ML20151T656
| ML20151T656 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 09/04/1998 |
| From: | SOUTHERN CALIFORNIA EDISON CO. |
| To: | |
| Shared Package | |
| ML20151T642 | List: |
| References | |
| NUDOCS 9809100099 | |
| Download: ML20151T656 (112) | |
Text
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PCN 493 l
I 1
Attachment A Existing Technical Specifications and Bases SONGS Unit 2 l
i 9809100099 98o904 m-yDR ADOCK o m g PDR
Pressurizer Safety Valves 3.4.10 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.10 Pressurizer Safety Valves LC0 3.4.10 Two pressurizer safety valves shall be OPERABLE with a lif t setting of 2500 psia i 1%.
APPLICABILITY: MODES 1, 2, and 3.
NOTE--------------------------_-
The lift settings are not required to be within LC0 limits during MODE 3 for the purpose of setting the pressurizer safety valves under ambient (hot) conditions. This exception is allowed for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> following entry into MODE 3 provided a preliminary cold setting was made prior to heatup.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One pressurizer safety A.1 Restore valve to 15 minutes valve inoperable. OPERABLE status.
B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND OR B.2 Be ii, MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Two pressurizer safety valves inoperable.
SAN ON0FRE--UNIT 2 3.4-28 Amendment No. 127
I Pressurizer Safety Valves 3.4.10 l l
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify each pressurizer safety valve is In accordance OPERABLE in accordance with inservice with the testing program. Following testing, lift Inservice settings shall be within i 1%. Testing Program 1
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SAN ON0FRE--UNIT 2 3.4-29 Amendment No. 127
1 Pressurizer Safety Valves B 3.4.10 B 3.4 REACTOR C0OLANT SYSTEM (RCS)
B 3.4.10 Pressurizer Safety Valves BASES BACKGROUND The purpose of the two spring loaded pressurizer safety valves is to provide RCS overpressure protection. Operating in conjunction with the Reactor Protection System, two valves are used to ensure that the Safety Limit (SL) of 2750 psia is not exceeded for analyzed transients during operation in MODES 1, 2 and 3. During MODE 4, MODE 5, and MODE 6 with the reactor pressure vessel head on, overpressure protection is provided by operating procedures and LC0 3.4.12. " Low Temperature Overpressure Protection (LT0P) System." For these conditions, American Society of Mechanical Engineers (ASME) requirements are satisfied with one safety valve.
The self actuated pressurizer safety valves are designed in accordance with the requirements set forth in the ASME, Boiler and Pressure Vessel Code,Section III (Ref.1). The required lift pressure is 2500 psia i 1%. The safety valves discharge steam from the pressurizer to a quench tank located in the containment (Ref. 2). The discharge flow is indicated by an increase in temperature downstream of the safety valves and by an increase in the quench tank temperature and level.
The upper and lower pressure limits are based on the
- 1%-tolerance requirement (Ref.1) for lif ting pressures above 1000 psig. The lift setting is for the ambient conditions associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between hot and cold settings be established.
The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated accidents. OPERABILITY of the safety valves ensures that I the RCS pressure will be limited to 110% of design pressure. i The consequences of exceeding the ASME pressure limit ,
(Ref.1) could include damage to RCS components, increased l leakage, or a requirement to perform additional stress I analyses prior to resumption of reactor operation. )
(continued) I SAN ONOFRE--UNIT 2 B 3.4-51 Amendment No. 127 l
Pressurizer Safety Valves B 3.4.10
(
BASES (continued)
APPLICABLE- All accident analyses in the UFSAR that require safety valve SAFETY ANALYSES actuation assume operation of both pressurizer safety valves to limit increasing reactor coolant pressure (Ref. 3). The overpressure protection analysis is also based on operation of both safety valves and assumes that the valves open at the high range of the setting (2500-psia system design pressure plus 1%). These valves must accommodate pressurizer insurges that could occur during a startup, rod j withdrawal, ejected rod, loss of main feedwater, or main i feedwater line break accident. The combined relief capacity -
of these valves is sufficient to limit the System pressure to within its Safety Limit of 2750 psia following a complete i loss of turbine generator load while operating at RATED THERMAL POWER and assuming no reactor trip until the first Reactor Protective System trip setpoint (Pressurizer Pressure-High) is reached (i.e., no credit is taken for a direct reactor trip on the loss of turbine) and also assuming no operation of the steam dump valves. The startup accident establishes the minimum safety valve capacity. The startup accident is assumed to occur at < 15% power. Single failure of a safety valve is neither assumed in the accident analysis nor required to be addressed by the ASME Code.
