ML20066F959
| ML20066F959 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 11/17/1982 |
| From: | Lundvall A BALTIMORE GAS & ELECTRIC CO. |
| To: | Clark R Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20066F961 | List: |
| References | |
| NUDOCS 8211190244 | |
| Download: ML20066F959 (86) | |
Text
1 BALTIMORE GAS AND ELECTRIC l CHARLES CENTER. P. O. BOX 1475 BALTIMORE, MARYLAND 21203 I
ARTHUR E. LUNDVALL, JR.
I v ct PatsaDEM Su aa" )
November 17,1982 I Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C. 20555 ATTENTION: MR. R. A. Clark, Chief Operating Reactors Branch #3 Division of Licensing
SUBJECT:
Calvert Cliffs Nuclear Power Plant Unit 2, Docket No. 50-318 Amendment to Operating License DPR-69 ,
Supplement I to Fifth Cycle License Application 1
REFERENCES:
(A) A. E. Lundvall to R. A. Clark letter dated 10/15/82, " Unit 2 Fif th Cycle License Application" (B) A. E. Lundvall to R. A. Clark letter dated 11/5/82, " Unit No. 2 Request for Amendment" Gentlemen:
Baltimore Gas and Electric Company hereby supplements an earlier request (Reference (A)) for amendment to Operating License DPR-69. The enclosed Supplement I presents discussion in support of the conclusion that the Safety Analyses for an Auxiliary Feedwater Actuation System (Reference (B)) in Unit 2, Cycle 5 envelop and ensure conservative operation at a RATED THERMAL POWER OF 2700 MWth.
TECHNICAL SPECIFICATION CHANGES AND JUSTIFICATION The proposed changes to the Standard Technical Specifications (STS) required by tnis Supplement I are presented in Section 4.0 of the Enclosure to this letter and justified by the discussions in Sections 1.0 through 3.0 of the Enclosure. Also included in Section 4.0 are all the proposed modifications to the STS included in Reference (B) in order that the staff may have a complete package of STS modifications associated with this Supplement 1.
Section 5.0 of the Enclosure proposes a one-time exemption to Technical Specification 3.7.1.2 in order to allow a thorough test of the Auxiliary Feedwater Actuation System (AFAS). Section 5.0 also presents the justification for that exemption.
8211190244 821117 "
l PDR P ADOCK 05000318 pgg j
Office of Nuclear Regulation November 17, 1982 Page 2 t
SAFETY ANALYSES AND REVIEW This supplement and proposed STS changes constitute an unreviewed safety question since consequences of two previously analyzed Design Bases Events (DBE) are more severe, one new DBE is analyzed, and the margin of safety defined in the bases for one STS is slightly reduced from that discussed in Reference (A). However, the Enclosure presents analyses which demonstrate that acceptable limits on DNBR, Reactor Coolant System upset pressure, and 10CFR100 site boundary dose rate guidelines would not be exceeded during a Design Bases Event.
The Plant Operations and Safety Review Committee (POSRC) and Offsite Safety and Review Committee (OSSRC) have reviewed this proposed Amendment and these proposed changes to the Standard Technical Specifications and have concluded that although they constitute an unreviewed safety question they do not present an undue risk to the health and safety of the public.
Very truly yours, -
BALTIMORE GAS AN LECTRIC COMPANY
[
. 46//-
/ A.J. Lundvall, Jr.
ViceNresident - Supp[ly AEL/WJL/Imt Enclosure (40 copies) i l
l i
I
Office of Nuclear Regulation November 17, 1982 Page 3 STATE OF MARYLAND, CITY OF BALTIMORE, TO WIT:
Arthur E. Lundvall, Jr., being duly sworn states that he is Vice President of the Baltimore Gas and Electric Company, a corporation of the State of Maryland; that he executed the foregoing Amendment for the purposes therein set forth; that the statements made in said Amendmcat are true and correct to tne best of his knowledge, information, and belief; and that he was authorized to execute the Amendment on behalf of said Corporation.
WITNESS My Hand and Notarial Seal.
/
l C$6 '
, A L/LA Notary PublK cc: 3. A. Biddison, Esquire G. F. Trowbridge, Esquire D. H. Jatte P. W. Kruse I
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i SUPPLEMENT 1 i
i TO CALVERT CLIFFS UNIT 2 CYCLE 5 REFUELING AMENDMENT 4
SAFETY ANALYSIS l'OR THE SAFETY GRADE i
! AUXILIARY FEEDWATER ACTUATION SYSTEM 4
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This supplement documents the results of the safety analysis performed for the safety j grade Auxiliary Feedwater Actuation System (AFAS) and the associated Technical Specification changes. The safety grade AFAS consists of:
- 1. Automatic initiation of auxiliary feedwater to both steam generators based on a low level signal from either one of the steam generators. This signal is generated ,
when the water level in either steam generator decreases below a nominal setpoint value of -172 inches based on wide range level indication. The safety analysis was performed by including appropriate uncertainties to the nominal setpoint.
- 2. Isolation logic to identify and isolate a ruptured steam generator. A steam generator with lower pressure (in comparison to the other steam generator) is identified as being ruptured and is isolated when the steam generator differential pressure (i.e., lPSG(A) - PSG(B) ) exceeds a nominal setpoint value of 130 psid.
The safety analysis was performed by including appropriate uncertainties to the nominal setpoint.
The Design Basis Events (DBEs) impacted by the safety grade AFAS are: 1) the Loss of Feedwater event,2) the Feed Line Break (FLB) event and 3) the Steam Line Break (SLB) event. These events were analyzed with and without Loss of AC power on turbine trip.
In addition, a spectrum of break sizes were analyzed for the FLB and SLB events. Table 1 presents the reasons for analysis of each event, the acceptance criterion used in judging the results and a summary of results obtained. Detailed presentations of the results of the analysis are provided in Sections 1.0 through 3.0.
Section 4.0 presents the Technical Specification changes associated with the safety grade AFAS.
A summary of the analysis setpoints for the Reactor Protection System (RPS) and AFAS assumed in the analysis of each DBE is given in Table 2. For completeness, the table also presents the Technical Specification setpoints and the associated uncertainties.
Section 5.0 proposes a one time exemption to Technical Specification 3.7.1.2 in order to allow a thorough test of AFAS.
TABLE 1 EVENTS ANALYZED FOR SAFETY GRADE AUXILIARY FEEDWATER ACTUATION SYSTEM Reason for Acceptance Omry Event Reanalysis Criterion of Results Loss of Determine acceptability Peak pressure The peak pressure Feedwater of analysis setpoint less than upset is 2574 psia. The to initiate auxiliary pressure limit steam generator feedwater and analysis of 2750 psia water mass does not setpoint for flow snd ensure that decrease below controller. adequate heat 37,500 lbm. Thus, sink is main- results are tained during the acceptable.
event. For further details see Section 1.0 Feed Line Determine acceptability Peak pressure The peak pressure Break of analysis setpoint less than upset is 2749 psia *.
to initiate auxiliary pressure limit The O to 2 hr feedwater and analysis of 2750 psia. thryroid dose setpoint for isolation The 0-2 hr site (DEQ I-131) is logic to isolate doses are within 2.2 REM. For ruptured steam 10CFR100 guide- further details see generator, lines. Section 2.0
- Steam Line Determine acceptability For breaks outside The O to 2 hr Break of analysis setpoint containment, the thyroid dose for isolation logic site boundary doses (DEQ I-131) is to isolate ruptured are within 10CFR100 67.0 REM.
steam generator. guidelines.
For breaks inside The minimum post-containment the trip DNBR is 1 31.
post-trip DNBR is Ihus, the results greater than 1 3 are acceptable.
using McBeth For further details correlation. see Section 3 0
- The peak pressure value quoted is for a FI.B event with Loss of AC Power on turbine trip.
9 e
TABLE 2 RPS AND AFAS SETPOINTS ASSUMED IN SAFETY ANALYSIS RPS and AFAS Tech. Spec. Analysis DBE Function Setpoint Uncertainty Setpoint Loss of Steam Generator 10" below top 10" 20" below top Feedwater Low Level Trip of feed rfag of feed ring High Pressurizer 2400 psia 22 3 psia 2422 3 psia Pressure Trip (HPPT)
Steam Generator >44.L% 2.0% 42.4%
Low Level Signal T-194 inches) (9 inches) (-203 inches) to Initiate Auxiliary Feedwater C II Auxiliary Feedwater 160 GPM 70 GPM 90 GPM Flow Controller Feed Line High Pressurizer 2400 psia 67 4 psia 2467.4 psia Break Pressure Trip .
Steam Generator >42 9% 13 8% 29 1%
Low Level Signal T-202 inches) (64 inches) (-266 inches) to Initiate Auxiliary Feedwater fl)
Auxiliary Feedwater 160 GPM 70 GPM 90 GPM '
Flow Controller Steam Generator 130 paid 120 psid 10 psid(2)
Differential Pressure to Isolate Ruptured Steam Generator Steam Lcw Steam Generator 685 psia 83 1 psia 600 psia
. Line Pressure Trip Break
TABLE 2 (continued)
RPS and AFAS Tech. Spec. Analysis DBE Function Setpoint Uncertainty Setpoint Steam Steam Generator 130.0 psid 120.0 psid 250.0 psid Line Differential Break Pressure to Isolate Ruptured Steam Generator Steam Generator <54.4% 6.5% 60 9%
Low Level Signal T-148 ir.ches) (30 inches) (-118 inches) to Initiate Auxiliary Feedwater(II i
(I)% of the distance between steam generator wide range upper and lower level instrument taps (-401 inches to 43 5 inches).
(2)For additional conservatism in the ana)vsis, no auxiliary feedwater flow to the ruptured steam generator was assumed.
l
1.0 Loss of Feedwater Flow Event The Loss of Feedwater Flow event was reanalyzed for Calvert Cliffs Unit 2 Cycle 5 to demonstrate that the RCS pressure limit of 2750 psia is not exceeded and that an adequate heat sink is maintained during the event.
he event is reanalyzed to incorporate the effects of the safety grade Auxiliary Feedwater Actuation System. This system includes actuation of auxiliary feedwater based on wide range steam generator level indication and isolation logic to identify the ruptured steam generator based on steam generator differential pressure. The event was analyzed with and without loss of AC power on turbine trip.
