (t rises pape rsa.ss l
, - ,r .
r* . , ---,, e , ,m--
System 80+ Design ControlDocument Table 15A-1 Core Inventoryl81 (CD h Isotope Core Inventory Isotope Core Inventory Isotope Core Inventory H3 5.223E+04 Y-91 1.750E +08 Mo-106 3.802E+07 Co-60 0.000E+00 Y-91m 9.787E +07 Tc 106 6.050E+07 Co-60m 0.000E+ 00 Kr-92 4.299E+07 Ru-106 3.913E+07 Co-58 0.000E+00 Rb-92 1.369E+08 Rh-106 4.340E+07 Co-58m 0.000E+00 Sr-92 1.785E +08 Ra-109 2.021E +07 Zn-72 6.625E+03 Y-92 1.791E+08 Rh-109 2.099E+07 Ga-72 6.645E+03 Kr-93 1.520E+07 Pd-109 2.335E+07 As-76 2.391E+02 Rb-93 1.025E+08 N-109m 1.054E+07 i Ga-77 1.262E+05 Sr-93 1.968E+08 Ag-110 6.921E+06 Ge-77 1.262E+05 Y-93 2.010E +08 Ag-110m 1.672E+05 Ge-77m 2.861E+05 Kr-94 6.082E+06 N-ill 5.61E +06 Br-82 4.204E+05 Rb-94 5.259E +07 Ag-ll! 5.619E+06 Br-82m !.728Eto5 Sr-94 1.840E +08 Ag-lllm 5.591E+06 Ge-83 2.761E+06 Y-94 1.992E+08 N-112 3.096E+06 As-83 1.173E +07 Rb-95 2.661E+07 Ag-ll2 3.106E+06 Se-83 6.401E+06 Sr-95 1.701E+08 N-115 1.770E+06 Se-83m 1.003E+07 Y-95 2.101E+08 Ag-ll5 1.328E+06 Br-83 1.669E+07 Zr-95 2.178E+08 Ag-115m 5.Il3E+05 Kr 83m 1.670E +0', Nb-95 2.193E+08 Cd-ll5 1.173E+06 l Se-85 1.754E+07 Nb-95m 1.585E +06 Cd-ll5m 1.636E +05 Br-85 3.646E +07 Sr-97 6.113E +07 In-ll5m 1.717E +06 Kr-85 1.127E+06 Y-97 1.688E+08 Cd 121 1.520E +06 Kr-85m 3.692E +07 Zr-97 2.070E+08 in-121 1.295E+06 Rb-86 1.561E+05 Nb-97 2.086E+08 In-121m 3.280E+06 Rb-86m 1.953E+04 Nb-97m 1.963E+08 Sn-121 1.625E+06 Se-87 2.745E+07 Zr-99 2.041E+08 Sb-122 1.258E+05 Br-87 6.087E+07 Nb-99 2.114E+08 Sb-122m 1.105E+03 i Kr-87 7.232E +07 Nb-99m 7.544E+06 In-123 1.298E+06 Se-88 1.020E+07 Mo-99 2.201E + 08 Sn-123 3.749E+05 Br 88 6.733E +07 Tc-99m 1.926E +08 Sb-124 7.575E+04 Kr-88 1/J20E+08 Zr-101 1.211E +08 Sb-124m 9.134E+02 Rb-88 ". 034E+08 Nb-101 1.886E+08 In-125 1. ' ele +06 Se-89 2.807E+06 Mo-101 1.988E +08 Sa-125 1.3.!7E+06 BI-89 4.879E+07 Tc-101 1.988E+08 Sn-125m 2.141E+06 Kr-89 1.265E +08 Mo-103 1.610E +08 Sb-125 1.205E +06 Anwowat Cesign Materiel AccMent Analyses (11/96) Pope 15A 16
, System 80+ Design ControlDocument 1
o
) Table 15L1 Orte Inventory (Cl)I I (Cont'd.)
Isotope Core Inventory Isotope Core Inventory Isotope Core Inventory , Rb-89 1.335E+08 Tc-103 1.632E4 08 In-127 1.785E+06 Sr-89 1.389E+08 Ru-103 1.628E+08 Sn-127 6.885E+06 Br-90 3.203E+ 07 Rh-103m 1.466E+08 Sn-127m 3.350E+06 l Kr-90 1.254E+08 Nb-104 4.325E+07 Sb-127 1.091E+07 Rb-90 1.308E+08 Mo-104 1.175E+08 Te-127 1.078E+07 Rb-90m 2.919E +07 Tc-104 1.251E+08 Te-127m 1.415E+06 Sr-90 8.904E+06 Mo-105 7.751E +07 in-129 2.440E+06 Y-90 9.225E+06 Tc-105 9.483E+07 Sn-129 1.167E+07 Y-90m 1.585E+03 Ru-105 9.617E+07 Sn-129m 1.455E+07 Kr-91 9.271E+07 Rh-105 8.998E +07 Sb-129 3.487E+07 Rb-91 1.592E+08 Rh-105m 2.693E+07 Te-129 3.435E+07 Sr-91 1.687E+08 Cs-137 1.077E+07 Pm-151 2.090E+07 Te-129m 5.146E+06 Ba-137m 1.021E+07 Pr-152 6.138E+06 Sn-130 4.019E+07 Te-138 3.636E+06 Pm-153 9.254E+06 o Sb-130 1.128E +07 l-138 5.515E+07 Eu-154 6.310E+05 ( (,)e Sb-130m 5.338E+07 Xe-138 2.109E+08 Sm-155 3.390E+06 1-130 2.634E+06 Cs-1; ., 2.318E+08 Eu-155 4.108E+05 1-130m 1.085E+06 1-139 2.463E+07 Sm-156 2.042E+06 In-131 1.093E+ 06 Xe-139 1.669E+08 Eu-156 9.826E+06 Sn-131 3.690E+07 Cs-139 2.195E +08 Sm-157 1.301E+06 Sb-131 9.875E +07 Ba-139 2.251E +08 Eu-157 1.674E+06 Te-131 1.034E+08 1-140 7.069E+06 Eu-158 7.407E+05 Te-131m 1.631E +07 Xe-40 1.118E +08 Eu-159 3.817E+05 1 131 1.165E+08 Cs-140 1.979E +08 Gd-159 4.385E+05 Xe-131m 1.297E+% Ba-140 2.187E+08 Tb-160 3.994E+04 In 132 2.865E+05 La-140 2.246E+08 Dy-166 2.433E+03 Sb-132 6.0llE+07 Cs-141 1.488E+08 Ho-166 6.110E+03 Sb-132m 3.925E+07 Ba-141 2.052E+08 Rn-220 3.587E-02 Te-132 1.673E+08 La-141 2.061E+08 Ra-224 3.587E412 1-132 1.695E+ 08 Ce-141 2.085E+08 Th-228 3.565E-02 Cs-132 2.300E+04 Xc-142 1.286E+07 U-239 1.779E+09 Sn-133 6.105E +06 Cs-142 9.190E +07 Np-238 2.106E+07 q Sb-133 7.351E+07 Ba-142 1.970E +08 Np-239 1.777E+09 kj Te-133 1.433E+08 La-142 2.012E +08 Np-240m 3.7%E+05 Te-133m 9.593E+07 Pr-142 6.289E +06 Np-240 1.496E+ 06 l AMweved Desiger Matedet- AccMest Analyses (11/961 Page 15A-17
System 80+ Design ControlDocument Table 15A-1 Core Inventory (Cl)D3 (Cont'd.) Isotope Core Inventory Isotope Core Inventory Isotope Core Inventory I-133 2.467E +08 Pr-142m 1.343E+06 Np-241 3.266E-02 Xe-133 2.468E+08 Cs-143 4.671E+07 Pu-238 1.078E+05 Xe-133m 7.562E+06 Ba-143 1.750E+08 Pu-239 3.381E+04 Sn-134 6.989E+05 1.a-143 1.953E +08 Pu-240 4.168E+04 Sb-134 1.078E+07 Cc-143 1.%5E+08 Pu-241 7.866E+06 Te-134 2.161E+08 Pr 143 1.925E+08 Pu-242 5.753E+01 1-134 2.727E+08 Ba-144 1.351E+08 Pu-243 8.030E+06 I-134m 2.322E +07 12-144 1.742E+08 Am-239 4.674E-02 Cs-134 1.068E+07 Ce-144 1.567E+08 Am-241 6.120E+03 Cs-134m 4.101E +06 Pr-144 1.578E+08 Am-242m 3.263E +02 Sb-135 6.694E +06 Pr-144m 1.884E+06 Am-242 3.333E+06 Te-135 1.098E+08 Cc-147 7.906E+07 Am-243 3.177E+02 1-135 2.298E+08 Pr-147 8.ll8E+07 Am-24m 1.309E+06 Xe-135 6.333E+ 07 Nd-147 8.183E+07 Am-244 6.874E+04 Xe-135m 4.636E+07 Pm-147 1.968E +07 Cm-241 2.956E-01 Cs 135m 1.632E+06 Pm-148 3.136E+07 Cm-242 1.356E+06 Sb-136 1.205E+06 Pm-148m 3.966E +06 Cm-244 1.899E+04 Te-136 5.987E+07 Pr-149 4.230E+07 Cm 245 9.558E41 1-136 1.092E +08 Nd-149 4.399E+07 -- - Cs-136 4.123E +06 Pm-149 4.975E+07 - - Te-137 1.542E+07 Pr-151 1.429E +07 - - I-137 1.101E +08 Nd-151 2.086E +07 - - Xe-137 2.160E +08 -- -- - - l l l i l HI Calculated assuming :. power level of 3914 MWt, and a core average burnup of 28,000 MWD /MTU. An 1 uncertainty factor of 15% was included. The accident analysis used 102% of the above values to address ! instrument error per Reg Guide 1.49. Annroved Desigre Materiel. AccMent Ardyses (11/96) Page 15A-18
m o (V) (Vl I. V t System 80+ Design ControlDocument Table 15A-2A Gamma and Beta Average Energies per Nuclide (MeV/ dis) Isotope Gamma Beta 19stepe Gamma Beta Isotope Gamma Beta Isotope Gamma Iketa As-110 2.944 6-02 1.178E +00 Ar-110m 2.69s E+00 6.629E-02 Ag-l i t 2.605 E-02 3.50 t E-01 Ag-112 6.612 E-01 1.429E + 00 Am-241 2.80lE42 2.938E-02 An-76 4.226E-01 1.064E + 00 Ba-137m 5.978E41 6367E-02 Ba-139 3.330E-02 8.932E41 Ba-140 1.879E-O L 2.720E41 Ba-142 9.069E-Oi 4.554E-O n Br-82 2.640E + 00 1.360E-01 Br-83 6.885E43 3.200E41 Br-85 5.752E42 1.OOOE + 00 Ccwil5 2.099E42 3.125E-01 Cd-ll5m 2.037 E-01 6.062E-01 Ce-141 7.683E-02 1.447E-01 Ce-143 2.676E-04 4.098E41 Ce-144 1.920E42 8.323E-02 Cm-242 1.6456-03 7.530E-03 Cm-244 1.4 73E-03 6.454 E-03 Co-58 8.230v-01 3 UO4E-02 Cc-58m 4.032E-03 2.465E-02 Co-60 2.506E + 00 9.579E-02 Col 32 6.832E-01 7.927E44 Cs-134 1.555E + 00 1.568E41 Cs-134m 2.722E-02 1.080E-01 Cs-135m 1.616E44 0.000E + 00 Cs-136 2.166E + 00 1.001E-01 Cs-136m 0.toJE +00 0 000E+00 Cart 37 0.000E + 00 1.708 E-01 Cs-138 2334E+ 00 1.220E + 00 Cs-139 2.428 E-01 1.656E + 00 Cs-8 40 2.267E+00 2.046E + 00 Ee -154 8.242E +00 2.254E-01 Eu-155 6.051 E-02 6.198 E42 Eu-156 1.329E + 00 3.901 E-01 Eu-137 2.3 76E41 3.815E-01 Es -158 1.375E + 00 8.16 t E-U t Es-159 2.720E-01 8.510E-01 Ga-72 2.685E + 00 4.982 E-01 Gd-139 3.829E42 3.109E-01 Gr-77 1.033E + 00 6.448E-O n 11-3 0.000E + 00 5.685E-03 110-166 1.657 E + 00 4.059E-02 1-129 2.466E-02 4.090E42 1-L30 2.132L + 00 2.776E-01 1-131 3.80$E41 1.815E41 1-132 2.259E + 00 4.868E-01 1-133 6.0385-01 4.070E-01 1-W 34 2.602E + 00 6.076E-01 1-135 1.5576 + 00 3.683E-01 1-136 2.432E+00 2.020E + 00 in-il5m 1.592E 4)I 1.522E4I Kr83m 2.56 t E43 3.817E42 Kr-85 2.231E-03 2.500E-01 Kr-85m 9.946E-02 1.807 E-01 Kr-87 7.825E-O L 1.324 E + 00 Kr-88 1.93$ E + w 3.590E-01 Kr49 1.678E+00 1360+00 Kr-90 1.238E + 00 1.304 E + 00 12-140 2.3 tob + 00 5.274E-01 1A-14 4 3.749E-02 9.479E-Oi La-142 2.714E + 00 8.480E41 La-143 3.ll3E-02 1.471 E + 00 Mo-99 1.533b-01 3.935E41 Mo-101 1.454E+00 5.191E-01 N b-95 7.643 E-01 4.334E-02 Nb-95m 6.214E42 1.492E41 N b-97 6.608E-01 4.662E-01 N >-97m 7.284E-0 8 1437E-02 Nd-147 1.401E41 2.335E-On Np-239 1.715 E-01 1.150E-01 Pd-109 0.000E + 00 3.6065-01 Pm-147 0 000E+00 6.196E-02 Pm-148 5.708E41 7.260E-01 Pm-848m 1.905 E + 00 1.452E-01 Pm-149 9.787E-03 3.642E-01 Pm-151 3.177 E-01 2.836E-01 Pr-142 5.830E 02 8.085E41 Pr-143 0.000E + 00 3.156E41 Pr-144 3.161E-02 1.207 E + 00 Pu-238 1.578E-03 8.279E-03 Pu-239 5.984 E-04 4.88 t E-03 Pu-240 1.4%E-03 8.345E-03 Pu-241 0.UUOE + 00 5.230E-03 Pra-242 1.238E-03 6.849E43 Rb-86 9.453E-02 6.674E-01 Rb-88 6312E-01 2.070E + 00 Rb-89 2.042E + 00 1.015E + 00 R$-90 2.107E+00 1.963 E + 00 Rb-90m 3.176E + 00 1359E+ 00 Rh-103m 1.690E43 3.713E-02 Rh-105 7.744E42 1.523E4I Ra-105m 3.504E-02 1.027 E-O n Rh-lO6 1.994E-01 1.4 t l E + 00 Rn-220 5.497 E44 0.000E + 00 Ru-103 4.837E-01 6.740E-02 R.s-106 0.000E + 00 1.003 E-02 Sb-122 4.233E41 5.470E41 Sb-124 1.853E + 00 3.776E41 Sb-125 4.325E-01 8.641 E 02 S'-127 6.583 E-U n 3.I ll E-01 Sb-129 1.418E + 00 3.585 E-01 Sb-130 3.269E+00 1.326E+00 Sb-130m 2.700E + 00 1326E+00 S>l31 1.94 s E + 00 9.66oE-01 Sb-132 2.570E + 00 3.782E+00 Sb-132m 2.5 73E + 00 3.782E + 00 Sb-133 2.458E + 00 3.286E + 00 S$83 2.559E + 00 5.626E-01 Sm-153 6.045E-02 2.236E-01 Sn-121 0.000E +00 1.3%E-01 Sn-123 6.532E-03 5.203E-01 $+125 2.969E-01 8.049E-01 Sn-127 1.868 E + 00 6.200E-01 Sr-89 0.UUOE + 00 5.299E-01 l Sr-90 0.OU0E + 00 1.95LE-01 Sr-91 6.776E-01 6.532E-01 Sr-92 1.338E + 00 2.010E-01 St-93 2.014 E + 00 8.976E-01 SrM l .423E + 00 8.976E41 Tb-160 1.077E+00 2.263E41 Tc-99m 1.266E41 1.557E42 Tc-101 3.386E41 4.737E41 Tc-104 1.943 E + 00 1.564E + 00 1c-105 4.767E-01 1.519E+00 le-127 4.612E-03 2.229E-01 Te-127m 1.033E-02 7.455 E-02 Te-129 5.515E-02 5.224E-01 Te-129m 1.594E-02 135 t E-01 Te-131 4.122E-01 6.%7 E-O n Te-131m 1.089E +00 1.471E41 Te-132 2.307E41 9.840E-02 le-133 1.478E+00 8.100E41 Te-133m 1.914E + 00 5.859E-On Te-134 8.737E-01 1.466E-01 Th-228 2.881E-03 1.900E42 Ae-131m 2.008E42 1.422 E-01 Xe-133 4.519E-02 1.004E-01 Xe-133ni 4.146E-02 1.902E-Oi Xe-135 2.465E-01 3.030E-01 le-135m 4Jo?E-01 9.576E-02 Xe-137 1.695E41 1.774E+00 Xe-138 1.0466 + 00 6.100E41 Y-90 0.0000E + 00 9347E 0t Y-91 3.615E43 6.023E-01 Y-91m 5306E41 2.694 E-02 Y-92 2.492E-01 1.446E +00 Y-93 8.453 E-02 1.173E + 00 Y-94 7.725E-01 1.893E+00 Y-95 1.286E + 00 1.810E+00 Zr-95 7349E-01 1.16t E41 Zr-97 l.793E-01 6.975E-Ol - - - - - - - - - Approved Design Materlat - Accident Analyses (11/96) Page 15A-19 _ _ _ . _ _ - _-_ _ _ _ - _ L - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ . . _ _ _ - _ _ - . _ _ _ _ _ _ _ _ _ _ _ -
System 80+ Design Control Document Table 15A-2B Thyroid Dose Conversion Factors (DCF) Isotope Thyroid DCF Otem/CD l-131 1.43E+06 I-132 5.3. 5 +04 1-133 4.00E+05 I-134 2.50E+04 l-135 1.24E+05 Table 15A-3 Gap Activities (Curies) Isotope Curies Kr-85m 1.85E6 Kr-85 5.64E4 Xe-131m 6.49E4 Xe-133m 3.78E5 Xe-133 1.23E7 Xe-135m 2.32E6 Xc-135 3]L6 Br-82 2.10E4 I130 1.32E5 1-131 5.83E6 I-132 8.48E6 I-133 1.23E7 1-135 1.15E7 Cs-134 5.34E5 Cs-136 2.06ES Cs-137 5.39E5 Cs-138 1.16E7 Rb-88 5.17E6 RtrS9 6.68E6 O Approved Des % Mateniet Accident Analyses (11/96) Page 15A 20