Compliance with this specification is required to ensure that the accident analysis and design basis calculations remain valid.
The pressurizer safety valves satisfy Criterion 3 of the NRC Policy Statement.
LC0- The two pressurizer safety valves are set to open at the RCS design pressure (2500 psia) and within the ASME specified tolerance to avoid exceeding the maximum RCS design pressure SL, to maintain accident analysis assumptions, and to comply with ASME Code requirements. The upper and lower pressure tolerance limits are based on the i 1% tolerance requirements (Ref.1) for lifting pressures above 1000 psig.
The limit protected by this specification is the reactor coolant pressure boundary (RCPB) SL of 110% of design pressure. Inoperability of one or both valves could result in exceeding the SL if a transient were to occur. The consequences of exceeding the ASME pressure limit could include damage to one or more RCS components, increased leakage, or additional stress analysis being required prior to resumption of reactor operation.
(continued)
SAN ON0FRE--UNIT.2 B 3.4-52 Amendment No. 127
l
' i Prescurizer Safety Valves l
, B 3.4.10 1 BASES 4 l
ACTIONS B.1 and B.2 (continued)
The 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed is reasonable, based on operating
, experience, to reach MODE 3 from full power without
! challenging plant systems. Similarly, the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed i
' is reasonable, based on operating experience, to reach
' MODE 4 without. challenging plant systems. The' change from MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power i'
and pressure), lowers the potentiai for large pressurizer insurges, and thereby removes the need for overpressure protection by two pressurizer safety valves.
4 SURVEILLANCE SR 3.4.10.1 REQUIREMENTS ,
. SRs are specified in the inservice testing program.
Pressurizer safety valves are to be tested one at a time and
! in accordance with the requirements of Section XI of the
- ASME Code (Ref. 1), which provides the activities and the Frequency necessary to satisfy the SRs. No additional requirements are specified.
The pressurizer safety valve setpoint is i 1% for OPERABILITY.
1
- 4
- REFERENCES 1. ASME, Boiler and Pressure Vessel Code,Section III,
- Section XI. -
1 2. UFSAR, Section 5.4
- 3. UFSAR, Section 15.
j-SAN ON0FRE--UNIT 2 B 3.4-54 Amendment No. 127
]
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PCN 493 I
1 Attachment B Existing Technical Specifications and Bases SONGS Unit 3 i
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Pressurizer Safety Valves 3.4.10 3.4 REACTOR C0OLANT SYSTEM'(RCS) 3.4.10 Pressurizer Safety Valves LC0 3.4.10 Two pressurizer safety valves shall be OPERABLE with a lift setting of 2500 psia i 1%.
APPLICABILITY: MODES 1, 2, and 3.
NOTE----------------------------
The lift settings are not required to be within LC0 limits during MODE 3 for the purpose of setting the pressurizer safety valves under ambient (hot) conditions. This exception is allowed for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> following entry into MODE 3 provided a preliminary cold setting was made prior to heatup.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME i
A. One pressurizer safety A.1- Restore valve to 15 minutes valve inoperable. OPERABLE status.
B. Required Action and- B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. .A_tLD OR B.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Two pressurizer safety valves inoperable.
SAN ON0FRE--UNIT 3 3.4-28 Amendment No. 116
Pressurizer Safety Valves 3.4.10 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify each pressurizer safety valve is In accordance OPERABLE in accordance with inservice with the testing program. Following testing, lift Inservice settings shall be within i 1%. Testing Program
)
i SAN ON0FRE--UNIT 3 3.4-29 Amendment No. 116
- ._ --. . . _ . .. -- ~ . . _ - . - . - . .
Pressurizer Safety Valves B 3.4.10 B 3.4 REACTORCOOLANTSYSTEM(RCS)
B 3.4.10 Pressurizer Safety Valves BASES BACKGROUND The purpose of the two spring loaded pressurizer safety valves is to provide RCS overpressure protection. Operating in conjunction with the Reactor Protection System, two valves are used to ensure'that the Safety Limit (SL) of 2750 psia is not exceeded for-analyzed transients during operation in MODES 1, 2 and 3. During MODE 4, MODE 5, and MODE 6 with the reactor pressure vessel head on, overpressure protection is provided by operating procedures and LC0 3.4.12, " Low Temperature Overpressure Protection (LTOP) System." For these conditions, American Society of Mechanical Engineers (ASME) requirements are satisfied with one safety valve.