Analysis Assumptions and Initial Conditions Table 1-1 presents the initial conditions chosen to maximize tge RCS pressure. A Moderator Temperature Coefficient (MTC) of +0.5x10 ao / F is assumed in the analysis. This MFC in conjunction with increasing coolant temperatures, adds positive reactivity and thus maximizes the rate of change of heat flux and pressure at the time of trip. A Fuel Temperature Coefficient (FTC) corresponding to beginning of cycle conditions was used in the analysis. Bis FTC causes the least amount of negative reactivity feedback, allowing higher increases in both the heat flux and RCS pressure. An uncertainty factor of 15% is used in the analysis. An initial pressure of 2154 psia is used in the analysis to maximize the rate of change of pressure at time of trip and thus the peak pressure obtained following a reactor trip. This initial pressure corresponds to the minimum allowed Technical Specification limit of 2200 psia and includes a conservatively high instrument uncertainty of 46 psia. An initial steam generator pressure of 815 psia is assumed in the
- analysis. his pressure delays the opening of the Main Steam Safety Valves (MSSVs), decreases the steam releases through the MSSVs and maximizes the peak RCS pressure. The Steam Dtanp and Bypass System (SDBS),
the Pressurizer Pressure Control System (PPCS), the Pressurizer Level Control System (PLCS) and the Power Operated Relief Valves (PORV) are assumed to be in the manual mode of operation. This assumption enhances the RCS pressure increase since the automatic operation of these system mitigates the RCS pressure increase.
Table 1-3 presents the initial conditions chosen to analyze the Loss of Feedwater Flow to determine whether an a during the event. An MTC of +0 5x10 gequate ao / F isheat sink is maintained assumed since this results in a greater rise in core power and heat flux prior to reactor trip. An EOC FTC was selected since it results in slower power rampdown after reactor trip, and thus maximizes rate of steam generator inventory depletion. The SDBS is assumed to be in the automatic mode of operation and an initial steam generator pressure of 915 psia is chosen. These assumptions increase the steam flow out of the secondary system via SDBS and MSSVs, and maximize the rate of steam generator inventory depletion.
An auxiliary feedwater actuation analysis setpoint of 42.4% of steam generator wide range span is assumed in this analysis. This represents a Technical Specification a4:tuation setpoint of 44.4% and includes a 2.0%
uncertainty. The actuation signal activates a motor driven auxiliary feedwater pump and a steam driven auxiliary feedwater pump which deliver auxiliary feedwater to both steam generators. The motor driven pump's auxiliary feedwater reaches the steam generato 18.0 seconds after low
steam generator level signal is iniviated. Bis includes 14.5 seconds for the pump to accelerate to speed including all signal processing delays and 35 seconds for water to travel through piping and reach the steam i generator. !
he flow from the motor driven pep to each steam generator is controlled '
o by a flow control valve installed in the " leg" connecting the pump to the steam generator. A minimum flow of 90 gpm through each leg is conservatively assumed in the analysis. It represents the Technical Specification limit on AW flow rate of 160 gpm through the flow control valve and an uncertainty of 70 gpm.
The steam driven pump's auxiliary feedwater reaches the steam generator 58.0 seconds after Auxiliary Feedwater Actuation setpoint is reached.
! his includes 50 seconds required to open steam admission valves to the pump, 4.5 seconds for the pump to accelerate to speed and 3 5 seconds for water to travel through piping and reach the steam generator. He flow from the steam driven pump to each steam generator is also controlled by a flow control valve installed in the flow " leg" connecting the pep to the i steam generator. A flow of 90 gpm through each leg is assumed in the analysis. It represents the Technical Specification limit on AW flow rate of 160 gpm through the flow control valve and an uncertainty of 70 gpm.
In case of loss of AC at turbine trip, there is an additional delay time involved for the motor driven pump. It includes 10 seconds for the diesel generators to start and reach speed following the LOAC and 30 seconds for the motor driven pump to be loaded on line.
Results he results of the Loss of Feedwater event show that with respect to RCS peak pressure, the case with LOAC on turbine trip is more limiting than
, the case with no LOAC. Ioss of AC power on turbine trip causes the RCS i
pumps to coastdown and dump and bypass valves to shut. Both effects contribute to the primary heatup and pressurization: the former by reducing the heat transfer rate from primary to secondary and the latter by temporarily suppressing the steam release out of the steam generators and raising the steam generator pressure before MSSVs open.
The sequence of events for the Loss of Feedwater Flow event with Loss of AC on turbine trip analyzed to determine the peak RCS pressure is i presented in Table 1-2. Figures 1-1 through 1-5 present the transient behavior of core power, core average heat flux, RCS temperatures, RCS pressure and steam generator pressure. The results show that High Pressurizer Pressure analysis trip setpoint is reached at 21.5 seconds.
Loss of AC power occurs at 22 9 seconds and RCS pmps start to coastdown.
The primary safety valves begin to open at 24 3 seconds and the pressure reaches a maximum of 2574 psia at 25 3 seconds. The increase in secondary pressure is limited by the opening of MSSVs at 25.9 seconds. ne steam generator pressure reaches a maximum of 1048 psia at 29 7 seconds.
The results of the analysis show that with respect to steam generator water inventory, the Loss of Feedwater event is less limiting when LOAC on turbine trip occurs. Loss of AC power causes Steam Dump and Bypass Valves
to close, thereby reducing the total steam flow out of the steam generators and leaving more masa in them.
The sequence of events for the Loss of Feedwater Flow event without LOAC on turbine trip analyzed to maximize steam generator inventory depletion is given in Table 1-4. Figures 1-6 through 1-12 present the transient behavior of core power, core average heat flux, RCS temperatures, RCS pressure, steam generator pressure, steam generator water mass and auxiliary feedwater flow to the steam generator. The results of the analysis show that the low steam generator level trip setpoint is reached at 18.0 seconds and the CEAs begin to drop at 19 4 seconds. A signal to open Steam Dump and Bypass is generated at 19 0 seconds. At 21.2 seconds MSSVs begin to open to limit the increase in steam generator pressure.
Maximum steam generator pressure of 1048 psia is reached at 25 0 seconds.
At 37.1 seconds the Auxiliary Feedwater Actuation setpoint is reached.
The motor driven pump's auxiliary feedwater flow reaches the steam generator at 55 1 seconds. The steam driven pump's auxiliary feedwater flew reaches the steam generator at 95.1 seconds. Each pump delivers 90 gpm to each steam generator. The analysis shows that this flow rate is sufficient to maintain an adequate heat sink during the transient.
Conclusion In conclusion, the results of the Loss of Feedwater Flow event with and without Loss of AC following the reactor trip demonstrate that the peak pressure does not exceed the upset limit of 2750 psia and that an adequate heat sink is maintained during the event. .
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TABLE 1-1 KEY PARAMETERS ASSUMED IN THE LOSS OF FEELVATER ANALYSIS TO MAXIMIZE CALCULATED RCS PEAK PRESSURE Parameter Units Value Initial Core Power Level MWt 2754 CF Initial Core Coolant Inlet 550 Temperature Initial RCS Vessel Flow Rate gpm 370,000 Initial Reactor Coolant System psia 2154 Pressure Initial Steam Generator Pressure psia 815 Initial Pressurizer Liquid Volume ft3 975 Moderator Temperature Coefficient x10~"ao/0F 45 Doppler Coefficient Multiplier 0.85 High Pressurizer Pressure Analysi.= psia 2422 3 Trip Setpoint Reactor Gegulating System Operating Mode Manual **
Steam Dump and Bypass System Operating Mode Manual **
Pressurizer Pressure Control Operating Mode Manual **
System Pressurizer Level Control System Operating Mode Manual **
- These modes of control system operation maximize the peak RCS pressure.
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TABLE 1-2 SEQJENCE OF EVENTS FOR LOSS OF FEEDWATER FLOW ANALYSIS TO MAXIMIZE CALCULATED RCS PEAK PRESSURE WITH LOAC Time (sec) Event Setpoint or Value 0.0 Loss of Main Feedwater 21.5 High Pressurizer Pressure Trip 2422 3 psia Setpoint Reached 22.4 Trip Breakers Open 22.8 Turbine Stop Valves Close 22.9 CEAs Begin to Drop Into Core, loss of AC Power 24 3 Primary Safet:' Valves Begin to Open 2500 psia 25 3 Maximum RCS Pressure 2574* psia 25 9 Steam Generator Safety Valves 1000 psia Begin to Open 29 1 Primary Safety Valves Close 2400 psia 29 7 Maximum Steam Generator Pressure 1048 psia
- Pressure Includes Elevation Head
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TABLE 1-3 KEY PARAMETERS ASSUMED IN THE LOSS JF FEEDWATER ANALYSIS TO MAXIMIZE STEAM GENERATOR INVENTORY DEPLETION
?araneter Units Value Initial Core Power Level MWt 2754 Initial Core Coolant Inlet OF 550 Temperature Initial RCS Vessel Flow Rate gpm 370,000 Initial Reactor Coolant System psia 2154 Pressure Initial Steam Generator Pressure psia 915 Initial Pressurizer Liquid Volume ft3 975 Moderator Temperature Coefficient x10~"ao /0F +0 5 Doppler Coefficient Multiplier 0.85 Steam Generator Low Level Analysis inches below top 20.0 Trip Setpoint of feed ring Auxiliary Feedwater Actuation % Wide Range Steam 42.4 Analysis Setpoint Generator Level Indication Auxiliary Feedwater Flow BTU /lbm 80.0 Enthalpy .
Reactor Regulating System Operating Mode Manual **
Steam Dump and Bypass System Operating Mode Automatic 5*
Pressurizer Pressure Control Operating Mode Manual **
System Pressurizer Level Control System Operating Mode Manual **
- These modes of control system operation maximize the steam generator water inventory depletion rate.
TABLE 1-4 SEQUENCE OF EVENS FOR LOSS OF FEEDWATER FLOW ANALYSIS TO MAXIMIZE STEAM GENERATOR INVENTORY DEPLETION Time (sec) Event Setpoint or Value 0.0 Loss of Main Feedwater -
2.0 S.G. Bypass Valve Opens 895 psia 18.0 Steam Generator Low Water 20 inches below the Level Analysis Trip Setpoint top of the feed ring is Reached 18.9 Trip Breakers Open 19 0 S.G. Dump Valve Opens -
l 19 3 Turbine Valves close 19 4 CEAs Begin to Drop Into Core -
21.2 Steam Generator Safety Valves 1000 psia Begin to Open 22.6 Maximum RCS Pressure 2364* psia f
25 0 Maximum Stean Generator ' Pressure 1048 psia 37 1 Auxiliary Feedwater Actuation 42.4%**
Analysis Setpoint is Reached 51.6 Motor Driven Auxiliary Feed Ptap Reaches Rated Speed 55 1 Motor Driven Auxiliary Feedwater 90 gpm/S.G.