, System 80+ Desian controlDocument (3 1 v) Table 15A-4 Primary Coolant Technical Specification Concentrations (pCi/gm) l Imdope pCi/gm I-131 6.63E-01 1-132 2.07E-01 1-133 1.03E+00 - I-134 1.46E41 1-135 5.84E-01 Br-83 1.24E-03 Br-84 5.84E42 Br-85 6.79E43 Kr-83m 5.21E-01 Kr-85 2.79E+00 Kr-85m 2.51E+00 Kr-87 1.58E+00 - Kr-88 4.62E+00 Kr-89 1.29E-01 e Xe-131m 2.07E+02 Xe-133 2.62E+02 Xc-133m 1.06E+00 ~ Xe-135 8.24E+00 Xe 135m 2.28E-01 Xe-137 2.70E-01 i Xe-138 9.50E-01 Rb-88 1.16E-01 Rb-89 1.30E-01 Sr-89 3.66E-03 St-90 2.35Ef4 St-91 2.32E-03 St-92 1.I1E-03 Y-90 3.43E-05 Y-9) 7.42E-04 Y-91m 3.56E-05 Y-92 2.18E-04 Y-93 4.60E-04 4prenn' Doe 4po nneeeniet Acoment Anotyree ti1AF6) Pere 15A-21
System 80+ Design controlDocument Table 15A-4 1% nary Coolant Technical Specification Concentrations (pCi/gm) (Cont'd.) h Isotope pCilgm Zr-95 9.24E-04 Nb-95 9.24E-04 Tc-99m 3.35E44 Mo-99 1.04E+00 Rh-103m 6.10E-05 Ru-103 6.98E-04 Ru-106 1.72E44 Te-129 1.08E42 Te-129m 1.38E-02 Te-131 1.25E-02 Te-131m 3.46E 02 Te-132 4.05E-01 Te-134 4.24E-02 Cs-134 6.54E-01 Cs-136 2.39E-01 Cs-137 6.35E-01 Cs-138 4.74E-01 Ba-137m 1.30E-06 Ba-139 8.17E-04 Ba-140 5.69E-03 La-140 7.92E-04 Ce-141 8.80E44 Cc-143 6.60E-04 Ce-144 6.67E-04 l't144 2.13E-05 Mn-54 1.01E-02 Co-58 2.89E-02 Co-60 3.33E-03 Fe-59 1.89E-03 Cr-51 1.95E-02 11-3 1.80E+01 O Anwavett Design Meterial- AccMent Anetyses (11/96) Page 15A-22
System 80+ Design ControlDocument i 4 4 (Aj Table 15A-5 Initial Iodine and Noble Gas Concentrations in the Steam Generator Isotope Liquid Concentration (pCl/gm) Steam ConcentrationU3 (pCi/gm) Kr-83m - - Kr-85 - 1.21 x 104 Kr-85m - 4.64 x 104 Kr-87 - 4.09 x 10 4 Kr-88 - 8.05 x 104 Xe-131m - 2.05 x 10-5 Xc-133m - 2.05 x 10 4 Xe-133 - 7.37 x 10-5 Xe-135m - 3.68 x 104 Xe-135 -- 2.46 x 10-5 Xe 138 - 3.41 x 10 4 I-131 4.74 x 10-2 4.74 x 10 d 1-132 8.15 x 10 2 8.15 x 104 I-133 1.26 x 10 3 1.26 x 10-3 1-134 6.30 x 10-2 6.30 x 104 ) (' I-135 1.73 x 10'8 1.73 x 10-3 03 Based on primary to secondary leak rate of I gpm. All values are obtained from NURECcv017, Rev.1 April,1985 (Reference 20), with an additional 20% uncertainty factor for conservatism. lodine , concentrations have been scaled to yield a concentration of 0.1 pCi/gm I-131 dose equivalent in the steam j generator liquid. Table 15A-6 Pre-Accident Iodine Spike Concentration in Reactor Coolant Isotope pCi/gmu l I-131 3.98E + 1 I-132 1.24E + 1 1-133 6.18E + 1 1-134 8.76E+0 j 1-135 3.50E+ 1 U3 60 times technical specification concentrations t V Spectrum is used only for the control room dose calculations and for the LOCA event. The 1-131 l maximum technical specification equivalent source is used for the site boundary dose calculation for those events which do not have fuel damage predicted. Nowowed DeeQn Manwial Acondent Andrees (1136) Pope 15A.23
System 80+ Design ControlDocument Table 15A-7 Generated Iodine Spike Appearance Ratesill Isotope C1/Sec l-131 2.16 I-132 3.12 1-133 4.58 1-134 5.04 1-135 4.25 l Table 15A-8 Breathing Rates for Adults (Reference 8) 8 Time from Start of Accident B(t) (m /sec) l Site d O to 8 hrs. 3.47 x 10 8 to 24 hrs. 1.75 x 104 4 1 to 30 days 2.32 x 10 Control Room 4 0 - 30 days 3.47 x 10 O Table 15A-9 Containtnent Data item value Volume, nomiel, ft 3 3,337,000 Sprayed volume, % 82 Transfer rate between sprayed unsprayed regions See Figure 6.5-4 Spray removal constant, hr8 See Figure 6.5-6 Maximum contaimneut power purge inte, CFM 16,000 Contamment leak rate See Section 15.6.5 181 500 times the equilibrium Appearance Rate Spectrum is used only for the control room dose calculations. The 1-131 technical specification equivalent soutre is used for the site boundary dose calculations for those events which do not have fuel damage predicted. Approwd Destys MaterW- AccMent Analyses (11/96) Page 15A.24 l
1 I i System 80+ Design ControlDocument \ Table 15A-10 Control Roorn Data Item Value Maumum post accident filtered air intaketi,21 rate, CFM 2,000 Maximum post accident unfiltered inleakage rate, CFM 10 Nominal, post accident filtered recirculation rate!21. CFM 4,000 Maximum unfiltered normal air intake rate, CFM 2,000 l Maximum post accident unfiltered inleakage during loss of pressutuation during 1,000 ; a LOOP, CFM Control Room nominal net free volume, ft3 67,300 Post accident intake and recirculating iodine filter efficiencies: elemental 0.95 organic 0.95 particulate 0.99 Control Room pressurization (w.g.) 1/8" Control Room occupancy factors 0 - 8 hours 1 8 - 24 hours 1 l 1 1 - 4 days 0.6 4 - 30 days 0.4 Ioss of Offsite Power Yes r 183 Filtered intake and recirculation is activated by either the SI signal or redundant safety related Control O Room intake radiation monitors located at each Control Room intake. 121 Total post accident flow through the Control Room emergency filters is 6000 cfm (i.e.,2000 cfm intake and 4000 cfm recirculation flow). Anprenef Deefon nieendel. AccMent Ana&oes 111/96) Page 15A-25
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O CHAPTER 16 TECHNICAL SPECIFICATIONS PREFACE Technical Specifications are explicit restrictions on the operation of a l commercial nuclear power plant. They are designed to preserve the validity of the plant safety analysis by ensuring that the plant is operated within the I required conditions bounded by the analysis, and by ensuring that equipment assumed to be available for accident mitigation is operable. Technical , . specifications preserve the primary success path relied upon to detect and ' respond to accidents. They also complement the concept of defense in depth. Section 182a of the Atomic Energy Act of 1954, as amended (the Act), 47 U.S.C. - 2011, at 2232, provides the legislative framework within which technical specifications are required. Section 182a of the Act requires in part: l "In connection with applications for licenses to operate production or utilization facilities, the applicant shall state such technical specifications, including information on the amount, ind, and source i of special nuclear material required, the place of use, the specific ' characteristics of the facility, and such other information as the ; Commission may, by rule or regulation, deem necessary in order to j (]- enable it to find that the utilizatio) or production of special nuclear material will... provide adecuate protection to the health and l i safety of the public. Such technical specifications shall be a part of any license issued." The regulatory framework implementing Section 182a of the Act is the NRC's l regulation 10 CFR 50.36, " Technical Specifications." This regulation provides in part that each operating license:
...will include technical specifications ...(to) be derived from the analysis and evaluation included in the safety analysis report, and amendments thereto...and may also include such additional technical siibcifications is the Commission ~f thds appropriate.'
This set of System 80+d" Standard Technical Specifications is based on NUREG-1432, Standard Technical Specifications, Combustion Engineering Plants, and establishes these conditions and limitations for the System 80+ Standard Design. This set of technical specifications is intended to be used as a guide in the NRC's development of the plant-specific technical specifications issued with the operating license. The values provided in brackets [ ] are preliminary. O i System S0+ is a trademark of Combustion Engineering, Inc. 1 f i SYSTEM 80+ Rev. 00 Tech Spec
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Effective Page Listing . Chapter 16 P Pages Date Pages Date Preface Original 3.8-1 2/95 i,ii. 1/97 3.8-2 Original iii - vi Original 3.8-3, 3.8-4 2/95 3.8-5 through 3.8-44 Original 1.1-1 through 1.1-11 Original- [ 3.9-1 through 3.9-11 Original i 1.2-1 through 1.2-3 Original 4.0-1 through 4.0-5 Original 1.3-1 through 1.3-12_ Original 5.0-1 through 5.0-7 Original 1.4-1 through 1.4-4 Original 5.0-8 11/% 5.0-9 2/95 2.0-1, 2.0-2 Original 5.0-10 through 5.0-13 Original G 5.0-14 1/97 : .U 3.0-1 through 3.0-5 Original 5.0-15 through 5.0-20 Original 2/95 I 5.0-21 3.1-1 through 3.1-33 Original 5.0-22 through 5.0-27 Original 5.0-28 2/95 3.2-1 through 3.2-10 Original 5.0-29 through 5.0-42 Original 3.3-1 through 3.3-64 Original 3.4-1 through 3.4-47 Original I 3.5-1 through 3.5-10 Original 3.5-11 11/96 3.5-12 through 3.5-14 Original 3.6-1 through 3.6-7 Original 3.6-8 2/95 3.6-9 through 3.6-27 Original 3.7-1 through 3.7-38 Original ! m 3.7-39, 3.7-40 2/95. 'l ( .) 3.7-41' Original Annerewed Dee6n Moserd Toewcer Eroencetone (t/97) rege 1. E l
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. TABLE 0F: CONTENTS I
- i. l '. 0 ' USE AND APPLICATIONS . . . . . . ... . . . . . . . . . . ... .
1.1-1 l ~ 1.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . 1.1 ; 1.2 Logi cal Connectors . . . . . . . . . . . . . . . . . . . . . 1.221 i
- 1.3 Completion Times . . . . . . . . . . . . . . . . . . . . . 1.3-1 l
} 1.4 Frequency ................:......... 1.4-1 ; 4 q L2.0 SAFETY LIMITS.(SLs) ..................... 2.0-1 l
- t. 2.1 . Safety Limits . . . . . . . . . . ... . . . . . . . ... . 2.0-1 t i 2.2 ' Safety' Limit Violations ................. 2.0-2 .;
l 4 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY . . . . . 3.0 l F 3.0 3.0-4 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ......... l 3.1- REACTIVITY CONTROL SYSTEMS . . . . . . . . . . . . . . . . . . 3.1-1 ! 4 3.1.1 SHUTDOWN MARGIN (SDM) .................. 3.1-1
- 3.'1.2 Reactor Trip Circuit Breakers (RTCB) . . . . . . . . . . . 3.1-2 i
- 3.1 3 Reactivity' Balance . . . . . . . . . . . . . . . . . . . . 3.1-3 1 Moderator Temperature Coefficient (MTC) 3.1.4 ......... 3.1-5 4-3.1.5 Control Element Assembly (CEA) Alignment . . . . . . . . . 3.1-7 ,
3.1.6 Shutdown Control Element Assembly (CEA) Insertion Limitt . 3.1-12 1
- - 3.1.7 Regulating Control ~ Element Assembly (CEA) Insertion Limits. 3.1-14 J 3.1 ~. 8 Part Strength Control Element Assembly (CEA) Insertion i Limits . . . . . . . . . . . . . . . . . . . . . . . . . 3.1-18 3.1.9 Special Test Exception-(STE)-SHUTDOWN MARGIN (SDM) . . . 3.1-20 3.1.10 .Special Test Exceptions (STE)-NODES I and 2 . . . . . . 3.1-22 3.1.11 Special Test Exception - CEDMS Testing . . . . . . . . . 3.1-24 p _3.1.12 Boron Dilution Alarms . . . . . . . . . . . . . . . . . 3.1-26 4
3.2 POWER DISTRIBUTION LIMITS .................. 3.2-1 l 3.2.1 Linear Heat Rate (LHR) . . . . . . . . . . . . . . . . . . 3.2-1 j 3.2.2. Planar Radial- Peaking Factors (Fu) ........... 3.2-3 j 3.2.3 AZIMUTHAL POWER TILT (T,) ................ 3.2-5 I i ;3.2.4 Departure From Nucleate Boiling Ratio (DNBR) . . . . . . . 3.2-8 l 3.2.5 AXIAL SHAPE INDEX (ASI) . , , , , . . . . , , . . . . 3.2-10 1 i 3.3 INSTRUMENTATION ....................... 3.3-1 3.3.1 Reactor Protective System (RPS) Instrumentation -. Operating 3.3-1 l 3.3.2 Reactor Protective System (RPS) Instrumentation - Shutdown 3.3-13
; 3.3.3 Control Element Assembly Calculators (CEACs) . . . . . . 3.3-20
? 3.3.4 Reactor Protective System (RPS) Logic and Trip Initiation 3.3-23 3' 3.3.5 Engineered Safety Features Actuation System (ESFAS)
. . . Instrumentation . . . . . . . . . . . . . . . . .'. . . 3.3-26
..3.3.6 . Engineered Safety Features Actuation System (ESFAS) l
- Logic:and Manual Initiation . . . . . . . . . . . . . . 3.3-32 3.3.7 Diesel Generator (DG) ~- Loss'of Voltage Start (LOVS) . . 3.3-37 !