The self actuated pressurizer safety valves are designed in accordance with the requirements set forth in the ASME, Boiler and Pressure Vessel Code,Section III (Ref.1). The required lift pressure is 2500 psia i 1%. The safety valves discharge steam from the pressurizer to a quench tank located in the containment (Ref. 2). The discharge flow is indicated by an increase in temperature downstream of the safety valves and by an increase in the quench tank temperature and level.
The upper and lower pressure limits are bcsed on the i 1%-tolerance requirement (Ref.1) for lifting pressures above 1000 psig. The lift setting is for the ambient conditions associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between hot and cold settings be established.
The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated
' accidents. OPERABILITY of the safety valves ensures that the RCS pressure will be limited to 110% of design pressure.
The consequences of exceeding the ASME pressure limit (Ref.1) could include damage to RCS components, increased leakage, or a requirement to perform additional stress analyses prior to resumption of reactor operation.
(continued)
SAN ON0FRE--UNIT 3 B 3.4-51 Amendment No. 116
Pressurizer Safety Valves B 3.4.10 BASES (continued)
APPLICABLE All accident analyses in the UFSAR that require safety valve SAFETY ANALYSES actuation assume operation of both pressurizer safety valves j to limit increasing reactor coolant pressure (Ref. 3). The '
overpressure protection analysis is also based on operation of both safety valves and assumes that the valves open at the high range of the setting (2500-psia system design pressure plus 1%). These valves must accommodate pressurizer insurges that could occur during a startup, rod withdrawal, ejected rod, loss of main feedwater, or main feedwater line break accident. The combined relief capacity
, of these valves is sufficient to limit the System pressure to within its Safety Limit of 2750 psia following a complete loss of turbine generator load while operating at RATED THERMAL POWER and assuming no reactor trip until the first )
Reactor Protective System trip setpoint (Pressurizer Pressure-High) is reached (i.e., no credit is taken for a 1 direct reactor trip on the loss of turbine) and also assuming no operation of the steam dump valves. The startup !
accident establishes the minimum safety valve capacity. The startup accident is assumed to occur at < 15% power. Single '
failure of a safety valve is neither assumed in the accident :
analysis nor required to be addressed by the ASME Code.
Compliance with this specification is required to ensure that the accident analysis and design basis calculations remain valid.
The pressurizer safety valves satisfy Criterion 3 of the NRC Policy Statement.
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LCO The two pressurizer safety valves are set to open at the RCS i design pressure (2500 psia) and within the ASME specified tolerance to avoid exceeding the maximum RCS design pressure SL, to maintain accident analysis assumptions, and to comply J with ASME Code requirements. The upper and lower pressure '
tolerance limits are based on the
- 1% tolerance requirements (Ref.1) for lifting pressures above 1000 psig.
The limit protected by this specification is the reactor coolant pressure boundary (RCPB) SL of 110% of design pressure. Inoperability of one or both valves could result in exceeding the SL if a transient were to occur. The consequences of exceeding the ASME pressure limit could include damage to one or more RCS components, increased s
leakage, or additional stress analysis being required prior to resumption of reactor operation.
2 (continued)
SAN ON0FRE--UNIT 3 B 3.4-52 Amendment No. 116
Pressurizer Safety Valves B 3.4.10 BASES ACTIONS B.1 and B.2 (continued) l l
The 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed is reasonable, based on operating l experience, to reach MODE 3 from full power without l challenging plant systems. Similarly, the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed [
is reasonable, based on operating experience, to reach MODE 4 without challenging plant systems. The change from ;
MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power !
and pressure), lowers the potential for large pressurizer insurges, and thereby removes the need for overpressure protection by two pressurizer safety valves.
SURVEILLANCE SR 3.4.10.1 REQUIREMENTS SRs are specified in the inservice testing program.
Pressurizer safety valves are to be tested one at a time and )
in accordance with the requirements of Section XI of the ASME Code (Ref. 1), which provides the activities and the Frequency necessary to satisfy the SRs. No additional requirements are specified.
The pressurizer safety valve setpoint is i 1% for OPERABILITY.
REFERENCES 1. ASME, Boiler and Pressure Vessel Code,Section III, Section XI.
- 2. UFSAR, Section 5.4
- 3. UFSAR, Section 15.