Enters Both Steam Generators I
87 1 Steam Admission Valves to Steam Driven Auxiliary Feedwater Pump Opens l
91.6 Steam Driven Auxiliary Pump Reaches Rated Speed 95 1 Steam Driven Auxiliary Feedwater 90 gpm/S.G.
Enters Both Stean Generators
' Pressure includes elevation head
- % of distance between steam generator wide range upper and lower level instrument taps.
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, 2.0 Feedline Break Event Introduction he Feed Line Break (FLB) event was analyzed for Calvert Cliffs Unit 2 Cycle 5 to demonstrate that the RCS pressure limit of 2750 psia is not exceeded and that the site boundary doses do not exceed 10CFR100 guidelines. The event is analyzed to incorporate the effects of the safety grade auxiliary feedwater actuation system. This system includes actuation of auxiliary feedwater based on wide range steam generators differential pressure. The event was analyzed with and without Loss of AC Power on turbine trip. A spectrian of break sizes were considered in the analysis and the results of the limiting break size is presented herein.
~
Discussion t
The 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 I
cooldown of the Nuclear Stean 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, l otherwise. Break locations are identified with respect to the feedwater line reverse flow check valve. There is one reverse flow check valve per feed line and it is located between the steam generator feedwater nozzle and the containment penetration. Closure of the check valve to prevent
- reverse flow from the steam generator maintains the heat removal j capability of that generator in the presence of a break upstream of the check valve. ,
Feed line breaks upstream of the reverse flow check valve can initiate one of the following transients. A break of any size with MFS unavailable will result in a Loss of Feedwater Flow (LOW) event. A small pipe break with MFS available will result in no reduction in feedwater flow.
Depending on the break size, a large break with MFS available will result in either a partial or a total LOW event. Since FLBs upstream of the reverse flow check valve result in transients no more severe than a LOW event (see Section 1.0 for the results of the LOW event), these FLBs were not analyzed.
In addition to the possibility of partial or total LOW, FLBs downstream of the check valve have the potential to establish reverse flow from the ruptured steam generator back to the break. Reverse flow occurs whenever the MFS is not operating subsequent to a pipe break or when the MFS is operating but without sufficient capacity to maintain pressure at the break above the steam generator pressure. FLBs which develop reverse flow through the break are limiting with respect to primary overpressure.
Thus, only these FLBs were considered in the analysis.
FLBs downstream of the check valve with reverse flow may result in either a RCS heatup or a RCS cooldown event depending on the enthalpy of the
, reverse ficw and the heat transfer characteristics of the ruptured steam generator. However, excessive heat removal through the feed line break is not considered in the analysis because the cooldown potential is less than i
that for the Steam Line Br9ak (SLB) event (see Section 3 0 for the results
- of the SLB event). This occurs because SLBs have a greater potential for
l
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discharging high enthalpy fluid due to the location of the steam piping which additionis located above the feedwater piping within a stfam generator. In the maximum break area for a FLB is 1.4 ft in comparison to 6 305 ft2for a SLB.
Unlike SLBs, FLBs cause a decrease in feedwater flow, resulting in lower steam generator liquid inventory which reduces the heat removal capacity.
The reduced heat transfer capability results in a rapid RCS overpressurization and, thus, it is the heatup potential of a FLB which is analyzed and reported herein.
A general description of the FLB event downstream of the check valves, with the MFS unavailable and with low enthalpy break discharge is given below. De loss of subcooled feedwater flow to both steam generators causes increasing steam generator temperatures, decreasing liquid inventories and decreasing water levels. De rising secondary temperature reduces the primary-to-secondary heat transfer which results in a heatup and pressurization of the RCS. Be heatup becomes more severe as the ruptured steam generator experiences a further reduction in its heat transfer capability due to decreasing liquid inventory as the discharge through the break continues. De heatup of the RCS and the depletion of liquid inventory in the steam generator will initiate a reactor trip on either High Pressurizer Pressure or Steam Generator Low Water Level. The
, RCS heatup can continue even after a reactor trip due to a total loss of heat transfer in the ruptured steam generator as the liquid inventory is completely depleted. De rise in RCS pressure causes the Pressurizer Safety Valves (PSVs) to open. he rise in secondary pressure is limited by the opening of the Main Steam Safety Va}ves (MSSVs). De opening of the PSVs and the MSSVs in conjunction with the reactor trip (which reduces core power to decay level) mitigates the RCS overpressurization.
The reduction in liquid inventory in the undamaged steam generator initiates auxiliary feedwater flow to both steam generators. As the steam generator differential pressure reaches the AFW isolation logic setpoint, AFW flow to the ruptured steam generator is terminated. The automatic initiation of AFV flow to the undamaged steam generator in conjunction with operator action to increase the AFW flow rate is sufficient to remove , ,
decay heat. '
Analysis Asstaptions and Initial Conditions he following is a discussion of the conservative assumptions and initial conditions chosen to maximize RCS pressure. Blowdown of the stean generator nearest the feedwater line break is modeled assuming frictionless critical flow as calculated by the Henry-Fauske correlation' (Reference 1). He feed line break location is conservatively modeled to be near the bottom of the steam generator, even though in reality, the feed line nozzle is at a much higher elevation within the steam generator. The analysis assumes that saturated liquid is discharged s through the break until the liquid mass reaches 5000 lbm, at which time saturated steam discharge is assumed. This assumption maximL2es the liquid inventory discharge through the break and minimizes :the energy removal from the steam generator through the break. It also minimizes the ruptured steam generator heat transfer capacity and thereby marimizes the RCS overpressurization.
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l The analysis also assumed that the effective heat transfer area is decreased linearly as the steam generator liuuid mass decreases. The mass interval over which the rampdown is assumed to occur is conservatively chosen to model a rapid loss of heat transfer in the ruptured steam !
generator.
To maximize RCS pressure, the analysis conservatively credited only the high pressurizer pressure trip. This assumption maximizes the rate of change of pressure at the time of trip and thus the peak pressure obtained i following the trip. The analysis did not credit either the high containment pressure trip or the steam generator low water level trip.
Table 2-1 presents the initial conditions chosen to maximize the RCS pressure. A Moderator Temperature Coefficient curve corresponding to beginning of cycle conditions is assumed. This MTC in conjunction with increasing coolant temperatures adds positive reactivity and, thus, maximizes the rate of change of heat flux and pressure at the time of trip. A Fuel Temperature Coefficient (FTC) corresponding to beginning of cycle conditions was used in the analysis. This FTC causes the least amount of negative reactivity feedback, allowing higher increases in both
, the heat flux and RCS pressure. An uncertainty factor of 15% is used in the analysis.
~
An initial pressure of 2154 psia is used in the analysis to maximize the rate of change of pressure at time of trip and, thus, the peak pressure obtained following a reactor trip. Bis initial pressure corresponds to the minimum allowed Technical Specification limit of 2200 psia and includes a conservatively high instrument uncertainty ,of 46 psia. An initial steam generator pressure of 815 psia is assumed in the analysis.
, This pressure delays the opening of the Main Steam Safety Valves (MSSVs) and maximizes the peak RCS pressure.
The Steam Dtap and Bypass System (SDBS), the Pressurizer Pressure Control System (PPCS), the Pressurizer Level Control System (PLCS) and the Power Operated Relief Valves (PORV) are assumed to be in the manual mode of operation. Bis assumption enhances the RCS pressure increase since the automatic operation of these systems mitigates the RCS pressure increase.
i Auxiliary feedwater actuation analysis setpoint of 29 1% of steam generator wide range span is assumed in this analysis. This represents a Technical Specification actuation setpoint of 42.9% and includes a 13 8%
uncertainty. The actuation signal activates a motor driven auxiliary feedwater pump and a steam driven auxiliary feedwater pump which deliver auxiliary feedwater to both steam generators. The motor driven pump's auxiliary feedwater reaches the steam generator 18.0 seconds after low steam generator level signal is initiated. This includes 14 5 seconds for the pump to accelerate to speed including all signal processing delays and 35 seconds for water to travel through piping and reach the steam
! generator.
The flow from the motor driven pump to each steam generator is controlled by a flow control valve installed in the " leg" connecting the pump to the steam generater. A minimum flow of 90 gpm through each leg is
(, , conservatively assumed in the analysis. It represents the Technical Specification limit on AFW flow rate of 160 gpm 'hrough the ficw control valve and an uncertainty of 70 gpm.
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The steam driven pump's auxiliary feedwater reaches the steam generator 58.0 seconds after Auxiliary Feedwater Actuation setpoint is reached.
This includes 50 seconds required to open steam admission valves to the pap, 4.5 seconds for the pep to accelerate to speed and 3 5 seconds for water to travel through piping and reach the steam generator. The flow from the steam driven pump to each steam generator is also controlled by a clow control valve installed in the flow " leg" connecting the pump to the steam generator. A flow of 90 gpm through each leg is assumed in the analysis. It represents the Technical Specification limit on AFW flow rate of 160 gpm through the flow control valve and an uncertainty of 70 gpm.
In case of loss of AC at turbine trip, there is an additional delay time involved for the motor driven pump. It includes 10 seconds for the diesel
- generators to start and reach speed following the LOAC and 30 seconds for the motor driven pump to be loaded on line.
The assmptions made to maximize the boundary site dose are given in Table 2-2. During the event, two sources of radioactivity contribute to the site boundary dose. The initial activity in the steam generator and the activity associated with primary to secondary leakage. The leakage through the steam generator tubes is assmed to be the Technical Specification limit of 1.0 GPM. The initial primary and secondary activities are assmed to be at the Technical Specification limits of 1.0 pCi/gm and 0.1 uCi/gm, respectively. The analysis assumes that all of the initial activity in the steam generators and the primary activity due to the tube leakage are released to the atmosphere with a decontamination factor of.1.0, resultiing in the maximum site boundary dose. '
Results he FLB event with Loss of AC (LOAC) power on turbine trip results in the maximum RCS pressure. This occurs because LOAC power causes the Reactor
. Coolant Pumps to coastdown. The reduced core flow decreases the rate of heat removal and, thus, maximizes the primary heatup and overpressurization. Thus, only the results of the FLB event with LOAC power on turbine trip are presented herein.
Figure 2-1 presents the results of the parametric study to determine the break size which leads to the highest RCS peak pressure. Figure 2-1 shows that, initially as the break size increases, so does the peak RCS pressure. This is due to faster water drainage out of the ruptured generator, which will cause a more rapid primary to secondary heat transfer rampdown. However, as the break size increases further, the greater steam relieving capacity of larger breaks once the ruptured steam generator feedwater nozzle uncovers will offset the faster heat transfer rampdown and will result in lower peak pressuge. The highest peak pressure was obtained for a break size of 0.275 ft .