13.3.8. Alternate Protection System (APS) . . . . . . . . . . . 3.3-40 i i (continued) -) ; a m SYSTEM 80+- -iii Rev. 00
. Tech Spec y ;
1 l l l i l TABLE OF CONTENTS 3.3 INSTRUMENTATION (continued) 3.3.9 Control Room Intake / Filtration Signal (CRIFS) . . . . . 3.3-43 ' 3.3.10 Containment Bypass Instrumentation Steam Generator i Tube Rupture (SGTR) . . . . . . . . . . . . . . . . . . 3.3-46 ' 3.3.11 Post Accident Monitoring Instrumentation (PAMI) . . . . 3.3-49 ; 3.3.12 Remote Shutdown Instrumentation and Controls . . . . . . 3.3-52 1 3.3.13 Logarithmic Power Monitoring CHANNELS . . . . . . . . . 3.3-57 ( 3.3.14 Reactor Coolant Monitoring - Instrumentation . . . . . . 3.3-59 ! 3.4 REACTOR COOLANT SYSTEM (RCS) ................. 3.4-1 3.4.1 RCS Pressure, Temperature, and Flow Limits . . . . . . . . 3.4-1 3.4.2 RCS Minimum Temperature for Criticality ......... 3.4-4 3.4.3 RCS Pressure and Temperature (P/T) Limits ........ 3.4-5 3.4.4 RCS Loops - MODES 1 and 2 . . . . . . . . . . . . . . . 3.4-10 3.4.5 RCS Loops - MODE 3 . . . . . . . . . . . . . . . . . . . 3.4-11 3.4.6 RCS Loops - MODE 4 . . . . . . . . . . . . . . . . . . . 3.4-13 3.4.7 RCS Loops - MODE 5 (Loops Filled) . . . . . . . . . . . 3.4-16 3.4.8 RCS Loops - MODE 5 (Loops Not Filled) . . . . . . . . . 3.4-19 3.4.9 Pressurizer . . . . . . . . . . . . . . . . . . . . . . 3.4-22 l 3.4.10 Pressurizer Safety Valves . . . . . . . . . . . . . . . 3.4-24 l 3.4.11 Low Temperature Overpressure Protection (LTOP) System . 3.4-26 3.4.12 RCS Operational LEAKAGE . . . . . . . . . . . . . . . . 3.4-28 3.4.13 RCS Pressure Isolation Valve (P1V) Leakage . . . . . . . 3.4-30 3.4.14 RCS LEAKAGE Detection Instrumentation . . . . . . . . . 3.4-33 3.4.15 RCS Specific Activity . . . . . . . . . . . . . . . . . 3.4-36 3.4.16 RCS Loops - Test Exception . . . . . . . . . . . . . . . 3.4-40 3.4.17 Reactor Coolant Gas Vent System . . . . . . . . . . . . 3.4-42 3.4.18 Rapid De)ressurization Function . . . . . . . . . . . . 3.4-44 3.4.19 Vent Patis - REDUCED RCS INVENTORY Operations . . . . . 3.4-46 3.5 EMERGENCY CORE COOLING SYSTEM (ECCS) ............. 3.5-1 3.5.1 Safety Injection Tanks (SITS) .............. 3.5-1 3.5.2 Safety Injection System (SIS) - Operating ........ 3.5-4 3.5.3 Safety Injection System (SIS) - Shutdown . . . . . . . . . 3.5-7 3.5.4 In-containment Refueling Water Storage Tank (IRWST) ... 3.5-9 3.5.5 Trisodium Phosphate (TSP) . . . . . . . . . . . . . . . 3.5-12 3.5.6 Cavity Flooding System (CfS) . . . . . . . . . . . . . . 3.5-13 3.6 CONTAINMENT SYSTEMS ..................... 3.6-1 3.6.1 Containment ....................... 3.6-1 3.6.2 Containment Air Locks .................. 3.6-2 3.6.3 Containment Isolation Valves . . . . . . . . . . . . . . . 3.6-7 3.6.4 Containnent Pressure . . . . . . . . . . . . . . . . . . 3.6-13 3.6.5 Containment Air Temperature . . . . . . . . . . . . . . 3.6-14 3.6.6 Containment Spray System . . . . . . . . . . . . . . . . 3.6-15 3.6.7 Hydrogen Analyzers . . . . . . . . . . . . . . . . . . . 3.6-17 3.6.8 Shield Building . . . . . . . . . . . . . . . . . . . . 3.6-19 3.6.9 Annulus Ventilation System . . . . . . . . . . . . . . . 3.6-21 (continued) SYSTEM 80+ iv Rev. 00 Tech Spec
TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS (continued) 3.6.10 Hydrogen Mitigation System (HMS) Igniters . . . . . . . 3.6-23 3.6.11 Containment Penetrations - REDUCED RCS INVENTORY Operati on s . . . . . . . . . . . . . . . . . . . . . . . 3. 6-26 3.7 PLANT SYSTEMS ........................ 3.7-1 3.7.1 Main Steam Safety Valves (MSSVs) . . . . . . . . . . . . . 3.7-1 . 3.7.2 Main Steam isolation Valves (MSIVs) ........... 3.7-5 3.7.3 Main Feedwater Isolation Valves (MFIVs) ......... 3.7-7 3.7.4 Emergency Feedwater (EFW) Systes ............ 3.7-9 3.7.5 Emergency Feedwater Storage Tank FWST) . . . . . . . . 3.7-12 3.7.6 Secondary Specific Activity . . . . . . . . . . . . . . 3.7-14 3.7.7 Component Cooling Water (CCW) System . . . . . . . . . . 3.7-15 3.7.8 Station Service Water System (SSWS) . . . . . . . . . . 3.7-18 3.7.9 Ultimate Heat Sink (UHS) . . . . . . . . . . . . . . . . 3.7-20 3.7.10 Fuel Storage Pool Water Level . . . . . . . . . . . . . 3.7-22 3.7.11 Atmospheric Dump Valves (ADVs) . . . . . . . . . . . . . 3.7-23 3.7.12 Control Complex Ventilation System (CCVS) . . . . . . . 3.7-25 3.7.13 Control Room Ventilation System (CRVS) . . . . . . . . . 3.7-28 3.7.14 Subsphere Building Ventilation Systam (SBVS) . . . . . . 3.7-30 ; 3.7.15 Fuel _ Building Ventilation Exhaust System (FBVES) . . . . 3.7-32 3.7.16 Diesel Building Ventilation System (DBVS) . . . . . . . 3.7-34 3.7.17 Essential Chilled Water System (ECWS) ........ . 3.7-36 1 O 3.7.18 3.7.19 3.7.20 MAIN STEAM LINE LEAKAGE Fuel Storage Pool Boron Concentration Spent Fuel Assembly Storage . . . . . . . 3.7-37 3.7-38 3.7-40 3.8 ELECTRICAL POWER SYSTEMS . . . . . . . . . . . . . . . . . . . 3.8-1 3.8.1 AC Sources - Operating . . . . . . . . . . . . . . . . . . 3.8-1 3.8.2 AC Sources - Shutdown . . . . . . . . . . . . . . . . . 3.8-17 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air . . . . . . 3.8-23 3.8.4 DC Sources - Operating . . . . . . . . . . . . . . . . . 3.8-26 3.8.5 DC Sources - Shutdown . . . . . . . . . . . . . . . . . 3.8-31 3.8.6 Battery Cell Parameters . . . . . . . . . . . . . . . . 3.8-33 3.8.7 Inverters - Operating . . . . . . . . . . . . . . . . . 3.8-37 3.8.8 Inverters - Shutdown . . . . . . . . . . . . . . . . . . 3.8-39
- 3.8.9 Distribution Systems - Operating . . . . . . . . . . . . 3.8-41 3.8.10 Distribution Systems - Shutdown . . .. . . . . . . . . . 3.8-43 3.9 REFUELING OPERATIONS ..................... 3.9-1 3.9.1 Boron Concentration ................... 3.9-1
. 3.9.2 Nuclear Instrumentation ................. 3.9-2 3.9.3 Containment Penetrations . . . . . . . . . . . . . . . . . 3.9-4 3.9.4 Shutdown Cooling System (SCS) and Coolant Circulation
- High Water Level . . . . . . . . . . . . . . . . . . . . 3.9-6 3.9.5 Shutdown Cooling System (SCS) and Coolant Circulation
- Low Water Level .................... 3.9-8 3.9.6 Refueling Water Level . . . . . . . . . . . . . . . . . 3.9-11 (continued)
SYSTEM 80+ v Rev. 00 Tech Spec
TABLE OF CONTENTS (continued) 4.0 DESIGN FEATURES ....................... 4.0-1 4.1 Site . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.0-1 4.2 Reactor Core . . . . . . . . . . . . . . . . . . . . . . . 4.0-1 4.3 Fuel Storage . . . . . . . . . . . . . . . . . . . . . . . 4.0-2 5.0 ADMINISTRATIVE CONTROLS ................... 5.0-1 5.1 Responsibility . . . . . . . . . . . . . . . . . . . . . . 5.0-1 5.2 Organization . . . . . . . . . . . . . . . . . . . . . . . 5.0-2 5.3 Unit Staff Qualifications ................ 5.0-6 5.4 Training . . . . . . . . . . . . . . . . . . . . . . . . . 5.0-7 5.5 Reviews and Audits . . . . . . . . . . . . . . . . . . . . 5.0-8 5.6 Technical Specifications (TS) Bases Control . . . . . . 5.0-14 5.7 Procedures, Programs, and Manuals . . . . . . . . . . . 5.0-15 5.8 Safety Function Determination Program (SFDP) . . . . . . 5.0-29 5.9 Reporting Requirements . . . . . . . . . . . . . . . . . 5.0-31 5.10 Record Retention . . . . . . . . . . . . . . . . . . . . 5.0-37 5.11 [High Radiation Area] . . . . . . . . . . . . . . . . . 5.0-39 O O SYSTEM 80+ vi Rev. 00 Tech Spec
1 i Definitions
/G 1.1 1.0 .USE AND APPLICATIONS 1.1 Definitions j
------------------ i
------------------------------------NOTE-------------------
The defined terms of this section appear in capitalized t>se and are ! applicable throughout these Technical Specifications and Bases. ItDD Definition !! ACTIONS ACTIONS shall be that part of a Specifit.a@n thr.t prescribes Required Actions to be taken under designated Conditions within specified Completion Times. ACTUATION LOGIC ACTUATION LOGIC is defined as a set of interconnected hardware and software components i that process initiation inputs received from the LOGIC CHANNEL to produce an ESF actuation signal within a division. This includes the initiation l signal's associated selective 2-out-of-4 voters. 1 AXIAL SHAPE INDEX (ASI) ASI shall be the power generated in the lower half b of the core less the power generated in the upper half of the core, divided by the sum of the power generated in the lower and upper halves of the Core. lower - udder ASI = lower + upper AZIMUTHAL POWER TILT (T,) AZIMUTHAL POWER TILT shall be the power asymmetry between azimuthally symmetric fuel assemblies. CHANNEL CHANNEL is an arrangement of components and modules that generates a single protective action signal when required by a generating station condition. A CHANNEL is comprised of the cascaded elements of a TRIP CHANNEL, LOGIC CHANNEL, and ACTUATION LOGIC, as applicable. CHANNEL CALIBRATION A Ci'ANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy 1 (continued) SYSTEM 80+ 1.1-1 Rev. 00 16.1 Tech Spec
Definitions 1.1 1.1 Definitions CHANNEL CALIBRATION to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass (continued) the entire channel, including the required sensor, alarm, and trip functions, and shall include the CHANNEL FUNCTIONAL TEST. Calibration of instrument channels with resistance temperature detector (RTD) or thermocouple sensors shall consist of an in-place cross calibration of the sensing elements and normal calibration of the remaining adjustable devices in the channel. Whenever a sensing element is replaced, the next required in-place cross calibration consists of comparing the othcr sensing elements with the recently installed sensing element. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is calibrated. A CHANNEL CHECK shall be the qualitative CHANNEL CHECK assessment, by observation, of channel behavior & during operation. This determination shall W include, where possible, comparison of the channel indicatior, and status to other indications or status derived from independent instrument channels measuring the same parameter. CHANNEL FUNCTIONAL TEST A CHANNEL FUNCTIONAL TEST is defined as the manipuiation of a channel input condition to exercise its output in order to verify the OPERABILITY of the channel. A CHANNEL FUNCTIONAL TEST may be applicable to a TRIP CHANNEL, LOGIC CHANNEL, ACTUATION LOGIC, MEASUREMENT CHANNEL, or Instrument CHANNEL. For CHANNEL FUNCTIONAL TEST, the following applies:
- a. Analog CHANNELS - the injection of a simulated or actual signal into the channel as close to the sensor as practicable to verify OPERABILITY, including required alarms, interlocks, display and trip functions; (continued)
SYSTEM 80+ I.1-2 Rev. 00 16.1 Tech Spec
Definitions , g 1.1 U l.1 Definitions i CHANNEL FUNCTIONAL TEST b. Binary CHANNELS (e.g., pressure switches and (continued) switch contacts) - the injection of a , simulated or actual signal into the channel as close to the sensor as practicable to l verify OPERABILITY, including required alarms, interlocks, displays, and trip l functions; or i
- c. Computer CHANNELS - the use of diagnostic programs to test digital computer hardware and the injection of process data into the channel to verify OPERABILITY, including alarms, interlocks, displays and trip l functions. ,
The CHANNEL FUNCTIONAL TEST may be performed by l means of any series of sequential, overlapping, or total channel steps so that the entire CHANNEL is i tested. , I COMPONENT CONTROL LOGIC COMPONENT CONTROL LOGIC is defined for ESF logic , . - functions as a set of interconnected hardware and software components which process inputs from the ACTUATION LOGIC to produce plant component control functions. This logic is implemented within the programming software for all component control ! functions including ESF components. ! CORE ALTERATION CORE ALTERATION shall be the motement or manipulation of any fuel, sou.us, reactivity control component 3, or other components (excluding , CEAs withdrawn into the upper guide structure] ' affecting reactivity within the reactor vessel with the vessel head removed and fuel in the ! vessel. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position. CORE OPERATING LIMITS The COLR is the unit specific document that REPORT (COLR) provides core operating limits for the current reload cycle. These cycle specific core operating limits shall be determined for each reload cycle : in accordance with Specification 5.9.1.6. Plant - operation within these core operating limits is : addressed in individual Specifications. l (continued) 4 SYSTEM 80+ 1.1-3 Rev. 00 l 16.1 Tech Spec I
Definitions 1.1 1.1 Definitions (continued) DIVERSE MANUAL DIVERSE MANUAL ESF ACTUATION CHANNEL is defined as ESF ACTUATION CHANNEL a channelized manual initiation switch and related signal wiring which is used to provide diverse manual actuation of ESF components in selected divisions. A DIVERSE MANUAL ESF ACTUATION CHANNEL is channelized, independent and diverse from the TRIP CHANNEL, LOGIC CHANNEL, and ACTUATION LOGIC. DOSE EQUIVALENT I-131 DOSE EQUIVALENT I-131 shall be that concentration of I-131 (microcuries/ gram) that alone would produce the same thyroid dose as the quantity and isotopic mixture of I-131, I-132, I-133,1-134, andI-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, AEC, 1962 " Calculation of Distance Factors for Power and Test Reactor Sites" [or those listed in table E-7 of Regulatory Guide 1.109, Rev. 1, NRC, 1977). 4 E - AVERAGE E shall be the average (weighted in proportion to DISINTEGRATION ENERGY the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives greater than [15] minutes, making up at least 95% of the total non-iodine activity in the coolant. ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time interval FEATURE (ESF) RESPONSE TIME from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the i ESF equipment is capable of performing its safety j function (i.e., the valves travel to their l required positions, pump discharge pressures reach their required values, etc.). Times shall include ! diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. l K,., K ., is the K effective calculated by considering the actual CEA configuru. ion and assuming that the fully or partially inserted full-strength CEA of the highest inserted worth is fully withdrawn. (continued) I
- 5. 1EM 80+ 1.1-4 Rev. 00 16.1 Tech Spec
O Definitions 7 1.1 k 1.1 Definitions (continued) LEAKAGE LEAKAGE shall be: ,
- a. Identified LEAKAGE
- 1. LEAKAGE, such as that from pump seals or valve packing (except RCP water seal injection or leakoff), that is captured and conducted to collection system or a sump or collecting tank, j
- 2. LEAKAGE into the containment atmosphere from sources that are both specifically :;
located and known either not to interfere with the operation of LEAKAGE detection systems or not to be Pressure Boundary LEAKAGE, or >
- 3. Reactor Coolant System (RCS) LEAKAGE ,
through a steam generator (SG) to the ; Secondary System. , O V b. Unidentified LEAKAGE All leakage which is not identified LEAKAGE.