SAN ONOFRE--UNIT 3 B 3.4-54 Amendment No. 116
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Attachment C Proposed Technical Specification and Bases (Bases changes are for Information Only)
(Redline and Strikeout) i SONGS Unit 2 l
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Pressurizer Safety Valves 3.4.10 3.4 REACTORCOOLANTSYSTEM(RCS) 3.4.10 Pressurizer Safety Valves LC0 3.4.10 .Two pressurizer safety valves shall,.b.e OPERABLE with a l i ii.
as-found:iliftsettingsof2500 psia',7+3%lo@24iI?..
APPLICABILITY: MODES 1, 2, and 3.
NOTE----------------------------
The lift settings are not required to be within LC0 limits during MODE 3 for the purpose of setting the pressurizer safety valves under ambient (hot) conditions. This exception is allowed for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> following entry into MODE 3 provided a preliminary cold setting was made prior to heatup.
EachMesslurizefiafety'is19eMas{ad. as 'foundj:t'oleranceEof
+3% or:N2%.v -:FollowingT. testing in: ac.cordanceJwith _. , . ..
TS! 5; 5. 2210 k pres su ri zer L s a fe ty;; va l ves is halli. beis etiwi thi n 11Rofit h.eis pe.c i fi edi s e tnoi.nt t ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One pressurizer safety A.1 Restore valve to 15 minutes valve inoperable. OPERABLE status.
B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND 0_R B.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Two pressurizer safety valves inoperable.
SAN ON0FRE--UNIT 2 3.4-28 Amendment No. 127
Pressurizer Safety Valves 3.4.10 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify each pressurizer safety valve is In accordance OPERABLE in accordance with inservice with the testing program. Following testing, liii.
~
Inservice as-found; lift se_.tting_s..shall be.within +3% Testing Program ori-2*t.t.;.However, . pressurizer safety valves
~
shall? be' set:1to within *1%[of1the.lspecified I setpoin.ti 14. ;
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l SAN ONOFRE--UNIT 2 3.4-29 Amendment No. 127
Pressurizer Safety Valves B 3.4.10 B 3.4 REACTOR C0OLANT SYSTEM (RCS)
B 3.4.10 Pressurizer Safety Valves 1 l
BASES
]
BACKGROUND The purpose of the two spring loaded pressurizer safety !
, valves is to provide RCS overpressure protection. Operating in conjunction with the Reactor Protection System, two )
valves are used to ensure that the Safety Limit (SL) of i
2750 psia is not exceeded for analyzed transients during operation in MODES 1, 2 and 3. During MODE 4, MODE 5, and MODE 6 with the reactor pressure vessel head on, overpressure protection is provided by operating procedures and LC0 3.4.12, " Low Temperature Overpressure Protection (LTOP) System " For these conditions, American Society of MechanicalEnhineers(ASME)requirementsaresatisfiedwith one safety valve.
The self actuated pressurizer safety valves are designed in accordance with the requirements set forth in the ASME . . _
Boilet and Pressure Vessel Code Section III (Ref. 1 as-foundtlifttpressuresist2500 p,sia,#3*eorM2%%Ref)d. 4 d, T Fo11'wingitesting
~
withinfi1%1of5ther# pressurizer %safetyyvalvesish o
specifiedisetpoint; The iequhci iiil t
pic33uie is 2500 paia 1^..'The safety valves discharge steam from the pressurizer to a quench tank located in the containment'(Ref. 2). The discharge flow is indicated by an increase in temperature downstream of the safety valves and by an increase in the quench tank temperature and level.
TheTs5!fou d upper onll imi ti ngithe s RCS@ pres su retto pes surs of30lda V110%S t des i gn! nc611iiit tll6fG3%31Wbase pre s s u re:;;;fo r infrequentidesign3basisneventsiandil20%iofsdesigntpressure for41 Imi .t i ng ; f aul ted; even t si JThes a sefoundil owera pres su re :.
tolerance 41imit occ u rs t ont h.i ressgh y p[of92%11 si b_ase d ionien s u ri ng s ai actuationi(Ref.J); gizer; , i ne pressure l prior;tossafety3yalve uppei anu ivwei fessui e j unj a ai e unscu un Luc A A9-Luieiante i equ i s einen t pc i . Aj ivi iiiLiny pressuies o'u vy c 1000 p3 h. The lift setting is for the ambient conditions associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between-hot and cold settings be established.