The sequence of events for a 0.275 ft2 Feed Line Break downstream of the reverse flow check valve with LOAC on turbine trip is given in Table 2-3 Figures 2-2 through 2-7 present the transient behavior of core power, core average heat flux, RCS temperatures, RCS pressure, steam generator pressure and steam generator liquid inventory for 1800 seconds of transient.
l 2
A 0.275 ft break in the main feedwater line in assumed to instantaneously terminate feedwater flow to both steam generators and '
establish critical flow from the steam generator nearest the break.
During the first 24.6 seconds of the event, the absence of subcooled feedwater flow causes the secondary pressure and temperature to increase, which reduces the primary to secondary heat transfer. mis causes the primary pressures and temperatures to increase. At 24.6 seconds, the liquid inventory in the ruptured steam generator is sufficiently depleted to cause a further rampdown in the heat transfer rate.. This causes the primary pressure and temperature to rapidly increase and at the same time causes the secondary pressure to decrease.
Be rapid increase in primary pressure initiates a' High Pressur.zer Pressure trip at 27.1 seconds. At 27.7 seconds, the pressure reaches 2500 psia, at which time the Pressurizer Safety Valves (PSVs) open to mititage the increase in primary pressure. At 28.4 second$, the turbine stop valves close, increasing the secondary pressure. At 28.5 seconds, the
! CEAs begin to drop into the core, inserting negattive reactivity which mitigates the primary heatup. However, at this timel, the Reactor Coolant Ptanps (RCPs) are asstaned to initiate flow coastdowrt due to LOAC power on turbine trip. The rapid decrease in core flow slows /down the rate of heat removal from the primary. At 28.6 seconds, the feed line break is uncovered and steam is discharged through the bresk, which mitigates the primary heatup. These competing effects results ih a peak RCS pressure of 2749 psia at 31.2 seconds. The increase in/ secondary pressure is mitigated by the opening of the Main Steam Safett Valves in the undamaged and ruptured steam generator at,35.1 and 36 3 seconds respectively.
- A low steam generator level in the undamaged ' steam generator initiates AFAS at 60.0 seconds. The AFW flow from the motor driven pump reaches the undamaged steam generator at 86.5 seconds. The AFW flow from the steam driven pump reaches the undamaged steam generator at 118.0 seconds. (It should be noted that AFW flow at these times would also have been fed to the ruptured steam generator but no creditj was taken for this in the analysis.) The AFW flow in conjunction with the j steam release through the break causes the secondary and primary tynperatures and pressure to decrease.
At 188.5 seconds a steam Generator Isolation Signal is generated. After appropriate delays, the Main Steam Isolation Valves (MISVs) close at 201.4 seconds. This causes the pressure in the undamaged steam generatcr to increase rapidly and the pressure in the ruptured steam generator to decrease. An AFW isolation signal based on ste:m generator differential pressure is initiated at 202.0 seconds and the AFV block (i.e., isolation) valve completely closes at 222.0 seconds.
The water level in the undamaged steam generator continues to decrease as a result of boil-off. At about 250.0 seconds the liquid inventory in the undamaged steam generator is sufficiently depleted that there is no heat transfer from primary to secondary. This causes the primary pressure and temperature to increase again. The increase in primary pressure results in the opening of PSVs at 579 5 seconds.
The analysis conservatively assumed that the operator takes the necessary action to increase AFV ficw at 10 minutes follcwing reactor trip. Thus,
1 l
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at 628.5 seconds, AW flow is increased to the undamaged steam generator, which slowly reduces the primary heatup. The PSVs close at 688.0 seconds.
The resultant site boundary dose calculated with the asstaptions given in Table 2-2 is:
Thyroid (DEQ I-131) = 2.2 REM Conclusion The results of the FLB event with LOAC power on turbine trip shows tht the peak pressure does not exceed the pressure upset limit of 2750 psia and that the site boundary doses are within 10CFR100 guidelines.
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a TABLE 2-1 KEY PARAMETERS ASSUMED IN THE FEEDWATER LINE BREAK ANALYSIS Parameter Units Value Initial Core Power Level MWt 2754.0 O
Initial Core Coolant Inlet F 550.0 Temperature Initial RCS Vessel Flow Rate gpm 370,000.0 Initial Reactor Coolant System psia 2154.0 Pressure Initial Steam Generator Pressure psia 815 0 Initial Pressurizer Liquid Volume ft 975.0 Effective Moderator Temperature x10# ap/0F 4.2 Coefficient Doppler Coefficient Multiplier 0.85 High Pressurizer Pressure psia 2467.4 Analysis Trip Setpoint Auxiliary Feedwater Actuation 5WideREige 29 1 Analysis Setpoint Steam Generator Level Indication Steam Generator Differential psid 10.0 Pressure Analysis Setpoint CEA Worth at Trip % ao -5 2 Reactor Regulating System Operating Mode Manual **
Steam Dump and Bypass System Operating Mode Manual **
Pressurizer Pressure Cont: cl Operating Mode Manual **
System Pressurizer Level Control System Operating Mode Manual **
- These modes of control system operation raaximize the peak RCS presstre.
l l
TABLE 2-2 I ASSUMPTIONS FOR IEE RADIOLOGICAL EVALUATION FOR IliE FEED LINE BREAK EVENT Parameter Units Value Reactor Coolant System Maximum pCi/gm 1.0 Allowable Concentration (DEQ I-131)1 pCi/gm 0.1 SteamGeneratorMaximumA}lowable Concentration (DEQ I-131)
Partition Factor Assumed for 1.0 All Doses Atmospheric Dispersion Coefficient 2 sec/M 3 1.80x10-"
Breathing Rate M3 f3.c 3,47x10 4 Dose Conversion Factor (I-131) REM /Ci 1.48x10 6 I Tech Spec limits 20-2 hour accident condition
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TABLE 2-3 SEQUENCE OF EVENTS FOR FEED LINE BREAK ANALYSIS I WITH LOAC FOLLCWING REACTOR TRIP 1
Time (sec) Event Setpoint or Value 0.0 Break in the Main Feedwater 0.275 ft 2 Line Instantaneous Loss of All Feedwater Flow to Both Steam Generators 24.6 Heat Transfer Rampdown Begins 19691 lbm in the Ruptured Steam Generator 27 1 High Pressurizer Pressure Trip 2467.4 psia Setpoint is Reached 27.7 Primary Safety Valves Open 2500 psia 28.0 Trip Breakers Open 28.4 Turbine Stop Valves Close 28 5 CEAs Begin to Drop Loss of AC Power on Turbine Power; Diesel Generators Start Coming On Line; RCPs *
. Coastdown Begins 28.6 Level in the Re.stured Steam 5000 lbm Generator Goes Below the Assumed Nozzle Level Steam Will Be Blown Out of the Break 31.2 Maximum RCS Pressure 2749# psia 35.1 Undamaged Stean Generator 1000 psia Safety Valves Open 36 3 Ruptured Steam Generator 1000 psia Safety Valves Open 38.5 Diesel Generators Reach Rated Speed and Voltage Following LOAC Power 38.7 Maximum Steam Generator Pressure, Undamaged / Ruptured 1022/1009 psia 43 5 Primary Safety Valves Close 2400 psia
- Pressure Includes Elevation Head
TABLE 2-3 (continued)
Time (sec) Event Setpoint or Value 55.5 Steam Generator Safeties are 1000 psia Closed 60.0 Auxiliary Feedwater Actuation 29 15" Analysis Setpoint is Reached in Undamaged Steam Generator 68.5 Motor Eriven AFW Pump is loaded on Diesel Generator 83 0 Motor Diven Auxiliary Feed Pump Reaches Rated Speed 86.5 Motor Driver. Auxiliary Feedwater 90.0 GPM Enters Undamaged S.G.
110.0 Steam Admission Valves to Steam Driven Auxiliary Feedwater Pump Open 114.5 Steam Driven Auxiliary Pump Reaches Rated Speed 118.*0 Steam Driven Auxiliary Feedwater 90.0 GPM
- Flow Enters Undamaged Steam Generator 138.5 Heat Transfer Rampdown Begins in 19691 lbm Undamaged Steam Generator 188.5 Steam Generator Isolation 600.0 psia Analysis Setpoint is Reached 189 4 Main Steam Isolation Valves Start to Close 201.4 Main Steam Isolation Valves are Completely Closed .
202.0 Steam Generator Differential t.P i: 10.0 psid Pressure Analysis Setpoint is Reached 222.0 AFW Block Valve Completely Closed 250.0 Undamaged Steam Generator Empties
- % of distance between steam generator wide range upper and lower level instrument taps.
TABLE 2-3 (centinued)
Time (sec) Event Setpoint or Value 445.0 Undamaged Steam Generator Safety 1000.0 psia Valves Open 519 5 Primary Safety Valves open 2500.0 psia 628.5 Operator Increases Auxiliary 400.0 GPM Feedwater Flow to Undamaged Stean Generator 688.0 Primary Safety Valves Close t
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4 2700 s2 m .
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ce 2600 O.2 0.4 0.6 0.8 1.0 1.2 l'. 4 BREAK SIZE, FT2
- PRESSURE INCLUDES ELEVATION HEAD FEED LINE BREAK EVENT FIGURE GAS & $E R CO.
calvert cli ns REACTOR COOLANT SYSTEM PEAK PRESSURE VS BREAK SIZE 2-1 j Nuclear Power Plant
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s ec cAsl1vegtci$$s 9' WITH LOAC FOLLOWING REACTOR TRIP c - 2-2 Nuclear Power Plant CORE POWER VS TIME
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0 0 300 600 900 1200 1500 ' 1800 TIME, SECONDS BALTIMORE FEED LINE BREAK EVENT GAS & ELECTRIC CO. FIGURE WITH LOAC FOLLOWING REACTOR TRIP calvert cifffs 2-3 Nuclear Power Plant CORE HEAT FLUX VS TIME
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0 300 600 900 1200 1500 1800 TIME, SECONDS .
BALTIMORE GAS FEED LINE BREAK EVENT ~
- ' FIGURE Calve t C s WITH LOAC FOLLOWING REACTOR TRIP Nuclear Power Plant 2-6 STEAll GENERATOR PRESSURE VS TIME
140000 i i i i i 120000 -
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, 100000 -
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FIGURE Calve t C1 s WITH LOAC FOLLOWING REACTOR TRIP 2-7 Nuclear Power Plant STEAM GENERATOR WATER INVENTORY VS TIME
3.0 Steam Line Break Introduction he Steam Line Break event was reanalyzed for Calvert Cliffs Unit 2 Cycle 5 to demonstrate that the post-trip minimum DNBR will not exceed the limit of 13 (MacBeth correlation) and that the site boundary doses will be within the 10CFR100 guidelines. The event was reanalyzed to incorporate the effects of the safety grade Auxiliary Feedwater Actuation Systeam (AFAS). This includes actuation of auxiliary feedwater based on wide range steam generator level indication and isolation logic to identify the ruptured steam generator based on steam generator differential pressure.