- c. Pressure Boundary LEAKAGE LEAKAGE (except SG tube LEAKAGE) through a non-isolable fault in an RCS component body, pipe wall, or vessel wall.
LOGIC CHANNEL LOGIC CHANNEL is defined as a set of interconnected hardware and software components that process inputs from the TRIP CHANNELS to produce an identifiable trip initiation signal or ESF initiation signal within a division. This includes the initiation signal's associated LCD two-out-of-four voters, data transmission, software, trip channel bjpass, and MANUAL TRIP CHANNEL function for RPS and MANUAL INITIATION CHANNEL function for ESF. MAIN STEAM MAIN STEAM LINE LEAKAGE shall be leakage inside LINE LEAKAGE containment in any portion of the four (4) 28" I.D. main steam line pipe walls. (continued) SYSTEM 80+ 1.1-5 Rev. 00
'16.1 Tech Spec
Definitions 1.1 l 1.1 Definitions (continued) MANUAL INITIATION CHANNEL MANUAL INITIATION CHANNEL is defined as a channelized manual initiation switch and CHANNEL related signal wiring which is used to provide system level manual initiation of an ESF function. MANUAL TRIP CHANNEL MANUAL TRIP CHANNEL is defined as a channelized manual actuation switch and related signal wiring which is used to provide system level RPS manual trip of a channelized reactor trip circuit breaker. MEASUREMENT CHANNEL MEASUREMENT CHANNEL is defined as the equipment required to detect input signal information including sensor, transmitter, signal conditioning and communication device (s). A MEASUREMENT CHANNEL is comprised of the sensor, transmitter, and signal conditioning devices. MID-LOOP MID-LOOP is defined as the plant condition with fuel in the reactor vessel and reactor coolant level below the top of the hot legs at their junction with the reactor vessel. MODE A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in reactor vessel. OPERABLE - OPERABILITY A system, subsystem, division, train, component or device shall be OPERABLE when it is capable of performing its specified safety function (s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, division, train, component or device to perform its specified function (s) are also capable of performing their related support function (s). O (continued) SYSTEM 80+ 1.1-6 Rev. 00 l 16.1 Tech Spec
Definitions 1.1 ,s 1.1 Definitions (continued) PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related information. These tests are:
- a. Described in Chapter [14, Initial Test Program] of the CESSAR-DC;
- b. Authorized under the provisions of 10 CFR 50.59; or
- c. Otherwise approved by the Nuclear Regulatory Commission.
PRESSURE AND The PTLR is the unit specific document that TEMPERATURE LIMITS provides the reactor pressure and temperature REPORT (PTLR) limits, including heatup and cooldown rates, for the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.9.1.7. Plant operation pJ within these operating limits is addressed in individual Specifications. RATED THERMAL POWER (RTP) RTP shall be a total reactor core heat transfer rate to the reactor coolant of [3914] MWt. REACTOR PROTECTION The RPS RESPONSE TIME shall be that time interval SYSTEM (RPS) RESPONSE TIME from when the monitored parameter exceeds its RPS trip setpoint at the channel sensor until electrical power to the control element assemblies (CEAs) drive mechanism is interrupted. The response time may be measured by*means of any series of sequential, overlapping, or total steps so the entire response time is measured. REDUCED RCS INVENTORY REDUCED RCS INVENTORY is the plant condition when the reactor coolant system level is below the [117' elevation] and fuel is in the reactor vessel. (The [117' elevation] corresponds to three feet below the reactor vessel flange.) ("'\ L.) (continued) SYSTEM 80+ 1.1-7 Rev. 00 16.1 Te h Spec
Definitions 1.1 O 1.1 Definitions (continued) SHUTDOWN MARGIN (SDM) SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:
- a. All full length Control Element Assemblies (CEAs) (shutdown and regulating) are fully inserted except for the single CEA of highest reactivity worth which is assumed to be fully withdrawn. However, with all CEAs verified fully inserted by two independent means, it is not necessary to account for a stuck CEA in the SDM calculation,
- b. In MODES 1 and 2, the fuel and moderator temperature are changed to the [ nominal zero power design level].
With any CEAs not capable of being fully inserted, the reactivity worth of the-se CEAs must be accounted for in the determination of SDM. STAGGERED TEST BASIS A STAGGERED TEST BASIS shall consist of the testing of one of the systems, subsystems, channels, or other designated components during the interval specified by the Surveillance Frequency, so that all systems, subsystems, CHANNELS, or other designated components are tested during n Surveillance Frequency intervals, where n is the total number of systems, subsystems, components, or other designated components in the associated function. THERMAL POWER THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant. TRIP CHANNEL A TRIP CHANNEL is defined as a set of interconnected hardware and software components that process an identifiable sensor signal to produce the trip or alarm signal associated with the sensor. This includes the sensor, data acquisition, signal conditioning, data transmission, software and all transmission lines 1 (continued) SYSTEM 80+ 1.1-8 Rev. 00 16.1 Tech Spec l l
- . - - - . . .. . - . - . - - - .- - - = . . - - - - -. --
i l
', l ' Definitions :
1.1 h 1.1 Definitions ! 4
- i. f
~ TRIP CHANNEL and operating bypasses associated with the sensor (continued) signal up to an input of. a two-out-of-four voter. There are three types of TRIP CHANNELS: !
- a. Analog TRIP CHANNEL An Analog TRIP CHANNEL is defined as the .
I equipment required to detect and digitize analog signal information including sensor ' 1 (e.g., pressure sensor), signal conditioning device, multiplexer, A/D convertor, trip , comparator, and communication device (s).
- b. Binary TRIP CHANNEL l
A Binary TRIP CHANNEL is defined as the equipment required to detect binary signal information including sensor (e.g., pressure , 1 switch), signal conditioning device, multiplexer, trip comparator, and ; communication device (s).
- c. Computer TRIP CHANNEL 1 A Computer TRIP CHANNEL is defined as the equipment required to detect and digitize ,
input signal information including sensor (e.g., neutron flux detector), signal conditioning device, multiplexer, A/D . convertor, software, and communication ! device (s). TRIP LEG A TRIP LEG is defined as the " logical or" '. combination of channel states which represent half ; of a Selective two-out-of-four Logic function. When both TRIP LEGS of a Selective two-out-of-four Logic function assume a true state, the output of the Selective two-out-of-four Logic function assumes a true state (e.g., in a Selective two-out-of-four Logic [(A "or" C) "and" (B "or" D) = ; N]; the term (A "or" C) is a TRIP LEG, the term (B ,
"or" D) is a TRIP LEG, and N is the output). j o (continued) 1 SYSTEM 80+ 1.1-9 Rev. 00 :
-16.1 Tech Spec !
Definitions 1.1 0 1.1 Definitions.(continued) A TRIP TEST is defined as the selective opening of TRIP TEST two (2) reactor trip circuit breakers to verify that initiation of MANUAL TRIP CHANNELS removes power from the control rod drives. The TRIP TEST is initiated by means of MANUAL TRIP CHANNEL manual actuation switches. O O SYSTEM 80+ 1.1-10 Rev. 00 16,1 Tech Spec
1 Definitions 1.1 Table 1.1-1 (Page 1 of 1) MODES ; REACTIVITY % RATED AVERAGE REACTOR MODE TITLE CONDITION, THERMAL COOLANT (K;,,) POWERla). TEMPERATURE (*F) 1 Power Operation = 0.99 >5 NA 2 Startup a 0.99 s5 NA 3 Hot Standby < 0.99 NA = [350] 4 Hot Shutdown (b) < 0.99 NA [350] > T ,> [210] . 5 Cold Shutdown (b) < 0.99 NA s [210] l 6 Refueling (c) NA NA NA (a) Excluding decay heat. (b) All reactor vessel head closure bolts fully tensioned. l (c) One or more reactor vessel head closure bolts less than fully tensioned. 1 I O SYSTEM 80+ 1.1-11 Rev. 00 16.1 Tech Spec . l
i Logical Connectors . 1.2 l
.h # 1.0 USE AND APPLICATION l
1.2 Logical ',onnectors PURPOSE The purpose of this section is to explain the meaning of logical connectors. Logical connectors are used in Technical Specifications (TS) to discriminate between, and yet connect, discrete Conditions, Required Actions, Completion Times, Surveillances and Frequency. The only logical connectors that appear in TS are A_lQ and 98 The physical arrangement of these connectors constitute logical l conventions with specific meaning. l BACKGROUND Several levels of logic may be used to state Required Actions. These levels are identified by the placement (or nesting) of the logical connectors and by number assigned to each Required Action. The first level of logic is identified by the first digit of the number assigned to a Required Action and the placement of the logical connector in the first level of nesting (i.e., left justified with the number of the Required Action). The successive levels of logic are . identified by additional digits of the Required Action i pd number and by successive indentions of the logical I connectors. When logical connectors are used to state a Condition, only the first level of logic is used, and the logical connector is left justified with the Condition statement. When logical connectors are used to state a Completion Time, Surveillance, or Fregt.ency, only the first level of logic is used, and the logical connector is left justified with the statement of the Completion Time, Surveillance, or Frequency. EXAMPLES The following examples illustrate the use of logical connectors.
,O
>V (continued) SYSTEM 80+ 1.2-1 Rev. 00 16.1 Tech Spec-
Logical Connectors 1.2 0> 1.2 Logical Connectors EXAMPLES fJg PLE 1.2-1 (continued) ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. LCO not met. A.1 Verify AND A.2 Restore In this example the logical connector AND is used to indicate that when the Condition A, both required Action A.1 and A.2 must be completed. O EXAMPLE 1,2-2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. LCO not met. A.1 Trip... 98 A.2.1 Verify... 6N_Q A.2.2.1 Reduce... 9.8 (continued) , O SYSTEM 80+ 1.2-2 Rev. 00 16.1 Tech Spec
- . . --..-.~ . _ . . . - . _ - - . . . - - . . . - . . - - . -
l l Logical Connectors 'i 1.2 ! ,f - .j e
-1.2 Logical Connectors 4
i EXAMPLES EXAMPLE 1.2-2 (continued) i ACTIONS 4 CONDITION REQUIRED ACTION COMPLETION TIME 1, i A.2.2.2 Perform... I A. (continued) L !
!, A.3 Align... ;
4 j i j This example represents a more complicated use of' logical j - connectors. Required Actions A.1, A.2, and A.3 are E alternative choices only one of which must be performed as ~ indicated by the use of the logical connector 2 and the : left justified placement. Any one of these three Actions i may be chosen. If A.2 is chosen, then both A.2.1 and A.2.2 4 f O must be performed as indicated by the indented position of the logical connector 8@. Required Action A.2.2 is met by performing A.2.2.1 o- A.2.2.2. The indented position of the i logical connector E indicates that A.2.2.1 and A.2.2.2 are - alternative choices, only one of which must be performed. ! i i i i i l; i t O :
' SYSTEM 80+i 1.2-3 Rev. 00 ;
16.1-Tech Spec :
.a .;
4 , n., + r-- ,.
Completion Times /"'; 1.3 \ 1 1.0 USE AND APPLICATION 1.3 Completion Times PURPOSE The purpose of this section is to establish the Completion l Time convention and to provide guidance for its use. BACKGROUND LCOs specify minimum requirements for ensuring safe operation of the unit. The ACTIONS associated with an LC0 state Conditions that typically describe the ways in which the requirements of the LC0 can fail to be met. Specified with each stated Condition are Required Action (s) and Completion Time (s). DESCRIPTION The Completion Time is the amount of time allowed for completing a Required Action. It is referenced to the time of discovery of a situation, (e.g. inoperable equipment or variable not within limits) that requires entering an ACTIONS Condition, unless otherwise specified, providing the [-mj unit is in a MODE or specified condition stated in the I i
'v Applicability of the LCO. Required Actions must be completed prior to the expiration of the specified Completion Time.
An ACTIONS Condition remains in effect and the Required Actions apply until the Condition no longer axists or the unit is not within the LC0 Applicability. If situations are discussed that require entry into more than one Condition at a time within a single LC0 (multiple Conditions), the Required Actions for each Condition must be performed within the associated Completion Time. When in multiple Conditions, separate Completion Times are tracked for each Condition starting from the time of discovery of the situation that required entry into the Condition. Once a Condition has been entered, subsequent divisions, trains, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition, unless specifically stated. The Required Actions of the Condition continue to apply to each additional failure, with Completion Times based on initial entry into the Condition. 7 i I %.J (continued) SYSTEM 80+ 1.3-1 Rev. 00 16.1 Tech Spec
Completion Timas 1.3 1.3 Completion Times . DESCRIPTION However, when a 1@youent division, train, subsystem, (continued) component, or variable expressed in the Condition is discovered to be inoperable or not within limits, the Completion Times may be extended. To apply this Completion Time extension, two criteria must first be met. The subsequent inoperability:
- a. Must exist concurrent with the first inoperability; and
- b. Must remain inoperable or not within limits after the first inoperability is resolved.