The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated accidents. OPERABILITY of the safety val.ves ensures that the RCS pressure will_be limited to 110% ort 120% of..desikn te pres s ure , Ldependi designTbasiss: event. The ng [on T thef f requencifcl consequences of exceeding as s_1 the ficat ion'ofi' ASME pressure' limit"(Ref. 1) could include damage to RCS components, increased leakage, or e requirement to perform additional stress analyses prior to resumption of reactor operation.
(continued)
-SAN ON0FRE--UNIT 2 8 3.4-51 Amendment No. 127
4 Pressurizer Safety Valves B 3.4.10 BASES (continued) i APPLICABLE All accident analyses in the UFSAR that require safety valve SAFETY ANALYSES actuation assume operation of 6.th pressurizer safety valves
- to limit increasing reactor coolant pressure (Ref. 3). The
- overpressure protection analysis is also based on operation j
of both safety valves and assumes that the valves open at the high range of the setting (2500-psia system design
_ pressure plus 1%). These valves must accommodate pressurizer insurges that could occur during a startup, rod withdrawal ejected rod, loss of main feedwater or main feedwateriinebreak. accident. Thecombinedreiiefcapacity of these valves is sufficient to limit the System pressure to within its Safety Limit of 2750 psia following a complete loss of turbine' generator load while operating at RATED THERMAL POWER and assuming no reactor trip until the first Reactor Protective System trip setpoint (Pressurizer Pressure-High) is reached i.e., no credit is taken for a direct reactor trip on the(loss of turbine) and also assuming no operation of the steam dump valves. The startup i
~ accident establishes the minimum safety valve capacity. The startup accident is assumed to occur at < 15% power. Single i failure of a safety valve is neither assumed in the accident
! analysis nor required to be addressed by the ASME Code.
4 Compliance with this specification is required to ensure j
~
that the accident analysis and design basis calculations remain valid.
2 The pressurizer safety valves satisfy Criterion 3 of the NRC Policy Statement.
LC0 The design twopressure pressurizer '2500 safety) valves psia and within arethe setASME to open at the RCS specified
- tolerance to avoid exceeding the maximum RCS design pressure
- SL, to maintain accident analysis assumptions,_and to comply
, Thel as-found < upper / pressure .
with.ASMECode.
tolerancealimitiofa3%2istba requirements.$$donslimitingLthe?RCSipressure
- toil 10%soffdesiin; pressure;for;1nfrequentidesignbasis1 d
events L and e 120% > of' design! pressureiforal imi ti ng / f aul ted .
events N Theiassfoundflower?pressurettoleranc'erlimit;ofM 2%
- issbasedfoniensuringLalreactoretriploccursionihigh
- pressurizerfpressurejprioritofsafepjvalvef actuati,onf(Ref!
{ 4). % upper oriu iuwer pr c33ui e, j ini L3,aie,uadeu via Liit 2
, A-a- Lv i ci o sit.c i equ i s ciutric pe i . Aj ivi iiicsay picasusc3 abvvc 1000 pais. -The limit protected by this s is the. reactor coolant pressure boundary (RCPB)pecification SL of 110%
orL120% of design pressure. Inoperability of one or both l valves could result in exceeding the SL if-a transient were to occur. The consequences of exceeding the ASME pressure limit could include damage to one or more RCS compc rots, increased leakage, or additional stress analysis beug
. required prior to resumption of reactor operation.
W (continued)
SAN ON0FRE--UNIT 2 B 3.4-52 Amendment No. 127
_ . . . _ ___ __. . . _ . ~. _ __ _ _ . . _ _ _ . _ _ _ _ _ _ . _ __
Pressurizer Safety Valves B 3.4.10 BASES ACTIONS B.1 and B.2 (continued)
The 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed is reasonable, based on operating experience, to reach MODE 3 from full power without challenging plant systems. Similarly, the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed l is reasonable, based on operating experience, to reach l M0DE 4 without challenging plant systems. The change from '
MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power and pressure), lowers the potential for large pressurizer !
insurges, and thereby removes the need for overpressure l protection by two pressurizer safety valves.
l SURVEILLANCE SR 3.4.10.1 REQUIREMENTS SRs are specified in the inservice testing program.
Pressurizer safety valves are to be tested one at a time and in accordance with the requirements of Section XI of the ASME Code (Ref. 1), which provides the activities and the Frequency necessary to satisfy the SRs. No additional requirements are specified.