A spectrum of stean line break sizes, both inside and outside containment initiated from Hot Full Power (HFP) and Hot Zero Power (HZP) were analyzed. In addition, the analysis was performed with and without Loss of AC (LOAC) power on turbine trip. The results of the limiting steam line break size, inside and outside containment is presented herein.
Analysis Assumptions and Initial Conditions SLB Inside Containment _
Be HFP SLB event was initiated from the conditions listed in Table 3-1.
De Moderator Temperature Coefficient (MTC) of reactivity assumed in the analysis corresponds to end of life, since this MTC results in the greatest positive reactivity change during the RCS cooldown caused by the Steam Line Rupture. Since the reactivity change associated with moderator feedback varies significantly over the poderator density covered in the analysis, a single value,ofcurve MTC, of is reactivity assumed ininsertion versus The the analysis. density rathercooldown moderator than a curve assumed in the analysis is given in Figure 3-1. Bis moderator cooldown curve was conservatively calculated assuming that on reactor scram the Control Element Assembly is stuck in the fully withdrawn position which yields the most severe combination of scram worth and
. reactivity insertion.
I Re reactivity defect associated with the fuel temperature decrease is also based on an end of life Doppler defect. The Doppler defect based on an end of life Fuel Temperature Coefficient (FTC), in conjunction with the l decreasing fuel temperatures, causes the greatest positive reactivity
- insertion during the Steam Line Rupture event. The uncertainty on the FTC assumed in the analysis is given in Table 3-1. De S fraction assumed is the maximum absolute value including uncertainties for end of life conditions. This too is conservative since it maximizes subcritical multiplication and thus, enhances the potential for Return-To-Power (R-T-P). The analysis also assumed a conservatively low value of boron reactivity worth of -1.0 h per 95 PPM for safety injection flow from the High and Low Pressure Safety Injection pumps.
De minimum CEA worth assumed to be available for shutdown at the time of reactor trip at the maximum allowed power level is 6.89% ao . This available scram worth was calculated for the stuck rod which produced the moderator cooldown curve in Figure 3-1.
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Du-ing a return-to-power, negative reactivity credit was assumed in the analysis. This negative reactivity credit is due to the local heatup of the inlet fluid in the hot channel, which occurs near the location of the stuck CEA. This credit is based on three-dimensional coupled neutronic-thermal-hydraulic calculations performed with the HERMITE/ TORC code (References 9 and 10) for St. Lucie Unit 2 Cycle 1 (Reference 11). It should be noted that only a small fraction of the negative reactivity credit justified for St. Lucie Unit 2 was included in the SLB event analysis for Calvert Cliffs Unit 2 Cycle 5.
The analysis only credited the low steam generator pressure trip. An analysis trip setpoint of 600.0 psia was assumed in the analysis. This represents the Technical Specification setpoint of 685.0 psia and an uncertainty of 85.0 psia. The analysis also assumed that a Steam Generator Isolation Signal (SGIS) is generated when secondary pressure reaches 600.0 psia. This represents the Technical Specification setpoint of 685.0 psia and an uncertainty of 85.0 psia. A Main Steam Isolation Valve (MSIV) closure time of 12 9# seconds (includes valve closure time and signal processing delay time) was conservatively assumed in the analysis.
The analysis conservatively assumed that following reactor trip, the main feedwater flow is ramped down to 8% of full power feedwater flow in 20 seconds and that the main feedwater isolation valves are completely closed in 80 seconds after a low steam generator pressure or a :aain stean isolation signal. These asstaptions ara consistent witn Technical Specification limits.
The analysis assugtions regarding auxiliary feedwater actuation analysis setpoint, the associated time delays, and the AW flow through eachg leg are given below. They were conservatively chosen to initiate AW flow sooner and deliver the maximum AW flow to the ruptured steam generator, i which maximizes the primary cooldown and enhances the potential R-T-P.
An auxiliary feedwater actuation analysis setpoint of 60 9% of steam generator wide range span is assumed in this analysis. This represents a Technical Specification actuation setpoint of 54.4% and includes a 6.5%
, uncertainty. The actuation signal activates a motor driven auxiliary l feedwater pump and a steam driven auxiliary feedwater pump which deliver t auxiliary feedwater to both steam generators. The motor driven pump's I
auxiliary feedwater flow reachet the steam generator 9 5 seconds after low steam generator level signal is initiated. This is the minimum time delay associated with the motor driven pump to accelerate to full speed and other signal processing delay times. The analysis conservatively assumed that the AW flow legs are filled with water and, th s, no time delay associated with AW flow through the piping was included in the analysis.
The flow from the motor driven pump to each steam generator is controlled by a flow control valve installed in the " leg" connecting the ptap to the steam generator. A maximum flow of 217 gpm through each leg is conservatively assumed in the analysis. It represents the Technical Specification limit on AW flow rate of 160 gpm through the flow control valve and an uncertainty of 57 spm.
' Conservative with respect to Technical Specification limit
l l
The steam driven pap's auxiliary feedwater reaches the steam generator l 9.5 seconds after auxiliary feedwater actuation setpoint is reached. This includes a minirmJm time delay of 5.0 seconds required to open steam admission valves to the AFW pump, and 4.5 seconds for the pump to accelerate to speed. The analysis conservatively assumed that the AFW flow legs are filled with water and, thus, no time delay associated with AFW flow through the piping was included in the analysis. De flow from the steam driven pep to each steam generator is also controlled by a flow control valve installed in the flow " leg" connecting the pump to the steam generator. A minimum flow of 217 gpm through each leg is assumed in the analysis. It represents the Technical Specification limit on AFW flow rate of 160 gpm throught the flow control valve and an uncertainty of 57 gpm.
. In case of loss of AC power on turbine trip, there is an additional delay time involved for the motor driven pump. It includes 10 seconds for the diesel generators to start and reach speed following the LOAC and 15 0 i seconds for the motor driven AFW pump to be loaded on line if shutdown i sequencer is initiated. A 30.0 second time delay is assmed for the motor 1
driven AFW pump to be loaded on line if the LOCA sequencer is initiated.
The LOCA sequencer is initiated when SIAS is generated.
The analysis also included isolation of the ruptured steam generator when j the steam generator differential pressure reached the analysis setpoint of 250.0 psid. This represents a Technical Specification setpoint of 130.0 psid and an uncertainty of 120.0 psid. In addition, a 20.0 second time delay was assumed in the analysis to close the AFW isolation (i.e., block) valves. These assumptions are conservative since it delays the isolation of AFW to the ruptured steam generator.
- A safety injection actuation analysis setpoint of 1645.0 psia was assumed
- in the analysis. This represents a Technical Specification setpoint of i
1725.0 psia and an uncertainty of 80.0 psia. The analysis conservatively assumed that on a Safety Injection Actuation Signal (SIAS), only one High Pressure Safety Injection (HPSI) pmp starts. In addition, a maximum time delay of 30 seconds for HPSI pumps to accelerate to full speed was assumed in the analysis. In case of LOAC power, additional time delays are included in the analysis. It includes 10.0 seconds for the diesel generators to start and reach speed following the LOAC and 5.0 seconds for the HPSI pump to be loaded on line regardless of which sequencer (i.e.,
shutdown or LOCA) is initiated.
The HZP inside containment SLB event was initiated at the conditions given in Table 3-2. The moderator cooldown curve is given in Figure 3-2. The cooldown curve corresponds to an end of life MIC. An end of life FTC was also used for the reasons previously discussed in connection with the HFP SLB event. The minimum CEA worth assmed to be available for shutdown at - I the time of reactor trip at the ::ero power level is 5.25 ao. This available scram worth was calculated for the stuck rod which produced the moderator cooldown curve in Figure 3-2. The maximum inverse boron worth of 90 PPM /% ao was conservatively assumed for the safety injection ficw during the HZP SLB event.
He post-trip minimum DNBR for both the HFP and HZP inside containment SLBs were calculated using the MacBeth correlation (Reference 4) with the Lee non-uniform mixing correlation factor (Reference 5).
SLB Outside Containment he HFP and HZP outside containment SLB events were initiated from conditions listed in Tables 3-3 and 3-4, respectively. All assumptions except for the moderator cooldown curve, the initial primary pressure, and the reactor trip credited in the analysis are identical to those for the inside containment SLB event. The reasons for these differences are given below.
The moderator cooldown curve assumed in the analysis is given in Figure 3-3 T cooldewn curve corresponds to an effective MrC of
-2 5x10 ys arison to the ECC Technical Speci limit of ao / F 13eao MFC
-2.2x10 F. An effective MTC of -2.5x10aofication / F was used in the outside containment SLB event analysis to envelope future cycles.
An initial primary pressure of 2154 psia was conservatively assumed in the analysis. This represents the minimum Technical Specification allowed pressure of 2200 psia and an uncertainty of 46.0 psia. Be lower initial pressure results in lower primary pressures at time of minimum DNBR and, thus, a lower minimum DNBR during the event.
For a SLB outside containment, a reactor trip on either Thermal Margin / Low Pressure (TM/LP), low stem generator pressure or high power is credited in ,
the anlaysis. - ,
The assumptions made to maximize the site boundary dose are given in Table 3-5. During the event, two sources of radioactivity contribute to the site boundary dose; the initial activity in the steam generator and the
, activity associated with primary to secondary leakage. The primary activity which leaked through the tubes included the initial activity in the primary allowed by the Technical Specifications and activity released to the coolant due to any additional fuel failure. The analysis conservatively assumed that all fuel pins with minimum DNBR below the design limit of 1.23 (CE-1 correlation) failed. The minimum DNBR during the transient was calculated using the thermal-hydraulic code CETOP (Reference 6). In calculating the site boundry dose, the analysis j conservatively assumed that all activity is released to the atmosphere !
with a decontamination factor of 1.0. l Results ;
i SLB Inside Containment j l
The SLB event with Loss of AC (LOAC) power on turbine trip results in the '
maximum post trip R-T-P and, thus, the minimum post trip transient DNBR.
This occurs because LCAC power causes the Reactor Coolant Pumps (RCPs) to coastdown. The decreasing coolant flow is asssumed to result in no flow mixing at the core inlet plenum. Thus, cold edge temperatures were used to calculate the moderator reactivity insertion. This resulted in more positive reactivity being inserted and produced the maximum post trip
)
R-T-P. In addition, the lower core flows resulted in minimizing the i transient minimum DNBR. !
The results of the parametric analysis in break size indicated that the largest break size resulted in the maximum post trip R-T-P and, thus, the minimum post trip DNBR. This occurs because the largest break size caused the greatest temperature reduction and, thus, inserted the greatest magnitude of positvie reactivity due to moderator reactivity feedback.