The total Completion Time allowed for completing a Required Action to address the subsequent inoperability shall be limited to the more restrictive of either:
- a. The stated Completion Time, as measured from the initial entry into the Condition, plus an additional 24 hours; or
- b. The stated Completion Time as measured from discovery of the subsequent inoperability.
The above Completion Time extensions do not apply to those ) Specifications that have exceptions that allow completely separate re-entry into the Condition (for each division, train, subsystem, component, or variable expressed in the Condition) and separate tracking of Completion Times based on the re-entry. These exceptions are stated in individual Specifications. The above Completion Time extension does not apply to a Completion Time with a modified " time zero." This modified
" time zero" may be expressed as a repetitive time (i.e.,
"once per 8 hours," where the Completion Time is referenced from a previous completion of the Required Action versus the time of Condition entry) or as a time modified by the phrase "from discovery..." Example 1.3-3 illustrates one use of this type of Completion Time. The 10 day Completion Time specified for Conditions A and B in Example 1.3-3 may not be extended.
(continued) SYSTEM 80+ 1.3-2 Rev. 00 16.1 Tech Spec
l Completion Times 1.3 1.3 Completion Times DESCRIPTION The following examples illustrate the use of Completion (continued) Times with different types of Condition and changing Conditions. EXAMPLE 1.3-1 ACTIONS , COMP;eTION TIME CONDITION REQUIRED ACTION , B. Required B.1 Be in MODE 3. 6 hours Action and associated E Completion Time not B.2 Be in MODE 5. 36 hours met. Condition B has two Required Actions. Each Required Action has its own separate Completion Time. Each Completion Time Q V is referenced to the time that Condition B is entered. The N guired Actions of Condition B are to be in MODE 3 within 6 hours M in MODE 5 within 36 hours. A total of 6 hours is allowed for MODE 3 and a total of 36 hours (not 42 hours) is allowed for MODE 5 from the time that Condition B was entered. If MODE 3 is reached in three hours, the time allowed to reach MODE 5 is the next 33 hours because the total time allowed to reach MODE 5 is 36 hours. If Condition B is entered while in MODE 3, the time allowed to reach MODE 5 is the next 36 hours. i l l O (continued) SYSTEM 80+ 1.3-3 Rev. 00 l 16.1 Tech Spec
l l Completion Times ! 1.3 i O ; 1.3 Completion Times DESCRIPTION EXAMPLE 1.3-2 (continued) ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One pump A.1 Restore pump to 7 days inoperable. OPERABLE status. B. Required B.1 Be in MODE 3. 6 hours Action and associated AND Completion Time not B.2 Be in MODE 5. 36 hours met. When a pump is declared inoperable, Condition A is entered. If the pump is not restored to OPERABLE status within seven days, Condition B is entered and the Completion Time clocks for Required Actions B.1 and 8.2 start. If the inoperable pump is restored to OPERABLE status after Condition B is entered, the Required Actions of Condition B may be terminated. When a second pump is declared inoperable while the first pump is still inoperable Condition A is not re-entered for the second pump. LC0 3.0.3 is entered, since the ACTIONS do not include a Condition for more than one inoperable pump. The Completion Time clock for Condition A does not stop after LCO 3.0.3 is entered, but continues to be tracked from the time Condition A was initially entered. While in LC0 3.0.3, if one of the inoperable pumps is restored to OPERABLE status and the Completion Time for Condition A has not expired, LC0 3.0.3 may be exited and operation continued in accordance with Condition B. While in LCO 3.0.3, if one of the inoperable pumps is restored to OPERABLE status and the Completion Time for Condition A has expired, LC0 3.0.3 may be exited and (continued) SYSTEM 80+ 1.3-4 Rev. 00 16.1 Tech Spec
Completion Times :*
- 1.3 L/!
1.3 Completion Times DESCRIPTION EXAMPLE 1.3-2 (continued) operation continued in accordance with Condition B. The Completion Time for Condition B is tracked from the time the Condition A Completion Time expired. . On restoring one of the pumps to OPERABLE status, the Condition A Completion Time is not reset, but continues from the time the first pump was declared inoperable. This Completion Time may be extended if the pump restored to OPERABLE status was the first inoperable pump. A 24 hour ' extension to the stated 7 days is allowed, provided this does not result in the second pump being inoperable for > 7 days. ! EXAMPLE 1.3-3 ACTIONS
/' N CONDITION REQUIRED ACTION COMPLETION TIME
( j . A. One Function A.1 Restore Function X 7 days X division division OPERABLE inoperable. status. M 10 days from discovery of failure to meet the LC0 B. One Function B.1 Restore Function Y 72 hours Y division division to inoperable. OPERABLE status. M 10 days from discovery of failure to meet the LCO i l l (continued) SYSTEM 80+ 1.3-5 Rev. 00 ! i 16.1 Tech Spec. ,
Completion Times 1.3 0 1.3 Completion Times DESCRIPTION EXAMPLE 1.3-3 (continued) ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One Function C.1 Restore Function X 72 hours X division train to OPERABLE inoperable. status. AND QB One Function C.2 Restore Function Y 72 hours Y division train to OPERABLE inoperable. status. When one Function X division and one Function Y division are inoperable, Condition A and Condition B are concurrently applicable. The Completion Time for Condition A and Condition B are tracked separately for each division starting from the time each division was declared inoperable and the Condition was entered. A separate Completion Time is established for Condition C and tracked from the time the second division was declared inoperable (i.e., the time the situation described in Condition C was discovered). If Required Action C.2 is completed within the specified Completion Time, Conditions B and C are exited. If the Completion Time for Required Action A.1 has not expired, operation may continue in accordance with Condition A. The remaining Completion Time in Condition A is measured from the time the affected division was declared inoperable (i.e., initial entry) into Condition A. The Completion Times of Conditions A and B are modified by a logical connector, with a separate 10 day Completion Time measured from the time it was discovered the LC0 was not met. In this example, without the separate Completion Time, it would be possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. (continued) SYSTEM 80+ 1.3-6 Rev. 00 16.1 Tech Spec
Completion Times 1.3 1.3 Completion Times DESCRIPTION EXAMPLE 1.3-3 (continued) The separate Completion Time modified by the phrase "from discovery of failure to meet the LC0" is designed to prevent indefinite continued operation while not meeting the LCO. i This Completion Time allows for an exception to the normal
" time zero" for beginning the Completion Time " clock." In this instance, the Completion Time " time zero" is specified as commencing at the time the LCO was initially not met, instead of at the time the associated Condition was entered. ,
k EXAMPLE 1.3-4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME i A. One or more A.1 Restore valve (s) 4 hours j q valves to OPERABLE status. Q inoperable, B. Required B.1 Be in MODE 3. 6 hours Action and associated MQ Completion Time not B.2 Be in MODE 4. 12 hours met. A single Completion Time is used for any number of valves inoperable at the same time. The Completion Time associated with Condition A is based on the initial entry into Condition A and is not tracked on a per valve basis. Declaring subsequent valves inoperable, while Condition A is still in effect, does not trigger the tracking of separate Completion Times. Once one of the valves has been restored to OPERABLE status, the Condition A Completion Time is not reset, but continues from the time the first valve was declared inoperable. The Completion Time may be extended if the valve restored to (continued) SYSTEM 80+ 1.3-7 Rev. 00 16.1 Tech Spec
Completion Times 1.3 0 1.3 Completion Times DESCRIPTION EXAMPLE 1.3-4 (continued) OPERABLE status was the first inoperable valve. The Condition A Completion Time may be extended for up to 4 hours provided this does not result in any subsequent valve being inoperable for > 4 hours. If the Completion Time of 4 hours (including any extensions) expires while one or more valves are still inoperable, Condition B is entered. EXAMPLE 1.3-5 ACTIONS _____-----------------------NOTE------------------ --------- Separate Condition Entry is allowed for each inoperable valve.
- - - - - _ = -
CONDITION REQUIRED ACTION COMPLETION TIME h A. One or more A.1 Restore valve to 4 hours valves OPERABLE status. inoperable. B. Required B.1 Be in MODE 3. 6 hours Action and associated AND Completion Time not B.2 Be in MODE 4. 12 hours met. The Note above the ACTIONS table is a method of modifying how the Completion Time is tracked. If this method of modifying how the Completion Time is tracked was applicable only to Condition A, the Note may appear in the Condition column. (continued) SYSTEM 80+ 1.3-8 Rev. 00 16.1 Tech Spec
i 4 I l Completion Times 4O i
'1.3 ' Completion Times- ,
1 I DESCRIPTION EXAMPLE 1.3-5. (continued) l
. The Note allows Condition A to be ente, red separately for i
- each . inoperable valve, and Completion Times tracked on a per valve basis. When a valve is declared inoperable, Condition i
- A is entered and its Completion Time starts. If subsequent !
4 valves are declared inoperable, Condition A is entered for ! each valve and separate Completion Times start and are tracked for each valve. i If the Campletion Time associated with a valve in Condition . A expires, Condition B is entered for that valve. If the : Completion Timss associated with subsequent valves in i . Condition A expire, Condition B it entered separately for i each valve and separate Completion Times start and are tracked for each valve. If a valve that caused entry into Condition B is restored to OPERABLE status, Condition B is l exited for that valve. , Since the Note in this example allows multiple Condition entry and tracking of separate Completion Times, Completion )O
- Time extensions do not apply.
I 1 EXAMPLE 1.3-6 . ACTIONS l CONDITION REQUIRED ACTION COMPLETION TIME A. One channel A.1 Perform SR Once per 8 hours inoperable 3.x.x.x. : l 08 A.2 Reduce THERMAL 8 hours ! POWER to s 50% RTP. j l l. O (continued)
)
l 2 SYSTEM 80+ 1.3-9 Rev. 00 j 16.1. Tech Spec j
- . . . , , - _ . - - . . _ _ _ . _ ____ o
Completion Times 1.3 1.3 Completion Times DESCRIPTION EXAMPLE 1.3-6 (continued) ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME B. Required B.1 Be in MODE 3. 6 hours Action and associated Completion Time not met. l Entry into Condition A offers a choice between Required Action A.1 or A.2. Required Action A.1 has a "once per" Completion Time, which qualifies for the 25% extension per SR 3.0.2, to each performance after the initial performance. If Required Action A.1 is followed and the Required Action is not met within the Completion Time (including 25% extension allowed by SR 3.0.2), Condition B is entered. If Required Action A.2 is followed and the Completion Time of 8 hours is not met, Condition B is entered. If after entry into Condition B, Required Action A.1 or A.2 is met, Condition B is exited and operation may then continue in Condition A. O\ (continued) SYSTEM 80+ 1,3-10 Rev. 00 ' 16.1 Tech Spec i
f l Completion Times I 1.3 V,fq 1.3 Completion Times (continued) SPECIAL EXAMPLE 1.3-7 COMPLETION TIMES ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One A.1 Verify affected I hour subsystem subsystem inoperable. isolated. MQ Once per 8 hours thereafter DB A.2 Restore subsystem 72 hours - to OPERABLE status. B. Required B.1 Be in MODE 3. 6 hours O' Action and associated MD Completion Time not B.2 Be in MODE 5. 36 hours met. Required Action A.1 has two completion Times. The I hour Completion Time begins at the time the Condition is entered and each "Once per 8 hours thereafter" interval begins upon performance of Required Action A.I. If after Condition A is entered, Required Action A.1 is not met within either the initial I hour, or any subsequent 8 hour interval, from the previous performance (including the 25% extension allowed by SR 3.0.2), Condition B is entered. The completion Time clock for Condition A does not stop after Condition B is entered, but continues from the time Condition A was initially entered. If Required Action A.1 is met after Condition B is entered, Condition B is exited and operation may continue in accordance with Condition A, provided the Completion Time for Required Action A.2 has not t i expired. O _ (continued) SYSTEM 80+ 1.3-11 Rev. 00 16.1 Tech Spec
Completion Times 1.3 0 1.3 Completion Times SPECIAL EXAMPLE 1.3-7 (continued) COMPLETION TIMES Since the second Completion Time of Required Action A.1 has a modified " time zero" (i.e., after the initial I hour, not from time of Condition entry), the allowance for a Completion Time extension does not apply. IMMEDIATE When "Immediately" is used as a Completion Time, the COMPLETION TIME Required Action should be pursued without delay and in a controlled manner. O O-SYSTEM 80+ 1.3-12 Rev. 00 16.1 Tech Spec
Frequency l I4 l (T 1.0 USE AND APPLICATION 1.4 Frequency c PURPOSE The purpose of this section is to define the proper use and application of Frequency Requirements. i DESCRIPTION Each Surveillance Requirement has a specified Frequency in ' which the Surveillance must be met in order to meet the associated LCO. An understanding of the correct application of the specified Frequency is necessary for compliance with the S0. The "specified Frequer.cy is referred to throughout this section and each of the Specifications of Section 3.0, , Surveillance Requirement (SR) Applicability. The "specified Frequency" consists of the requirements'of the Frequency column of each SR, as well as certain Notes in the Surveillance column that modify performance requirements. ; Situations where a Surveillance could be required (i.e., its Frequency could expire), but where it is not possible or not O desired that it be performed until sometime after the associated LCO is within its Applicability, represent ' potential SR 3.0.4 conflicts. To avoid these co' flicts, the SR (i.e., the Surveillance or the Frequency) is stated such , that it is only " required" when it can be and should be performed. With an SR satisfied, SR 3.0.4 imposes no restriction. EXAMPLES The following examples illustran ihe various ways that Frequencies are specified. In these examples, the Applicability of the LC0 (LC0 not shown) is MODES 1, 2, and
- 3. i 1
l IO I (continued) SYSTEM 80+ 1.4-1 Rev. 00 16.1 Tech Spec
Frequency 1.4 0 1.4 Frequency EXAMPLES EXAMPLE 1.4-1 (continued) SURVEILLANCE REQUIREMENTS SURVEILLANCE FREOUENCY Perform CHANNEL CHECK. 12 hours Example 1.4-1 contains the type of SR most often encountered in the Technical Specifications (TS). The Frequency specifies an interval (12 hours) during which the associated Surveillance must be performed at least one time. Performance of the Surveillance initiates the snbrequent interval. Although the Frequency is stated as 12 nours, an extension of the time interval to 1.25 times the stated Frequency is allowed by SR 3.0.2 for operational flexibility. The measurement of this interval continues at all times, even when the SR is not required to be met per SR 3.0.1 (such as when the equipment is inoperable, a variable is outside specified limits, or the unit is outside the Applicability of the LCO). If the interval specified by SR 3.0.2 is exceeded while the unit is in a MODE or other specified condition in the Applicability of the LCO, and the performance of the Surveillance is not otherwise modified (refer to Example 1.4-3), then SR 3.0.3 becomes applicable. If the interval as specified by SR 3.0.2 is exceeded while the unit is not in a MODE or other specified condition in the Applicability of the LC0 for which performance of the SR is required, the Surveillance must be performed within the Frequency requirements of SR 3.0.2 prior to entry into the MODE or other specified condition. Failure to do so would result in a violation of SR 3.0.4. (continued) SYSTEM 80+ 1.4-2 Rev 00 16.1 Tech Spec
. . . - ~ . . ,. . . - .- - . - - . . . . - . - ------ . -.
l l 1 1 Frequency 1.4 i 1.4 Frequency EXAMPLE 1.4-2 ! EXAMPLES ; R (continued). J ' SURVEILLANCE REQUIREMENTS l r 1 SURVEILLANCE FREQUENCY l Verify flow is within limits. Once within 12 , i, hours after = [ i 25% RTP i i i M [ f i I 24 hours l thereafter
- i 4
Example 1.4-2 has two Frequencics. The first ir a one time i < performance Frequency, and the second is of the type shown i in Example 1.41. The logical connector "E" indicates ;
- that both Fregtercy requirements must be met. Each time 1 reactor power h increased from a power level < 25% RTP to a
25% RTP, the Surveillance must be performed within 12 hours.