This resulted in a higher R-T-P and minimum post trip DNBR. Therefore, the results of the largest inside containment SLB with LOAC on turbine trip are presented herein.
The sequence of events for the 6 305 ft2 SLB with LOAC on turbine trip initiated from HFP conditions is given in Table 3-6. The reactivity insertion as a function of time is presented in Figure 3-4. The NSSS responses during the transient are given in Figures 3-5 through 3-9 The results of the analysis show that the HFP SLB causes the secondary pressure to rapidly cecrease until a reactor trip on low steam generator pressure is initiated at 1.7 seconds.. The CEAs drop into the core at 31 seconds and terminate the power and heat flux increases.
A LOAC power on turbine trip is assumed to occur at 31 seconds. At this time, RCPs start coasting down and the diesel generators start coming on line. At 13 1 seconds, the diesel generators reach full speed and shutdown sequencer is initiated to load emergency systems. At 17.7 seconds the safety injection actuation analysis setpoint is reached and diesel generators switch from shutdown sequencer to LOCA sequencer to load emergency systems. At 22.7 seconds HPSI pump is loaded on line and at 52.7 seconds the HPSI pump reaches full speed.
The Steam Generator Isolation Analysis Setpoint is reached at 1.7 seconds. At 2.6 seconds, the MSIVs begin to close and are completely closed at 14.6 seconds. The blowdown from the intact steam generator is terminated at this time.
An AW isolation signal based on steam generator differential pressure is initiated at 2,9 seconds. At 22 9 seconds, the AW block valve associated with the steam generator with lowest pressure (i.e., ruptured steam generator) is completely closed.
At 13 4 seconds, an AFAS is generated based on low steam generator level.
The steam admission valve to the AW pump is opened at 18.4 seconds and the steam driven AW pump reaches full speed and delivers AW flow to the intact steam generator at 22 9 seconds. The motor driven AW pump 's i loaded on line by diesel generators at 47.7 seconds and is assumed to reach full speed and deliver AW flow to the intact steam generator instantaneously.
The continued blowdown from the ruptured steam generators causes the core reactivity to approach criticality. The ruptured steam generator blows dry at 100.5 seconds, which terminates the cooldown of the RCS. A peak reactivity of -0.044% at 131.4 seconds is obtained. A peak R-T-P of 8.6%,
consisting of 5.2% fission power and 3 4% decay power, is produced at 136.8 seconds. A transient minimum CNBR of 1 31 at 136.8 seconds is obtained.
The negative reactivity inserted due to boron injection via the HPSI pump terminates the approach to criticality and the core becomes more suberitical.
The sequence of events for the 6 305 ft2 SLB with LOAC on turbine trip initiated from HZP conditions is given in Table 3-7 The reactivity insertion as a function of time is presented in Figure 3-10. The NSSS response during the transient are given in Figures 3-11 through 3-15 Be results of the analysis show that the HZP SLB causes the secondary j pressure to rapidly decrease until a reactor trip on low steam generator pressure is initiated at 1.5 seconds. The CEAs drop into the core at 2.9 seconds and terminate the power and heat flux increases.
A LOAC power turbine trip is asstaned to occur at 2 9 seconds. At this time, RCPs start coasting down and the diesel generators start coming on line. At 12.9 seconds, the diesel generators reach full speed and shutdown sequence- is initiated to load emergency systems. At 22.4 seconds, the safety injection actuation analysis setpoint is reached and the diesel generators switch from shutdown sequencer to LOCA sequencer to reload the emergency systems. At 27.4 seconds, the diesel generators load the HPSI pump on line and 30.0 seconds later (i.e., at 57.4 seconds) the HPSI pump reaches full speed.
The Steam Generator Isolation Analysis Setpoint is reached at 15
, seconds. At 2.4 seconds, the MSIVs begin to close and are completely closed at 14.4 seconds. The blowdown from the intact steam generator is terminated at this time.
- At 11.1 seconds, an AFAS is generated based on low steam generator level.
The steam admission valve at the AFW pumo is opened at 16.1 seconds and the steam driven AFW ptanp reaches full speed and delivers AFW flow to both steam generators at 20.5 seconds.
An AFW isolation signal based on steam generator differential pressure is initiated at 3 1 seconds. At 23 1 seconds, the AFW block valve associated with the steam generator with lowest pressure (i.e., ruptured steam generator) is completely closed. AFW flow to the ruptured steam generator is terminated. The motor driven AFW pump is loaded on line by diesel generators at 52.4 seconds and is assumed to reach full speed and deliver AFW flow to the intact steam generator instantaneously.
The continued blowdown from the ruptured steam generators causes the core reactivity to approach criticality. The ruptured steam generator blows dry at 98.5 seconds, which terminates the cooldown of the RCS. A peak reactivity of -0.0754o at 150.0 seconds is obtained. No R-T-P occurs and consequently, critical heat fluxes are not exceeded.
The negative reactivity inserted due to boren injection via the HPSI pump terminates the approach to criticality and the core becomes more suberitical.
- - - , . , - , . ----..,m,._..v-__,,-._,--.-. _ _ - , - - _ . _ . _ - _ _ - . . _ . , _ , . . - . - _ . - - _ . . - _ . . - -
SLB Outside Containment Be outside containment SLB event with LOAC power on turbine trip initiated from HFP resulted in the maximum site boundary dose. This occurs because the LOAC power causes RCPs to coastdown and minimizes the core flow following turbine trip. We lower core flows result in a lower transient DNBR which maximizes the predicted number of fuel pin failures.
The resu}ts of the parametric analysis in break sizes indicated that a SLB resulted in the maximum number of predicted fuel pin 0 33 ft failures. Bis break size is limiting since it delays the time of reactor trip on high power and thereby maximizes the power and heat flux overshoot after trip. The higher peak heat flux resulted in minimizing the DNBR maximizing the fuel failure. Berefore, the results of the and, thuj,SLB 0 33 ft outside containment with LOAC on turbine trip initiated from HFP is presented herein.
Be sequence of events for a 0 33 ft 2 SLB outside containment with LOAC on turbine trip initiated from HFP conditions is given in Table 3-8. The reactivity insertion as a function of time is presented in Figure 3-16.
The NSSS response during the transient are given in Figures 3-17 through 3-21.
Be results of the analysis show that the SLB causes the core power to rapidly increase until a reactor trip on high power is initiated at 14.7 seconds. He CEAs drop into the core at 15.6 seconds and terminate the power and heat flux increases.
A LCAC power on turbine trip is asstimed to occur at 15.6 seconds. At this time, RCPs start coasting down and the diesel generators start coming on line. At 25.6 seconds, the diesel generators reach full speed and shutdown sequencer is initiated to load emergency systems. At 30.6 seconds, the HPSI ptmp is loaded on line and at 40.6 seconds, the motor driven AFW pump is loaded on line.
At 15.7 seconds, an AFAS is generated based on low steam generator level.
l The steam admission valve to the AFW pump is opened at 20.7 seconds, and the steam driven AFW pump reaches full speed and delivers AW flow to both steam generators at 25.2 seconds. The motor driven AW pump is loaded on line by diesel generators at 40.6 seconds and is assumed to reach full speed and deliver AFW flow to both steam generators instantaneously.
The Steam Generator Isolation Analysis Setpoint is reached at 88.5 seconds. At 89.4 seconds, the MSIVs begin to close and are completely closed at 101.4 seconds. De blowdown from the intact steam generator is terminated at this time.
An AW isolation signal based on steam generator differential pressure is initiated at 172.0 seconds. At 192.0 seconds, the AW block valve associated with the steam generator with lowest pressure (i.e., ruptured steam generator) is completely closed. Thus, AW fhw to ruptured steam generator is terminated, while AW flow to intact steam generator continues.
I I
)
. . j The 0 33 ft 2 SLB outside containment shows that 2.0% of fuel pins experience DNB. The resultant site boundary dose is:
Byroid (DEQ I-131) = 67.0 REM Whole Body (DEQ Xe-133) = 0.055 REM Conclusions The results of the Steam Line Break inside containment shows that post-trip minimum DNBR is above the design limit of 13 De SLB outside containment results in a site boundary dose which is within 10CFR100 guide-lines. Therefore, the results of the inside and outside containment SLB events with LOAC power on turbine trip is acceptable for Unit 2 Cycle 5
.r- - - - - - - , - -.
TABLE 3-1 KEY PARAMETERS ASSUMED IN THE INSIDE CONTAIhHENT STEAM LINE BREAK EVENT INITIATED FROM HFP Paraneter Units Cycle 5 Initial Core Power MWt 2754.0 O
Initial Core Inlet F 550.0 Temperature Initial RCS Pressure psia 2300.0 Initial Stem Generator psia 860.0 Pressure Low Ste m Generator psia 600.0 Pressure Analysis Trip Setpoint Auxiliary Feedwater % Wide Range 60 9 Actuation Analysis Stem Generator Setpoint Level Indication Stem Generator psid 250.0 '
Differential Pressure
. Analysis Setpoint .
Safety Injection psia 1645 0 Actuation Signal Minimum CEA Worth 5 ap -6.89 Available at Trip
, Doppler Multiplier 1.15 Moderator Cooldown Curve % vs. See Figure density 3-1 Inverse Boron Worth PPM /% ao 95 0 0 -2.2
( Erfeetive MTC x10 8 ao/ F 8 Fraction (including .0060
- uncertainty) l l
TABLE 3-2 KEY PARAMETERS ASSUMED IN THE INSIDE CONTAINMENT STEAM LINE BREAK EVENT INITIATED FROM HZP Parameter Units Cycle 5 Initial Core Power MWt 1.0 Initial Core Inlet OF 532.0 Temperature Initial RCS Pressure psia 2300.0 Initial Steam Generator psia 900.0 Pressure Low Steam Generator psia 600.0 Pressure Analysis Trip Setpoint Auxiliary Feedwater 5 Wide Range 60 9 Actuation Analysis . Stean Generator Setpoint Level Indication Steam Generator psid 250.0 Differential Pressure Analysis Setpoint ,
Safety Injection psia 1645.0 Actuation Signal Minimum CEA Worth Sao -5 2 Available at Trip Doppler Multiplier 1.15 Moderator Cooldown Curve % vs. See Figure density 3-2 Inverse Bo on Worth PPM /%ao 90.0 Effective MIC x10d ao / F -2.2 8 Fraction (including .0060 uncertainty) i t .-
.= .