- The use of "once" indicates a single performance will I satisfy the specified Frequency (assuming no other ,
Frequencies are connected by " E "). This type of Frequency j does not qualify for the 25% extension allowed by SR 3.0.2. ,
"Thereafter" indicates future performances must be !
established per SR 3.0.2, but only after a specified i condition is first met (i.e., the "once" performance in this l example.). If reactor power decreases to < 25% RTP, the measurement of both intervals stops. New intervals start upon reactor power reaching 25% RTP. e i .# f (continued) ! j SYSTEM 80+ 1.4-3 Rev. 00 16.1: Tech Spec i' . -_. .. !
Frequency 1.4 O 1.4 Frequency EXAMPLES EXAMPLE 1.4-3 (continued) SURVEILLANCE REQUIREMENTS SURVERLANCE FREQUENCY
-----------------NOTE------------------
Not required to be performed until 12 hours after = 25% RTP. Perform channel adjustment. 7 days The interval continues, whether or not the unit operation is
< 25% RTP between performances.
As the Note modifies the required aerformance of the Surveillance, it is construed to be part of tue "specified Frequency." Should the 7 day interval be exceeded while operation is < 25% RTP, this Note allows 12 hours after power reaches a 25% RTP to perform the Surveillance. The Surveillance is still considered to be performed within the "specified Frequency." Therefore, if the Surveillance were not performed within the 7 day (plus 25% per SR 3.0.2) interval, but operation was < 25% RTP, it would not constitute a failure of the SR or failure to meet the LCO. Also, no violation of SR 3.0.4 occurs when changing MODES, even with the 7 day Frequency not met, provided operation does not exceed 12 hours with power a 25% RTP. Once the unit reaches 25% RTP,12 hours would be allowed for completing the Surveillance. If the Surveillance were not performed within this 12 hour interval, there would then be a failure to perform a Surveillance within the specified Frequency; MODE changes then would be restricted in accordance with SR 3.0.4 and the provisions of SR 3.0.3 would apply. O SYSTEM 80+ 1.4-4 Rev. 00 16.1 Tech Spec
Safety Limits p 2.0 A'/ 1 2.0 SAFETY _ LIMITS (SLs) , 2.1 Safety Limits . 2.1.1 Reactor Core SLs
- l 2.1.1.1 In MODES I and 2, the departure from nucleate boiling i ratio (DNBR) shall be maintained = [1.24).
2.1.1.2 In MODES I and 2, the peak linear heat rate (LHR) f (adjusted for fuel rod dynamics) shall be maintained 5 [21.0) kw/ft. . 2.1.2 Reactor Coolant System (RCS) Pressure SLs
- In MODES 1, 2, 3, 4 and 5, the RCS Pressure shall be maintained s ;
[2750] psia. l F 2.2 Safety Limit Violations If SL 2.1.1.1 or SL 2.1.1.2 is violated, restore compliance and be I r 2.2.1
\~ in MODE 3 within 1 hour.
2.2.2 If SL 2.1.2 is violated: 2.2.2.1 In MODES 1 or 2, restore compliance and be in MODE 3 i within 1 hour. , 2.2.2.2 In MODES 3, 4, or 5, restore compliance within 5 minutes. 1 2.P.3 Within 1 hour, notify the NRC Operations Center, in accordance I with 10 CFR 50.72. i l 2.2.4 Within 24 hours, notify the [ Plant Superintendent and Vice President - Nuclear Operations) and the [onsite plant reviewers , specified in Specification 5.5.1, " Plant Reviews"). l
/
(- l : i SYSTEM 80+ 2.0-1 Rev. 00 16.2. Tech Spec
Safety Limits 2.0 2.0 Safety Limits 2.2 Safety Limit Violations (continued) 2.2.5 Within 30 days of the violation, a Licensee Event Report (LER) shall be prepared pursuant to 10 CFR 50.73. The LER shall be submitted to the NRC, the [onsite plant reviewers specified in Specification 5.5.1], and the [ Plant Superintendent and Vice President-Nuclear Operations). 2.2.6 Operation of the unit shall not be resumed until authorized by the NRC. O O SYSTEM 80+ 2.0-2 h" 16.2 Tech Spec
LCO Applicability 3.0 V 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY LCO 3.0.1 LCOs shall be met during the MODES or other specified conditions in the Applicability, except as provided in LCOs l 3.0,2 and 3.0.7. . LC0 3.0.2 Upon discovery of a failure to meet an LCO, the Required Actions of the associated Conditions shall be met, except as ' provided in LC0 3.0.6. , If the LCO is met or is no longer applicable prior to expiration of the specified Completion Time (s), completion of the Required Action (s) is not required, unless otherwise stated. LCO 3.0.3 When an LC0 is not mot and the associated ACTIONS are not ' met or an associated ACTION is not provided, the unit shall be placed in a MODE or other specified condition in which the LC0 is not applicat,le. Action shall be initiated within I hour to place the unit, as applicable, in: J MODE 3 within 7 hours; a.
- b. MODE 4 within 13 hours; and
- c. MODE 5 within 37 hours.
Exceptions to this Specification are stated in the individual Specifications. Where corrective measures are completed that permit operation in accordance with the LC0 or ACTIONS, completion of the actions required by LCO 3.0.3 is not required. LC0 3.0.3 is applicable in MODES 1, 2, 3, and 4. LC0 3.0.4 When an LC0 is not met, entry into a MODE or other specified condition in the Applicability shall not be made except when the associated ACTIONS t4 be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. This O (continued) SYSTEM 80+ 3.0-1 Rev. 00 16.3 Tech Spec
. _ _ _ *_+_- * -_
LC0 Applicability 3,0 3.0 LC0 APPLICABILITY 0 LCO 3.0.4 (continued) Specification shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. Exceptions to this Specification are stated in the individual Specifications. These exceptions allow entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered allow unit operation in the MODE or other specified condition in the Applicability only for a limited period of time. LC0 3.0.5 Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate OPERABILITY, or the OPERABILITY of other equipment. This is an exception to LC0 3.0.2 for the system returned to service under administrative control to perform the testing required to demonstrate OPERABILITY. LCO 3.0.6 When a supported system LCO is not met solely due to a support system LC0 not being met, the Conditions and Required Actions associated with this supported system are not required to be entered. Only the support system LC0 ACTIONS are required to be entered. This is an exception to LC0 3.0.2 for the supported system. In this event, additional evaluations and limitations may be required in accordance with Specification 5.8, " Safety Function Determination Program (SFDP)." If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LC0 in which the loss of safety function exists are required to be entered. When a support system's Required Action directs a supported system to be declared inoperable or directs entry into , Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LC0 3.0.2. (continued) SYSTEM 80+ 3.0-2 Rev. 00 16.3 Tech Spec
LC0 Applicability. 3.0 I O 3.0 LCO APPLICABILITY (continued) , j LC0 3.0.7 Special test exception (STE) LCOs [in each applicable LCO i section] allow specified Technical Specifications-(TS) LC0 , 3.0.7 requirements to be changed to pensit performance of special tests and operations. Unless otherwise specified, i all other TS requirements remain unchanged. Compliance with STE LCOs is optional. When sn STE LCO is desired to be met but is not met, the ACTIOt ti the STE LC0 shall be met. When an STE LC0 is not des 1 rem to be met, entry into a MODE ! or other specified condition in the Applicability shall only be made in accordance with the other applicable l Specifications, f ; ~O i e t i g
\--) -
R P SYSTEM 80+ 3.0-3 Rev. 00 l
.I6.3 Tech Spec ,
t
SR Applicability 3.0 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY SR 3.0.1 SRs shall be met during the MODES or other specified conditions in the Applicability for LCOs, unless otherwise stated in the SR. Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the LCO. Failure to perform a Surveillance, within the specified frequency shall be failure to meet the LCO, except as provided in SR 3.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits. SR 3.0.2 The specified Frequency of each SR is met if the Strveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance, or as measured from the time a specified condition of the Frequency is met. For Frequencies specified as "once", the above interval extension does not apply. If a Completion Time requires periodic performance of "once per ...", the above Frequency extension applies to each h performance after the initial performance. Exceptions to this specification are stated in the individual Specifications. SR 3.0.3 If it is discovered that a Surveillance was not performed within its specified Frequency, then compliance with the requirement to declare the LC0 not met may be delayed, from the time of discovery, up to 24 hours or up to the limit of the specified frequency, whichever is less. This delay period is permitted to allow performance of the Surveillance. If the Surveillance is not performed within the delay period, the LC0 must immediately be declared not met, and the applicable Condition (s) must be entered. The Completion Times of the Required Actions begin immediately upon expiration of the delay period. (continued) SYSTEM 80+ 3.0-1 Rev. 00 16.3 Tech Spec
l SR Applicability l 3.0 , i 3.0 SURVEILLANCE REQUIREMENTS (SR) APPLICABILITY SR 3.0.3 When the Surveillance is performed within the delay period (continued) and the Surveillance is not met, the LC0 must immediately be i declared not met, and the applicable Condition (s) must be entered. The Completion Times of the Required Actions begin immediately upon failure to meet the Surveillance. SR 3.0.4 Entry into a MODE or other specified condition in the Applicability of an LC0 shall not be made unless the LCOs Surveillances have been met within their Specified frequencies. This provision shall not prevent passage through or to MODES or other specified conditions in l compliance with Required Actions. 1 4 1 . 1 J 1 (O q ,) I l SYSTEM 80+ 3.0-5 Rev. 00 l 4 16.3 Tech Spec
k SDM -! 3.1 REACTIVITY CONTROL SYSTEMS
-3.1.1 SHUTDOWN MARGIN (SDM) t l l
LCO 3.1.1 a. SDM shall be a (6.5]% Ak/k; and either b.1. With reactor trip circuit breaker (RTCBs) closed: the estimated critical position shall be within the limits of LCOs 3.1.6 (" Shutdown Control Element Assembly (CEA) Insertion Limits") and 3.1.7 (" Regulating Control Element Assembly (CEA) Insertion Limits"); or b.2 With RTCBs open: K n ., shall be < 0.99. l APPLICABILITY: MODES 3, 4 and 5. ACTIONS CONDITION REQ 0IREDACTION COMPLETION TIME
]
' d A. SDM not within limit. A.1 Initiate boration to 15 minutes i restore SDM to within l l limit. t w , ^ l SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.1.1 Verify SDM is a [6.5]% Ak/k. 24 hours ; l l n V ; i SYSTEM 80+ 3.1-1 Rev. 00 ' 16.3 Tech Spec-( ,
RTCB 3.1 REACTIVITY CONTROL SYSTEMS 3.1.2 Reactor Trip Circuit Breakers (RTCB) LCO 3.1.2 The RTCBs shall be open. APPLICABILITY: MODE 5 with REDUCED RCS INVENTORY ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RTCBs not in required A.1 Open RTCBs Immediately status. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.2.1 Verify RTCBs open. [12 hours] t O SYSTEM 80+ 3.1-2 Rev. 00 16.3 Tech Spec
t l- Reactivity Balance 3.1.3 3.1 REACTIVITY CONTROL SYSTEMS Reactivity Balance
- 3. I .3
~
i LC0 3.1.3 The core reactivity balance shall be within i I% Ak/k of predicted values. APPLICABILITY: MODES 1 and 2. l ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME 1 A. Core reactivity A.1 Re-evaluate core 72 hours balance not within design and safety analysis and limit, determine that the reactor core is acceptable for ) O , continued operation. l 4 V em 72 hours Establish appropriate A.2 operating restrictions and SRs. i 1 B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time not met. v
-U'
-SYSTEM 80+ 3.1-3 Rev. 00 16.3 Tech Spec
Reactivity Balance 3.1.3 SURVEILLANCE REQUIREMENTS O SURVEILLANCE FREQUENCY SR 3.1.3.1 --------------------NOTES-------------------
- 1. The predicted reactivity values may be adjusted (normalized) to correspond to the measured core reactivity prior to exceeding a fuel burnup of 60 effective full power days (EFPD) after each fuel loading.
- 2. This Surveillance is not required to be performed prior to entry into MODE 2.
Verify overall core reactivity balance is Prior to within 1.0% Ak/k of predicted values. entering MODE I after fuel loading AND
------NOTE-----
Only required after 60 EFPD 31 EFPD O SYSTEM 80+ 3.1-4 Rev. 00 16.3 Tech Spec
4 d MTC t 3.1.4 !
- O 3.1 REACTIVITY CONTROL SYSTEMS 1 3.1.4 Moderator Temperature Coefficient (MTC) !
i The MTC shall be maintained within the limits specified in :
, LCO 3.1.4 i the COLR, and a maximum positive limit as specified below: .l
- a. [0.0) Ak/k/*F when THERMAL POWER.is s 0% RTP; and'
- b. [-0.1E-4] Ak/k/*F when THERMAL POWER is 100% RTP; and
- c. [ Values linearly interpolated between a. and b. when ':
THERMAL POWER is > 0% RTP and < 100% RTP.] APPLICABILITY: MODES 1 and 2. f i ! ACTIONS 3 CONDITION REQUIRED ACTION COMPLETION TIME . A. MTC not within limits. A.1 Be in MODE'3. 6 hours t 6
- 1 5
]
l 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY t SR 3.1.4.1 ---------------------NOTE----------------- , j - This Surveillance is not required to be performed prior.to entry into MODE 2. Verify MTC within the upper limit specified Prior to in the COLR. entering MODE 1 ' after each fuel loading ! (continued) !
- O
- ' SYSTEM 80+ .3.1-5 Rev. 00 16.3 Tech Spec
_ _ - _ ._ _ _ . . _ - ._ _ b
l MTC i 3.1.4 SURVEILLANCE REQUIREMENTS (continued) 9 <l SURVEILLANCE FREQUENCY SR 3.1.4.2 -------------------NOTES-------------------
- 1. This Surveillance is not required to be performed prior to entry into MODE 1 or 2.
- 2. If the MTC is more negative than the COLR limit when extrapolated to the end of cycle, SR 3.1.4.2 may be repeated. Shutdown must occur prior to exceeding the minimum allowable boron concentration at which HTC is projected to exceed the lower limit.
Verify MTC is within the lower limit Each fuel cycle specified in the COLR. within 7 effective full power days (EFPD) of reaching 40 EFPD core burnup AND Each fuel cycle l within 7 EFPD l of reaching 2/3 i of expected core burnup i i
)
O' SYSTEM 80+ 3.1-6 Rev. 00 16.3 Tech Spec
)
CEA Alignment 3.1 REACTIVITY CONTROL SYSTEMS 3.1.5 Control Element Assembly (CEA) Alignment LC0 3.1.5 All full strength CEAs shall be OPERABLE, and all full and , part strength CEAs shall be aligned to within [7 inches] ' (indicated position) of their respective groups. APPLICABILITY: MODES I and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME k A. One or more regulating A.1 Reduce THERMAL POWER 1 hour i CEAs trippable and in accordance with ! misaligned from its Figure 3.1.5-1. ' group by > [7 inches] ~ and s (19 inches]. AND (T QB A.2.1 Verify SDM is I hour '
\_ / - a [6.5]% Ak/k.
One regulating CEA trippable and QB misaligned from its group by A.2.2 Initiate boration to I hour
> [19 inches]. restore SDM to within limit.