TABLE 3-3 KEY PARAMETERS ASSUMED IN THE OUTSIDE COEAINMENT STEAM LINE BREAK EVENT INITIATED FROM HFP Parameter Units Cycle 5 Initial Core Power NWt 2754.0 Initial Core Inlet OF 550.0 Temperature Initial RCS Pressure psia 2154.0 Initial Steam Generator psia 860.0 Pressure ,
low Steam Generator psia 600.0 Pressure Analysis Trip Setpoint Auxiliary Feedwater % Wide Range 60 9 Actuation Analysis Steam Generator Setpoint Level Indication Steam Generator psid 250.0 Differential Pressure Analysis Setpoint -
Safety Injection ' psia 1645.0 Actuation Signal Minimum CEA Worth b -6.89 '
Available at Trip Doppler Multiplier 1.15 Moderator Cooldewn Curve % vs. See Figure density 3-3 Inverse Baron Worth PPM /S ao 95.0 Effective EC x10 Map / F -2.5 8 Fraction (including .0060 uncertainty) i
)
.s TABLE 3-4 >
KEY PARAMETERS ASSUMED IN THE GUTSIDE CONTAINMENT .
STEAM LINE BREAK EVENT INITIATED FRCM HZP s , .
Parameter Units ,. Cycle 5 ,
^
v x 3
Initial Core Power MWt s ,
+
=1.0 '
' 's Initial Core Inlet OF 532.0' Temperature <
Initial RCS Pressure psia 2154,0 Initial Steam Generator psia '
900.0 Pressure
)
t .
Low Steam Generator psia ' 600.0 (' '
Pressure Analysis Trip Setpoint ,
Auxiliary Feedwater ,% Nide Range 60 9 Actuation Analysis iSteam Generator -
Setpoint Level Indication ,
Steam Generator psid 250.0 Differential Prassure ,
, Analysis Setpoint Safety Injection Actuation Signal p-ia
\i 1645 0 i
Minimum CEA Worth %Ao
~52 Available at Trip f s
Doppler Multiplier 1.15 s
Moderator Cooldown Curve ; vs. See Figure density 3-2' Inverse Baron Worth PPM /Mo 90.0 .
Effective MTC x10 Mao /CF -2.5
, 8 Fraction (including .0060 l uncertainty) ,
w L
I t.
< 1 l
TABLE 3-5 ASSUMPTIONS FOR THE RADICLOGICAL EVALUATION FOR THE STEAM LINE BREAK EVENT Parameter Units Value Reactor Coolant System Maximum uCi/gm 1.0 Allowable Concentration (DEQ I-131)'
uCi/gm 0.1 SteenGeneratorMaximumA}lowable Concentration (DEQ I-131)
Partition Factor. Assumed for 1.0 All Doses Atmosoberic Dispersion Coefficient 2 sec/M3 1,goxio-4 Breathing Rate M3 /sec 3 47x10-4 Dosi; Conversion Factor (I-131) REM /Ci 1.48x10 6 I Tech Spec limits 20-2 hour accident condition 1
1 i
e a
4
TABLE 3-6 SECUENCE OF EVENTS FOR INSIDE CONTAINMENT STEAM LINE BREAK EVENT WITH LOSS OF AC POWER ON TURBINE TRIP INITIATED FROM HFP Time (sec) Event Setpoint or Value 0.0 Steam Line Break Occurs 6 305 ft 2 17 Low Steam Generator Pressure 600.0 psia Analysis Trip Setpoint is Reached; Steam Generator Isolation Analysis Setpoint is Reached 2.6 Trip Breakers Open; Main Steam Isolation Valves Begin to Close; Main Feedwater Isolation Valves Begin to Close 2.9 Steam Generator Differential aP = 250.0 psid Pressure Analysis Setpoint is Reached .
31 CEAs Enter Core; loss of AC Power on Turbine Trip; RCPs Coastdown Begins; Diesel Generator Start Coming On Line; Main Feedwater Rampdown Begins 13 1 Diesel Generators Reach Rated Speed Following LOAC Power; Shutdosn Sequencer Initiated 13 4 Auxiliary Feedwater Actuation 60 95
Analysis Setpoint is Reached 14.6 Main Steam Isolation Valves -
Completely Closed 17.7 Safety Injection Actuation 1645.0 psia Analysis Setpoint is Reached; LOCA Sequencer Initiated 18.4 Steam Admission Valves to Steam Driven AEW Ptanp Completely Open 19 7 Pressurizer Empties -
- % of distance between steam generator wide range upper and lower level instrument taps.
TABLE 3-6 (continued)
Time (sec) Event Setpoint or Value 22.7 Power Provided to High Pressure Safety Injection Pumps 22 9 AFW Block Valve Completely Closed; 217 0 gpm Steam Driven AFW Pump at Full Speed and Delivers AFW Flow to Intact Steam Generator 23 1 Main Feedwater Rampdown 8% of Full Power Completed Feedwater Flow 47 7 Power Provided to Motor Driven A W Pump 47 7 Motor Driven AFW Ptanp at Full 217.0 gpm Speed and Delivers A W Flow to Intact .' team Generator 52.7 High Pressure Safety Injection -
Pump o Full Speed 82.6 Main Feedwater Isolation -
Valve Completely Closed .
100 5 Affected Steam Generator -
Blows Dry 131.4 Peak Reactivity -0.044 W 136.8 Peak Return to Power 8.6% of 2700 MWt 4
i
_ _ . . - - _ . . ~
.= .
TABLE 3-7 SEQUENCE OF EVENTS FOR INSIDE CONTAINMENT STEAM LINE BREAK EVENT WITH LOSS OF AC POWER ON TURBINE TRIP INITIATED FROM HZP Time (sec) Event Setpoint er Value 0.0 Steam Line Break Occurs 6 305 ft2 1.5 Low Steam Generator Pressure 600.0 psia Analysis Trip Setpoint is Reached; Steam Generator Isolation Analysis Setpoint is Reached 2.4 Trip Breakers Open; Main -
Steam Isolation Valves Begin to Close; Main Feedwater Isolation Valves Begin to Close 29 CEAs Enter Core; Loss of AC Power on Turbine Trip; RCPs Coastdown Begins; Diesel Generators Start Coraing On Line 31 Steam Generator Differential AP = 250.0 psid Pressure Analysis Setpoint is Reached 11.1 Auxiliary Feedwater Actuation 60 9%"
, Analysis Setpoint is Reached 12.9 Diesel Generators Reach Rated Speed Following LOAC Power; Shutdown Sequ(.ncer Initiated 14.4 Main Steam Isolation Valves -
Completely Closed i
16.1 Stean Admission Valves to Steam -
Driven AFW Pump Completely Open 20.6 Stean Driven Auxiliary Feedwater 217.0 gpm/S.G.
l Pump at Full Speed and Delivers AFW Flow to Both Steam Generators
- % of distance between steam generator wide range upper and lower level instrument taps.
TABLE 3-7 (continued)
Time (sec) Event Setpoint or Value 22.4 Safety Injection Actuation 1645 0 psia Analysis Setpoint is Reached LOCA Sequencer Initiated 23 1 AFW Block Valve Completely Closed; AFW Flow to Ruptured Steam Generator is Terminated -
27.4 Power Provided to HPSI Pump 28 9 Pressurizer Empties 52.4 Power Provided to Motor Driven 217.0 gpm AFW Pump; Motor Driven AFW Pump Reaches Full Speed and Delivers AFW Flow to Intact Steam Generator 57 4 High Pressure Safety Injection -
Pump Reaches Full Speea 98.5 Affected Steam Generator Blows Dry i
150.0 Peak Reactivity -0.075%ao l
l l
TABLE 3-8 SECUENCE OF EVENTS FOR OUTSIDE CONTAINMENT STEAM LINE BREAK EVENT WITH LOSS OF AC POWER ON TURBINE TRIP INITIATED FROM HFP .c Time (sec) Event Setpoint or Value 0.0 Steam Line Break Occurs 0 33 ft 2 14.7 High Power Analysis Trip 112% of 2700 MWt Setpoint is Reached 15 1 Trip Breakers Open -
15.6 CEAs Enter Core; Loss of AC -
Power on Turbine Trip; RCPs Coastdown Begins; Main Feedwater Rampdown Begins; Diesel Generators Start Coming On Line 15 7 Peak Core Average Power 118.1% of 2700 Mht Peak Core Averge Heat Flux 113 4% of 2700 MWt 15 7 Auxiliary Feedwater Actuation 60 9%H Analysis Setpoint is Reached 20.7 Steam Admission Valves to Steam .
Driven AFW Pump Completely Open 25.2 Steam Driven AFW Pump Reaches 217.0 gpm/S.G.
Full Speed and Delivers AFW to Both Steam Generators 25.6 Diesel Generators Reach Rated --
Speed Following LOAC Power; Shutdown Sequencer Initiated 30.6 Power Provided to High Pressure -
Safety Injection Pump i 35.6 Main Feedwater Rampdown 8% of full power Completed feedwater flow 40.6 Power Provided to Motor 217.0 gpm/S.G.
Driven AFV Pump; Motor Driven AFW Ptanp at Full Speed and Delivers AFW Flow to Both Steam Generators 88 5 Steam Generator Isolation 600.0 psia Analysis Setpoint is Reached
- % of distance between steam generator wide range upper and lower level instru=ent taps.
e TABLE 3-8 (continued)
Time (sec),
Event Setpoint or Value 89 0 Safety Injection Actuation 1645.0 psia Analysis Setpoint is Reached 89 4 Main Steam Isolation Valves -
Begin to Close; Main Feedwater Isolation Valves Begin to Close 101.4 Main Steam Isolation Valves -
Completely Closed 119 0 High Pressure Safety Injection -
Pump Reaches Full Speed 122 5 Pressurizer Empties -
169.4 Main Feedwater Isolation -
Completely Closed 172.0 Steam Generator Differential aP = 250.0 psid Pressure Analysis Setpoint is Reached 192.0 AFW Block Valve Completely -
Closed; AFV Flow to Ruptured .
. Steam Generators is
- Terminated
8 i , , ,
7 - 2 LOOP-FULL POWER -
INSIDE CONTAINMENT 6
- c. -
<3
.4 5 -
$4 - -
a b 3 5
x -
e 2 -
E E _ _
g 1 1 22 0 - -
-1 - -
-2 40 45 50 55 60 .65 MODERATOR DENSITY, LEM/FT 3 aAssNI$$$cco. STEAM LINE BREAK EVENT FIGURE
, calvert cliffs MODERATOR REACTIVITY VS MODERATOR DENSITY 3-1 lNuclearPowerPlant
7 i i , ,
6 2 LOOP-N0 LOAD -
INSIDE CONTAINMENT 5 -
Q.
&4 ~
N3 t
t3 2 -
5 x .