AND A.3.1 Restore the 2 hours misaligned CEA(s) to within [7 inches] (indicated position) of its group. DB (continued) SYSTEM 80+ 3.1-7 Rev. 00
'16.3 Tech Spec
CEA Alignment ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (Continued) A.3.2 Align the remainder 2 hours of the CEAs in the group to within [7 inches] (indicated position) of the misaligned CEA(s) while maintaining the insertion limit of LCO 3.1.7,
" Regulating Control Element Assembly (CEA) Insertion Limits."
B. One or more shutdown B.1 Reduce THERMAL POWER 1 hour CEAs trippable and in accordance with misaligned from its Figure 3.1.5-1. group by > [7 inches] and s [19 inches]. 6.N_Q QB B.2.1 Verify SDM is I hour
= [6.5]% Ak/k.
One shutdown CEA trippable and QB I misaligned from its group by B.2.2 Initiate boration to I hour
> [19 inches]. restore SDM to within I
limit. AND 2 hours B.3 Restore the , misaligned CEA(s) to within [7 inches] (indicated position) of its group. (continued) O SYSTEM 80+ 3.1-8 Rev. 00 16.3 Tech Spec
~ . . . _. . _ _ _ _ . _ _ _ _ _ _ . _- -
CEA Alignment 3.1.5 , ACTIONS (continued) CONDITION REQUIRED ACTION lCOMPLETIONTIME C. One or more part C.1 Reduce THERMAL POWER 1 hour , strength CEAs in accordance with misaligned from its Figure 3.1.5-1. group by > [7 inches] and 5 [19 inches). MQ C.2.1 Restore the 2 hours QB misaligned CEA(s) to One part strength CEA within [7 inches] misaligned from its (indicated position) ; group by of its group.
> [19 inches).
98 C.2.2 Align the remainder 2 hours of the CEAs in the i group to within [7 inches] (indicated position) of the misaligned CEA(s). l l D. Required Action and D.1 Be in MODE 3. 6 hours associated Completion ' Time of Condition A, B, or C not met. DB One or more full ) strength CEAs untrippable. l QB Two or more CEAs misaligned by
> [19 in:hes).
1 W O SYSTEM.80+ 3.1-9 Rev. 00 16.3 Tech Spec
I i CEA Alignment l 3.1.5 SURVEILLANCE REQUIREMENTS Oll SURVEILLANCE FREQUENCY SR 3.1.5.1 Verify the indicated position of each full 12 hours 1 and part strength CEA is within [7 inches] I of all other CEAs in its group. SR 3.1.5.2 Verify that, for each CEA, its OPERABLE CEA 12 hours position indicator channelt, indicate within [5 inches) of each other. SR 3.1.5.3 Verify full strergth CEA freedom of 92 days movement (trippability) by moving each individual full strength CEA that is not fully inserted in the core at least [5 inches]. [18 months] O SR 3.1.5.4 Perform a CHANNEL FUNCTIONAL TEST of each reed switch position transmitter channel. SR 3.1.5.5 Verify each full strength CEA drop time Prior to 5 [3.5] seconds and the arithmetic average reactor of all full strength CEA drop times criticality, s [3.2] seconds, after each removal of the reactor lead O SYSTEM 80+ 3.1-10 Rev. 00 16.3 Tech Spec
- . .- . - _ _ . - - - . . _ . . .. .~ . ..
2 CEA Alignment 3.1.5 O
.. . _- .. ........------ _----.--NOTE-----------------------------------------
< When core power is reduced to 60% RTP per this limit curve, further reduction is not required by this Specification. -------
- ..--=-._---
- - - - - - - . . . - - - - - - - . . . . . . . . . . . . . . . - - . . . . . . . . . . - - - - - = _ .
i e i NOT TO BE USED FOR OPERATION. FOR ILLUSTRATION PURPOSES ONLY. t
=
40 l 4 30 " (60 MIN, 30%) e"w - 1 ! e (60 MIN, 20%) 2 h 20 - B8 : E at I~ ! 5 10 - e s
=
O a a 0 15 30 45 60 TIME AFTER DEVIATION (MINUTES)
- CEA Mesalignment for setter Rank 13), Bank [P11, or Bank (P2]
** CEA maahenment for any Bank not mentened in the previous note Figure 3.1.5-1 Required Power Reduction After CEA Deviation O i SYSTEM 80+ 3.1-11 Rev. 00 16.3 Tech Spec
i i l l Shutdown CEA Insertion Limits i 3.1 REACTIVITY CONTROL SYSTEMS l 3.1.6 Shutdown Control Element Assembly (CEA) Insertion Limits LC0 3.1.6 All shutdown CEAs shall be withdrawn to = [145] inches. APPLICABILITY: MODE 1, MODE 2 with any regulating CEA not fully inserted.
- - - - - - - - - - - - - - - -NOTE----------------------------------
This LC0 is not applicable while performing SR 3.1.5.3. ACTIONS REQUIRED ACTION COMPLETION TIME CONDITION A. One or more shutdown A.1.1 Verify SDM 1 hour CEAs not within limit, a [6.5]% ak/k. Initiate boration to I hour O A.1.2 restore SDM to within limit. AND A.2 Restore shutdown 2 hours CEA(s) to within limit. B. Required Action and B.1 Be in MODE 3. 6 hours associated Completion Time not met. O SYSTEM 80+ 3.1-12 Rev. 00 16.3 Tech Spec
l k Shutdown CEA Insertion L mi i SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY j i i SR 3.1.6.1 Verify each shutdown CEA is withdrawn 12 hours !
= [145] inches.
i i i t I i i i l I O l i t I l O SYSTEM 80+ 3.1-13 Rev 00 16.3 Tech Spec
)
l Regulating CEA Insertion Limits 3.1 REACTIVITY CONTROL SYSTEMS 0.1.7 Regulating Control Element Assembly (CEA) Insertion Limits LCO 3.1.7 The power dependent insertion limit (PDIL) alarm circuit shall be OPERABLE, and
- a. With the Core Operating Limit Supervisory System (COLSS) in service, the regulating CEA groups shall be limited to the withdrawal sequence, insertion limits, and associated time restraints specified in the COLR.
- b. With COLSS out of service, the regulating CEA groups shall be limited to the short term steady state insertion limit and associated time restraints specified in the COLR.
APPLICABILITY: MODES I and 2.
---- ---_----------_-------NOTE-----------
This LCO is not applicable while conducting SR 3.1.5.3 [or during reactor power cutback operation]. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Regulating CEA groups A.I.1 Verify SDM 1 hour inserted beyond the = [6.5]% Ak/k. transient insertion limit with COLSS in M service. A.I.2 Initiate boration to I hour restore SDM to within limit. AND A.2.1 Restore regulating 2 hours CEA groups to within limits. E (continued) O SYSTEM 80+ 3.1-14 Rev. 00 16.3 Tech Spec
i c Regulating CEA Insertion Limits . ; 3.1.7 . O ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME l.
- A. (Continued) A.2.2 Reduce THERMAL POWER 2 hours to less than or equal ,
to the fraction of RTP allowed by the CEA group position and insertion limits specified in the , COLR. 4 4 . B. Regulating CEA groups B.1 Verify short term 15 minutes : inserted between the steady state i long term steady state insertion limits are !' insertion limit and not exceeded. > l the transient j insertion limit for QB
> 4 hours per 24 hour interval with COLSS in B.2 Restrict increases in 15 minutes O service. THERMAL POWER to s 5% RTP per hour.
i C. Regulating CEA groups C.1 Restore regulating 2 hours i inserted between the CEA groups to within long term steady state limits. ! insertion limit and the transient insertion limit for ) intervals j
> 5 effective full !
power days (EFPD) per !
- .30 EFPD interval or j i
> 14 EFPD per 365 EFPD 7 interval with COLSS in service.
1
- (continued) l A l U l SYSTEM 80+ 3.1-15 Rev. 00 16.3 Tech Spec l
Regulating CEA Insertion Limits 3.1.7 ACTIONS (continued) O CONDITION REQUIRED ACTION COMPLETION TIME D. Regulating CEA groups D.1.1 Verify SDM 1 hour inserted beyond the = [6.5]% Ak/k. short term steady state 1.isertion limit E with COLSS out of service. D.1.2 Initiate boration to I hour restore SDM to within limit. E D.2.1 Restore regulating 2 hours CEA groups to within limits. E D.2.2 Reduce THERMAL POWER 2 hours to less than or equal to the fraction of RTP allowed by CEA group position and short term steady state insertion limit specified in the COLR. E. PDIL alarm circuit E.1 Perform SR 3.1.7.1. I hour inoperable. M Once per 4 hours thereafter F. Required Actions and F.1 Be in MODE 3. 6 hours associated Completion Times not met. O SYSTEM 80+ 3.1-16 Rev. 00 16.3 Tech Spec
Regulating CEA Insertion Limits 3.1.7 SURVEILLANCE REQUIREMENTS , SURVEILLANCE FREQUENCY f [ SR 3.1.7.1 -----------------NOTE---------------------- ' This Surveillance is not required to be performed prior to entry into MODE 2. Verify each regulating CEA group position 12 hours is within its insertion limits. b 5 SR 3.1.7.2 Verify the accumulated times during which 24 hours the regulating CEA groups are inserted beyond the steady state insertion limits , but within the transient insertion limits. SR 3.1.7.3 Verify PDIL alarm circuit is OPERABLE. 31 days 1 4 1 4 , O ..
]
SYSTEM 80+ 3.1-17 Rev. 00 l 16.3 Tech' Spec
l Part Strength CEA Insertion Limits 3.1 REACTIVITY CONTROL SYSTEMS 3.1.8 Part Strength Control Element Assembly (CEA) Insertion Limits LCO 3.1.8 The part strength CEA groups shall be limited to the insertion limits specified in the COLR. APPLICABILITY: MODE 1 > 20% RTP.
---------------------- =-N0TE---------------====- = - - - ===
This LCO not applicable while exercising part strength CEAs.
- - = . . . _ _ = - - - --= =- --------
_______________. ---- =__ - ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Part strength CEA A.1 Restore part strength 2 hours groups inserted beyond CEA groups to within the transient the limit. insertion limit. M A.2 Reduce THERMAL POWER 2 hours to less than or equal to that fraction of RTP specified in the COLR. B. Part strength CEA B.1 Restore part strength 2 hours groups inserted CEA groups to within between the long term the long term steady steady state insertion state insertion limit and the limit. transient insertion limit for intervals a 7 effective full power days (EFPD) per 30 EFPD or 2 14 EFPD per 365 EFPD interval. (continued) SYSTEM 80+ 3.1-18 Rev. 00 16.3 Tech Spec
Part Strength CEA Insertion Limits ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Reduce THERMAL POWER. 4 hours associated Completion to s 20% RTP. Time of Condition B not met. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 1 - SR 3.1.8.1 Verify part strength CEA group position. 12 hours 4 O i. } l i O SYSTEM 80+ 3.1-19 Rev. 00 16.3 Tech Spec 4
STE-SDM 3.1 REACTIVITY CONTROL SYSTEMS 3.1.9 Special Test Exception (STC)-SHUTDOWN MARGIN (SDM) LCO 3.1.9 The SDM requirements of LCO 3.1.1, " SHUTDOWN MARGIN (SDM)," and the regulating control element assembly (CEA) insertion limits of LC0 3.1.7, " Regulating Control Element Assembly (CEA) Insertion Limits," may be suspended for measurement of CEA worth and SDM, provided shutdown reactivity equivalent to at least the highest estimated CEA worth (of those CEAs actually withdrawn) is vailable for trip insertion. APPLICABILITY: MODES 2 and 3 during PHYSICS TESTS.
-------------------NOTE-------=--- --- - -- = = --- - =--
Operation in MODE 3 shall be limited to 6 consecutive hours.=_-- ___- ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any full strength CEA A.1 Initiate boration to 15 minutes not fully inserted and restore required less than the required shutdown reactivity. shutdown reactivity available for trip insertion. DB All full strength CEAs inserted and the reactor suberitical by less than the above required shutdown reactivity equivalent. O SYSTEM 80+ 3.1-20 Rev. 00 16.3 Tech Spec
l STE-SDM 3.1.9 i SURVEILLANCE REQUIREMENTS .=- SURVEILLCCE FREQUENCY SR 3.1.9.1 Verify that the position of each CEA not 2 hours ! fully inserted is within the acceptance
> criteria for available negative reactivity ,
addition. SR 3.1.9.2 Verify each full strength CEA not fully Within [7 days) inserted is capable of full insertion when prior to tripped from at least the 50% withdrawn reducing SDM to position. less than the limits of LC0 3.1.1 i O l i i SYSTEM 80+ 3.1-21 Rev. 00 l 16.3 Tech Spec
STE-MODES 1 and 2 3.1.10 3.1 REACTIVITY CONTROL SYSTEMS 0 3.1.10 Special Test Exceptions (STE)-MODES I and 2 LCO 3.1.10 During performance of PHYSICS TESTS, the requirements of: LC0 3.1.4, " Moderator Temperature Coefficient (MTC)"; LC0 3.1.5, " Control Element Assembly (CEA) Alignment"; LCO 3.1.6, " Shutdown Control Element Assembly (CEA) Insertion Limits"; LC0 3.1.7, " Regulating Control Element Assembly (CEA) Insertion Limits"; LCO 3.1.8, "Part Strength Control Element Assembly (CEA) Insertion Limits"; LC0 3.2.2, " Planar Radial Peaking Factors (F,y)"; and LC0 3.2.3, " AZIMUTHAL POWER TILT (Tq)" may be suspended, provided:
- a. THERMAL POWER is restricted to the test power plateau, which shall not exceed 85% RTP; and
- b. SDM is a [6.5]% Ak/k.
APPLICABILITY: MODES 1 and 2 during PHYSICS TESTS. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Test power plateau A.1 Reduce THERMAL POWER 15 minutes exceeded. to less than or equal to the test power plateau. B. SDM is not within B.1 Initiate boration to 15 minutes limit. restore SOM to within limit. MQ B.2 Suspend PHYSICS TESTS. I hour (continued) SYSTEM 80+ 3.1-22 Rev. 00 16.3 Tech Spec
I STE-MODES I and 2 l 3.1.10 !
)
O- ACTIONS (continued) l CONDITION REQUIRED ACTION COMPLETION TIME l 1 C. Required Action and C.1 Suspend PHYSICS I hour i associated Ccapletion TESTS. Time not met. l AND 6 hours C.2 Be in MODE 3. . SURVEILLANCE REQUIREMENTS , SURVEILLANCE FREQUENCY f, SR 3.1.10.1 Verify THERMAL POWER equal to or *,ess than 1 hour the test power pl ateau. j O SR 3.1.10.2 Verify SDM is = [6.5]% AL/k. 24 hours F l ' l i i
- i. !
)
- -j i
I i i SYSTEM 80+ 3.1-23 Rev. 00
- L16.3 Tech Spec -!
--_ _ _ - ..____ . _ _ _ _ _ j
i i STE-CEDMS Testing 3.1 REACTIVITY CONTROL SYSTEMS 3.1.11 Special Test Exception - CEDMS Testing LC0 3.1.11 The SHUTDOWN MARGIN requirement of Specification 3.1.1 may be suspended for pre-startup tests to demonstrate the OPERABILITY of the control element drive mechanism system (CEDMS) provided:
- a. No more than one CEA is withdrawn at any time,
- b. No CEA is withdrawn more than [7] inches.
- c. With RTCBs open, K,.3 shall be less than 0.99 prior to the start of testing,
- d. All other operations involving positive reactivity changes are suspended during the testing.
APPLICABILITY: MODES 4 and 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME Any of the above A.1 Suspend testing and Immediately A. requirements not met. initiate boration to restore SDM to within the limit of LCO 3.1.1. O , SYSTEM 80+ 3.1-24 Rev. 00 16.3 Tech Spec
i' STE-CEDMS Testing , 3.1.11 ;
/
(~ -) SURVEILLANCE REQUIREMENTS i SURVEILLANCE FREQUENCY SR 3.1.11.1 Determine SDM.* Once per 24 i hours i
- Consider the following factors: ;
- 1. RCS boron concentration
- 2. CEA position RCS average temperature l 3.
- 4. Fuel burnup based on gross thermal energy generation 1
- 5. Xenon concentration .
- 6. Samarium concentration i
1 ( 1 l SYSTEM 80+ 3.1-25 Rev. 00 1 16.3 Tech Spec , I i
i Boron Dilution Alarms 3.1 REACTIVITY CONTROL SYSTEMS 3.1.12 Boron Dilution Alarms LC0 3.1.12 Two startup channel high neutron flux alarms shall be OPERABLE. APPLICABILITY: MODE 3, within I hour after the neutron flux is dthin the startup range following a reactor shutdown. MODES 4, 5, and 6. ACTIONS
NOTE- ---~ ---------------------------------
The provisions of LCO 3.0.3 are not applicabic. CONDITION REQUIRED ACTION COMPLETION TIME A. One startup channel A.1 Initiate action to Immediately high neutron flux restore ".he alarm inoperable. inoperab'e channel to OPERABLE status. AND A.2 Initiate action to Immediately determine the RCS boron concentration AND when entering MODE 3,4,5 or 6 or at the Once per time the alarm is required determined Frequency inoperable. identified in Tables 3.1.12-1 through 3.1.12-5 (continued) O SYSTEM 80+ 3.1-26 Rev. 00 16.3 Tech Spec
J Bcron Dilution Alarms 3.1.12 l
/)
LJ ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME B. Two startup channel B.1 Initiate action to Immediately high neutron flux restore at least one alarms inoperable. channel to OPERABLE status. AND B.2 Initiate action to Immediately determine the RCS 1 boron concentration AND when entering MODE 3, 4, 5 or 6, or at the Once per : time both al. arms are required i determined Frequency . (noperable. identified in l Tables 3.1.12-1 " through 3.1.12-5 - a!iQ B.3 Suspend all Immediately
/'~')
,(/ operations involving CORE ALTERATIONS or positive reactivity changes.
- 1 i
4 f SYSTEM 80+ 3.1-27 Rev. 00 l 16.3 Tech Spec
Boron Dilution Alarms 3.1.12 SURVEILLANCE REQUIREMENTS O SURVEILLANCE FREQUENCY 3.1.12.1 Perform a CHANNEL CHECK. 12 hours AND When initially setting setpoints at the following times:
- a. One hour after a reactor trip
- b. After a controlled reactor shutdown:
Within 1 hour after the neutron flux is within the startup range in MODE 3. 3.1.12.2 Perform a CHANNEL CALIBRATION. Every 31 days of cumulative operation during shutdown O SYSTEM 80+ 3.1-28 Rev. 00 16.3 Tech Spec
i Boron Dilution Alarms - 3.1.12 . t - Table 3.1.12-1 (Page 1 of 1) l Required Monitoring frequencies for Backup Boron Dilution Detection as a Function of Operating Charging Pumps i and Plant Operational MODES for K,,, > 0.98 Number of Operating Charging Pumps OPERATIONAL - MODE o 1 , i ! c 3 [12_ hours] [1 hour] ; i--
- 4 not on SCS [12 hours] [1 hour)-
J
?
! 5 not on SCS [8 hours] [1 hour] ; i
- f
\ :
4 & 5 on SCS [0NA] [0NA] L
--__.------NOTES------------ - - - - - - - - - - - - - - - - - - - - l 4
SCS = Shutdown Cooling System ONA. - Operation Not Allowed 6i- l 1 9 i SYSTEM 80+ 3.1-29 Rev. 00 j
-16.3 Tech Spec- l t
l
, , '.E
Boron Dilution Alarms 3.1.12 O Table 3.1.12-2 (Page 1 of 1) Required Monitoring Frequencies for Backup Boron Dilution Detection as a Function of Operating Charging Pumps and Plant Operational MODES for 0.98 a K,,, > 0.97 Number of Operating Charging Pumps OPERATIONAL MODE o 1 3 [12 hours) [2.0 hours] 4 not on SCS [12 hours] [2.5 hours] 5 not on SCS [8 hours] [2.5 hours] [0.5 hours] O 4 & 5 on SCS [8 hours] -- ......_---------___._-------_-------NOTES = - = - - --------------------------- SCS = Shutdown Cooling System , l l l l i I O' SYSTEM 80+ 3.1-30 Rev. 00 16.3 Tech Spec
y 1
- Boron Dilution Alarms 3.1.12 q
(V 4 r Table 3.1.12-3 (Page -1 of 1) Required Monitoring Frequencies for Backup Boron Dilution !
; Detection as a function of Operating Charging Pumps -
.and Plant Operational MODES for 0.97 2 K,,, > 0.96 i
l Number of_ Operating Charging Pumps ' OPERATIONAL MODE o 1 3 [12 hours] [3.5 hours] 4 not on SCS [12 hours] [3.5 hours] 5 not on SCS [8 hours] [3.5 hours] 1 O 4 & 5 on SCS [8 hours] [1 hour] 5
-------------------------------------NOTES-----------------------=--
SCS - Shutdown Cooling System 4 1 l
- i l
O ! SYSTEM 80+ 3.1-31 Rev. 00 i 16.3 Tech Spec. l
i 1 l Boron Dilution Alarms . 3.1.12 O' Table 3.1.12-4 (Page 1 of 1) Required Monitoring Frequencies for Backup Boron Dilution Detection as a function of Operating Charging Pumps and Plant Operational MODES for 0.96 a K,,, > 0.95 Number of Operating Charging Pumps OPERATIONAL MODE o 1 3 [12 hours] [5 hours] 4 not on SCS [12 hours] [5 hours] 5 not on SCS [8 hours] [5 hours] [2 hours] O 4 & 5 on SCS [8 hours]
_----------_-----------------NOTE--------- ----=-- -----------------------
SCS - Shutdown Cooling System ---- O SYSTEM 80+ 3.1-32 Rev. 00 16.3 Tech Spec
__...-_..___.____.7 i i i i Boron Dilution Alarms ; 3.1.12
'. l t
l Table 3.1.12-5 (Page 1 of 1) Required Monitoring Frequencies for Backup Boron Dilution- , 3
< Detection as a Function of Operating Charging Pumps ;
.and Plant Operational MODES for K,,, s 0.95 ,
v Number of Operating Charging Pumps OPERATIONAL i WE o 1 i 4 [6 hours] t 3 [12 hours] i 1 4 not on SCS [12 hours] [6 hours] j 5 5 not on SCS [8 hours] [6 hours] l i 4 & 5 on SCS [8 hours] [2 hours) i 4 6 [24 hours] [8 hours] l
-------------------------------------NOTES---------------------------------------
SCS - Shutdown Cooling System i I i i t (1, i
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SYSTEM 80+ 3.1-33 Rev. 00 l 16.3 Tech Spec l r
,, ,,.-e,- . , - - .J . . _ , . . . . . , _ _ . : _.
l LHR 3.2.1 ; (- (' 3.2 POWER DISTRIBUTION LIMITS
~3.2.1 Linear Heat Rate (LHR)
LCO 3.2.1 LHR shall not exceed the limits specified in the COLR. , APPLICABILITY: MODE 1 with THERMAL POWER > 20% RTP. ACTIONS CONDITION' REQUIRED ACTION COMPLETION TIME A. Core Operating Limit A.1 Restore'LHR to within 1 hour Supervisory System limits. (COLSS) calculated core power exceeds the COLSS calculated core , power operating limit < based on LHR. l B. LHR not within region B.1 Restore LHR to within 4 hours of acceptable limits. operation when the COLSS is out of service. C. Required Action and C.1 Reduce THERMAL POWER 6 hours ! associated Completion to s 20% RTP. Time not met, l I i l l g i i SYSTEM 80+ 3.2-1 Rev. 00 ! 16.3 Tech Spec
l l l LHR 3.2.1 SURVEILLANCE REQUIREMENTS O SURVEILLANCE FREQUENCY SR 3.2.1.1 -------------------NOTE-------------------- Only applicable when COLSS is out of service. With COLSS in service, LHR is continuously monitored. Verify LHR, as indicated on each OPERABLE 2 hours local power density channel, is s [13.7 kW/ft). SR 3.2.1.2 Verify the COLSS margin alarm actuates at a 31 days THERMAL POWER equal to or less than the core power operating limit based on LHR. O O SYSTEM 80+ 3.2-2 Rev. 00 16.3 Tech Spec
F* 3 3.2.l 3.2 POWER DISTRIBUTION LIMITS 3.2.2 Planar Radial Peaking Factors (Fxy) LC0 3.2.2 The measured Planar Radial Peaking Factors (F7,) shall be equal to or less than the Planar Radial Peaking Factors . (fey) . (These. factors are used in the Core Operating Limit Supervisory System (COLSS) and in the Core Protection Calculators (CPCs)). , 4 APPLICABILITY: MODE 1 with THERMAL POWER > 20% RTP. > ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME i A. fey > Fj,. A.I.1 Adjust addressable 6 hours CPC constants to increase the , multiplier applied to t Di
,U planar radial pleaking byafactor2F,/Ffy.
t E . A.I.2 Maintain a margin to 6 hours the COLSS operating < ~ limits of [(F7,/Fly)-I.0] x 100%. M A.2 Adjust the affected Ffy used in the COLSS 6 hours and CPCs to a value greater than or egual to the measured F,,. E (continued) SYSTEM 80+ 3.2-3 Rev. 00 16.3 Tech Spec
F
- 3. 2.T ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. A.3 Reduce THERMAL POWER 6 hours (continued) to 5 20% RTP.
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.2.1 Verify measured F7, obtained using the Once after each Incore Detector System is equal to or less fuel loading than the value of Ff, used in the COLSS and with THERMAL CPCs. POWER > 40% RTP but prior to operations above 70% RTP AND 31 EFPD thereafter O SYSTEM 80+ 3.2-4 Rev. 00 16.3 Tech Spec
e 4 T
' 3.2.3 i q
b 3.2 F0WER DISTRIBUTION LIMITS 3.2.3 AZIMUTHAL POWER TILT (T,) LCO 3.2.3 shall be less than or equal to the Ta , The measured allowance used T,in the core protection calculators-(CPCs). APPLICABILITY: MODE 1 with THERMAL POWER > 20% RTP. f
-ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Measured To greater A.1 Restore measured T,. 2 hours l than the allowance used in the CPCs and QB 4
5[0.10). A.2 2 hours 1 Adjust allowance the inT'the CPCs ,fN to greater than or d equal to the measured l value. I i
- )
l l B. Measured T, > [0.10). B.1 -------NOTE---------- All subsequent Required Actions must be completed if power - reduction commences prior to restoring T, to s [0.10). Reduce THERMAL POWER 4 hours to s 50% RTP. 1 AND (continued) O SYSTEM 80+ 3.2-5 Rev. 00 16.3 Tech Spec
'b
1 T 3.2.5 ACTIONS 9, CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 Reduce Linear Power 16 hours Level-High trip setpoints to s 55% RTP. AND B.3 Restore the measured Prior to increasing To to less than the T" allowance used in the THERMAL POWER CPCs.
-----NOTE-------
Correct the cause of the out of limit condition prior to increasing THERMAL POWER. Subsequent power operation
> 50% RTP may proceed provided that the measured T, is verified s [0.10) at least once per hour for 12 hours, or until verified at a 95% RTP.
C. Required Actions and C.1 Reduce THERMAL POWER 6 hours associated Completion to s 20%. Times not met. O SYSTEM 80+ 3.2-6 Rev. 00 16.3 Tech Spec
T 3.2.3 (N 1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.3.1 -------------------NOTE-------------------- ) Only applicable when COLSS is out of ' service. With COLSS in service, this parameter is continuously monitored. Calculate T, and verify it is within the 12 hours limit. SR 3.2.3.2 Verify COLSS azimuthal tilt alarm is 31 days actuated at a To value less than the T y value used in the CPCs. SR 3.2.3.3 Independently confirm the validity of the 31 days (~'T COLSS calculated T, by use of the incore 1 (_/ detectors. l l i f r
]
SYSTEM 80+ 3.2-7 Rev. 00 16.3 Tech Spec
DNBR 3.2 POWER DISTRIBUTION LIMITS 3.2.4 Departure from Nucleate Boiling Ratio (DNBR) LC0 3.2.4 The DNBR shall be maintained by one of the following methods:
- a. Maintaining Core Operating Limit Supervisory System (COLSS) calculated core power less than or equal to COLSS calculated core power operating limit based on DNBR (when COLSS is in service, and either one or both control Element assembly calculators (CEACs) are OPERABLE);
- b. Maintaining COLSS calculated core power less than or equal to COLSS calculated core power operating limit based on DNBR decreased by 13.0% RTP (when COLSS is in service and neither CEAC is OPERABLE);
- c. Operating within the region of acceptable operation of Figure 3.2.4-1 specified in the COLR using any operable core protection calculator (CPC) channel (when COLSS is out of service and either one or both CEACs are OPERABLE); or
- d. Operating within the region of acceptable operation of Figure 3.2.4-2 specified in the COLR using any operable CPC channel (when COLSS is out of service and neither CEAC is OPERABLE).
APPLICABILITY: MODE 1 with THERMAL POWER > 20% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. COLSS calculated core A.1 Restore the DNBR to I hour power not within within limit. limit. (continued) O SYSTEM 80+ 3.2-8 Rev. 00 16.3 Tech Spec
DNBR 3.2.4 ,q iU) ACTIONS (continued) CONDITION REQUIRED ACTION COMPLETION TIME B. DNBR outside the B.1 Restore DNBR to 4 hours region of acceptable within limit. operation when COLSS is out of service. C. Required Action and C.1 Reduce THERMAL POWER 6 hours associated Completion, to 5 20% RTP. Time not met. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY ( SR 3.2.4.1 --------------------NOTE------------------- Only applicable when COLSS is out of service. With COLSS in service, this parameter is continuously monitored. Verify DNBR, as indicated on all OPERABLE 2 hours DNBR CHANNELS, is within the limit of Figure 3.2.4-1 or 3.2.4-2 of the COLR, as applicable. SR 3.2.4.2 Verify COLSS margin alarm actuates at : 31 days THERMAL POWER level equal to or less than the core power operating limit based on DNBR. O V SYSTEM 80+ 3.2-9 Rev. 00 16.3 Tech Spec
ASI
- 3. 2 POWER DISTRIBUTION LIMITS 3.2.5 AXIAL SHAPE INDEX (ASI)
LCO 3.2.5 ASI shall be within the limits specified in the COLR. APPLICABILITY: MODE 1 with THERMAL POWER > 20% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Core average ASI not A.1 Restore ASI to within 2 hours within limits. limits. B. Required Action and B.1 Reduce THERMAL POWER 4 hours associated Completion to s 20% RTP. Time not met. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.5.1 Verify ASI is within limits. 12 hours i I i I SYSTEM 80+ 3.2-10 Rev. 00 16.3 Tech Spec _ _ _ _ _ . . - _ - _ _ - . . _ _ _ _ _ _ - _ - - - _ _ _ _ - - _ - _ _ _ _ __.}}