5 1
g -
g 0 -
E
-1 -
-2 -
l
-3 ' ' ' '
40 45 50 55 60' 65 MODERATOR DENSITY, LBM/FT3
.l casaIN$0!!co. -
STEAM LINE BREAK EVENT FIGURE calver: c14rrs MODERATOR ^ REACTIVITY VS MODERATOR DENSITY 3-2 Nuclear Power Plant
8 i i. . ,
2 LOOP-FULL POWER OUTSIDE CONTAINMENT 6
- J
- o. ; i N _
-1 N
E 4 p
4 -
g -
m E - J 2
lli E - -
E 0 .
-2 40 45 50 55 '60 55
- MODER6. TOR DENSITY, LEM/FT 3
.AS &BALMOM STEAM LINE BREAK EVENT e l':UR E ELECTR.c v0.
caiver: cliffs OUTSIDE CONTAINMENT 3_z
ne icar reve- Plant MODERATOR REACTIt.TY VS MODERA72R DENS:TY
,r ,
r.- --- m.. - , , - - - - - - - - - , - - , - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
l l
6 i i i i 2 LOOP-FULL POWER 1
4 _
MODERATOR D0PPLEP, I
<w q
0 h 3-D FEEDBACK
~
vi
\
>2 y
N, BORON 1
u i
1 -4 -
TOTAL _
l CEA
-8 0 100 200 300 400 500 600 TIME, SECON.0S l
BALTIMORE -
GAS & ELECTRIC CO. STEAM LINE BREAK EVENT FIGURE calvert cliffs REACTIVITIES VS TIME 3-4 Nuclear Power Plant -
1
I 9
i 120 i i i i i 100 2 LOOR-FULL POWER 8 80 -
n s
= 60 -
= .
2 40 -
is! .
8 20 '-
X.
' i - .
0 i
, 0 100 200 300 400 500 600 TIME, SECONDS BALTIMORE '
GAS & ELECTRIC CO. STEAM LINE BREAK EVENT FIGURE calvert o fffs CORE POWER VS TIME 3-5 Nuclear Power Plant
e i .
1 I
120 I I I l l 100 -
2 LOOP-FULL POWER 8
~
N 80 --
8 g
=,
60 --
1 cd
+ -
6
= 40 is! -
S -
20 x ' ' ' '
0 0 100 200 300 400 500 600 TIME, SECONDS BALTIMORE
' GAS & ELECTRIC CO. STEAM LINE BREAK EVENT' FIGURE Nuc r o r ant C RE HEAT FLUX VS TIME 3-6
e 650 i i i i i 2 LOOP-FULL POWER 600 _
.u_
- 1 5 550 -
h 5
m 500 .
M g -
TOUT a
IAVG
$ 450 - _
T g IN t3 5
400 - _
i I I i l 350 I i 0 100 200 300 400 500 600 l
TIME, SECONDS BALTIP. ORE GAS & ELECTRIC CO. STEAM LINE BREAK EVENT FIGURE 3j"j"/jjjill,,, / REACTOR COOLANT SYSTEM TEMPERATURES VS TIME 3-7
y 2500 i i i i i G
o.
- g 2 LOOP-FULL POWER h2000 E
m.
E h1500 e
5 -
8 1000 - -
x I I I ' '
500 0 100 200 300 400 500 600 TIME, SECONDS GAS & EC CO. STEAM LINE BREAK EVENT FIGURE calvert citffs REACTOR COOLANT SYSTEM PRESSURE VS TIME 3-8 Nuclear Power Plant
900 i i i i i 800 2 LOOP-FULL POWER 700 .
5 co 4 600 -
UNAFFECTED E ~
5? STEAM GENERATOR ya_ 500 -
is E 400 '-
W
, y
- 5 300 200 -
100 -
AFFECTED STEAM GENERATOR 0 100 2b0 300 4b0 500 600 TIME, SECONDS
. BALTIMORE GAS & ELECTRIC CO. STEAM LINE BREAK EVENT FIGURE nuc$Ia$owebIan: STEAM GENERATOR PRESSURE VS TIME 3-9
5.0 i i i i i i i i 2 LOOP-N0 LOAD 3.9 - -
MODERATOR 2.8 - -
1.7 DOPPLER BORON g ~ 0.~ 6 - -
w 0 -
f -0.5 - -
p 3-D FEEDBAC E
g -1.6 -
TOTAL
~
6 a:
! -2.7 - -
-3.8 - -
-4.9 1
-6.0 0 20 40 60 80 100 120 140 160 180 TIME, SECONDS 4
BALTIMORE -
GAS & ELECTRIC CO. STEAM LINE BREAK EVENT FIGURE nuc$ErloSeNIant REACTIVITIES VS TIME 3-10
120 i ,i , , ,
100 -
2 LOOP-N0 LOAD T
z ,
8 80 I
N '
- u. .
o I w 60
. i c:
W '
2 40 -
u 8
20 -
0 . ,
0 30 60 90 120 150 180 TIME, SECONDS l BALTIMORE i GAS & ELECTRIC ca. STEAM LINE 3REAX EVENT FIGJRE calver: c:iffs CORE POWER VS TIM: 3-11 -
Nuclear Power Plant l !
we e , - - - -
- s, - - - - - - , - .
I 120 , , , , . ;
i t
i 100 -
g 2 LOOP-N0 LOAD g.
l I
S 80 E
w -
l:
f 60 :
d *
@ *r i.
E S !
i
- 20 -
0^ ' '
0 30 60 90 120 150 180 TIME, SECONDS i
GAS & $EC R CO. STEAM LINE BREAK EVENT FIGURE catvert citffs l
CORE HEAT FLUX VS TIME 3-12 Nuclear Power Plant ;
. _ . . _ --_,,r_m
- ~ . _ .
550 i , , , , , .
2lE w -
g 500 -
2 LOOP-N0 LOAD z
y 450 TOUT TAVG B;
400 8 ' '
% 350 180 0 20 40 60 80 100 120 140 160 TIME, SECONDS
'I BALTIMORE GAS & ELECTRIC CO. STEAM LINE BREAK EVENT ~ FIGURE Nuc a REACTOR COOLANT SYSTEM TEMPERATURES VS TIME 3-13 owe ant
l 5 l
!C i i i g 2500 , i i i i E
W o-2000 2 LOOP-N0 LOAD 5 -
E m
1500 e -
5 1000 -
8 v
5 500 .
140 160 180 ,
w 0 . 20 40 60 80 . 100 120
- TIME, SECONDS STEAM LINE BREAK EVENT FIGURE GAS & E EC CO.
calvert cliffs - REACTOR COOLANT SYSTEM PRESSURE VS TIME 3-14 Nuclear Power Plant l
l
i 900 , i i i i i i i 800 2 LOOP-h0 LOAD
< 700 ' l G
o_
g 600 - - -
5 m
o.
500 UNAFFECTED STEAM GENERATOR _
5
$ 400 - -
u g 300 - -
W w '
i 200 - -
100 - ,
AFFECTED STEAM GENERATOR 0
0 20 40 60 80 100 120 140 160 180 TIME, SECONDS l
GAS & CO. STEAM LINE BREAK EVENT FIGURE calvert cliffs STEAM GENERATOR PRESSURE VS TIME 3-15 Nuclear Power Plant
6 i i i i I i MODERATOR 4 -
4 D0PPLER 1
2 -
q 3-D FEEDBACK
<3 N BOR t-E D -
2 -
$ TOTAL 4 -
, CEA l /
6 j 8
0 100 200 300 400 500 600 TIME, SECONDS BALTIMORE STEAM LINE BREAK EVENT uAs a ELEcmc co. OUTSIDE CONTAINMENT FIGURE Calvert Cliffs 3-16 Nuclear Power Plant REACTIVITIES VS TIME n -.g. , , - - - - _ . , , , ,,,.,-.g -, . . , .., ,, ,_, n ,.-,_,-,.n... ,.e. . , , _ _ , - _ . _ _ - _
.= . l 120 , i i i i i i l
i V
100 N 80 8
es
" 60 e
f 40 20
(
w 0
O 100 200 300 400 500 600 TIME, SECONDS l
0 BALTIMORE STEAM LINE BREAK EVENT-
'AS & ELECTRIC CO.
OUTSIDE CONTAINMENT Calvert Cli,ffs 3-p Nuclear Power Plant CORE POWER VS TIME-
120 i i i i i i 100 -
l N
8.
80 '
R b
D4 -
- ,2 60 3
u.
g 40 S. .
20 0
0 100 200 300 400 500 600 TIME, SECONDS BALTIMORE STEAM LINE BREAK EVENT GAS & ELECTRIC CO. FIGURE Calvert Cliffs- OUTSIDE CONTAINMENT -
fluclear Power Plant CORE HEAT FLUX VS TIME 3-36
I l
650 i i i i d 600 -
E 3
w b
i 550 -j.
5 s a '
M -
W 500
~
3 T0llT 8
v T yg 450 6
= s ._
l ~
I ' ' I I 400 O 100 200 300 400 500 600 TIME, SECONDS STEAM LINE BREAK EVENT GAS & E E R CO. FIGURE calvert cliffs OUTSIDE CONTAINMENT
' 3-19 Nuclear Power Plant REACTOR COOLANT SYSTEM TEMPERATURES VS TIME I
+ - -. , --- .-- . , - , , - - - , , - . , - .- -
3 2500 i i i i i i 10 ul g
22 2000 u
o 5
m -
M 1500 W
5 8 -
g 1000 t3 d5 i
500 O 100 200 300 400 500 600 TIME, SECONDS STEAf1 LINE BREAK EVENT FIGuas GAS & E CO.
calvert cliffs OUTSIDE CONTAINMENT 3-20 Nuclear Power Plant' REACTOR COOLANT SYSTEM PRESSURE VS TIME
900 i i j , ,, ,
R 1
\
800 N.'\ .
'\ UNAFFECTED
\ STEAM 700 GENERATOR
'\
\'
5 m s 600 -
u.7 s
N E .
N N
N 500 -
8 E
w
[ 400 -
6 ;
M 300 AFFECTED 'N GENERATOR STEAM
\.N' 100 0 100 200 300 400 500 600 TIME, SECONDS BALTIMORE STEN 1 LINE BREAK EVENT FIGURE GAS & ELECTRIC CO. OUTSIDE CONTAlNMENT Calvert Cliffs -
3-21 Nuclear Power Plant STEAM GENERATOR PRESSURE VS TIME
A t.
' 4.0' Technical Specifications 0 The Technical Specification changes and/or additions which are required to validate the safety analysis performed for the safety grade AFAS are presented in this section. The changes and/or additions for the safety grade AFAS are denoted by an asterisk (*).
t s
\
,e, s
+,
l l
l
---. __