The assfddnd. pressurizer safety _ valve .tolbFsncsfis33Qor . l E2%1forSOPERABILITY.;j followingitesting E pressurizerf safety, valvesishallibeiset91thinf*1%:offtheisp;ecified;setpoint; s e i.pv i n i. is i 14 Tur GFERABILITY.
REFERENCES 1. ASME, Boiler and Pressure Vessel Code,Section III, Section XI.
- 2. UFSAR, Section 5.4
- 3. UFSAR, Section 15.
l 4i AB@iit t sr LNoMSTs96M23 l d ali@Did erne n?.'19h i996 i s ubj ec t s:)Tra nsmi t t al 4a nd l Compl e ti oni.ofit he ; S C E i SONGS t
2/3 JSV1 Tolerance [ Study 2 I
SAN ON0FRE--UNIT 2 B 3.4-54 Amendment No. 127
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Attachment D Proposed Technical Specifications and Bases i (Bases changes are for Information Only)
(Redline and Strikeout)
SONGS Unit 3 l
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Pressurizer Safety Valves 3.4.10 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.10 Pressurizer Safety Valves LC0 3.4.10 .Two pressurizer safety valves shall be OPERABLE with a liii as@foundslift settings of 2500 psia,i+3%for42% t--h.
APPLICABILITY: MODES 1, 2, and 3.
)
NOTE---------------------------- l The lif t settings are not required to be within LCO limits during MODE 3 for the purpose of setting the pressurizer safety valves under ambient (hot) conditions. This exception is allowed for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> following entry into MODE 3 provided a preliminary cold setting was made prior to heatup.
Eabli?pressurizerfsafetyLValYe%As? an 'as1found:sfl'branceJf
+3% orl-2%iETollow1.ngitesting11n;accordan~ceiwith 1 .
TS ; 5;5 ; 2.10,j. pres su ri zer ;;s afe t9.s val vesis ha l l f befs et L wi t hi n il %::Lof [t he; s pe c i fi ed ;s et poi n t ;
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One pressurizer safety A.1 Restore valve to 15 minutes valve inoperable. OPERABLE status.
B. Required Action and 8.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion l Time not met. AND OR B.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Two pressurizer safety valves inoperable. l SAN ON0FRE--Ut?IT 3 3.4-28 Amendment No. 116
_ . ~ . . - . _ - _ . _ _ - _ _ _ . . _ _ . . _ _ _ _ _ . _ _ _ _ . _ _ _ _ _ . . . . . . _ _ . - . _ . .
1 Pressurizer Safety Valves i 3.4.10
\
SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify each pressurizer safety valve is In accordance OPERABLE in accordance with inservice with the testing progr.am. Following testing, iiii. Inservice 64found;. lift settings Testing Program ori-2%hEHowevern pres. .shal1 surizer.; safetybe withi.n 43(
1 valves shallibelsetito:within?..*1%%off thegpecified
's.etpoi_ntett.
f f
4 I
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SAN ON0FRE--UNIT 3 3.4-29 Amendment No. 116
-r .
,, y _.- , .- ., ,, - ,- - - - - .---,,-x-
l Pressurizer Safety Valves i B 3.4.10 )
B 3.4 -REACTOR COOLANT SYSTEM (RCS)
B 3.4.10 Pressurizer Safety Valves BASES 1
BACKGROUND The purpose of the two spring loaded pressurizer safety '
valves is to provide RCS overpressure protection. Operating in conjunction with the Reactor Protection System, two valves are used to ensure that the Safety Limit (SL) of 2750 psia is not exceeded for analyzed transients during operation in MODES 1, 2 and 3. During MODE 4, MODE 5, and MODE 6 with the reactor pressure vessel head on, overpressure protection is provided by operating procedures and LC0 3.4.12, " Low Temperature Overpressure Protection (LTOP) System " For these conditions, American Society of Mechanical Engineers (ASME) requirements are satisfied with one safety valve.
The self actuated pressurizer safety valves are designed in accordance with the requirements set forth in the ASME,.
Boiler and Pressure Vessel. Code, Section.III_(Ref. 1 .J The as-found411ftvpressure;is52500 psiaW3%for:-2%SRef)n4).a Followi ng : tes ti ng 4 pressuri zer;1:saf ety
- val ves ;sha' i n be" set wi thi n it 1%L ofithe itspeci f i ed ); s e t poi nt . The iequo ed liiL ~
piessuic is ^500 psia i 1;..~The safety valves discharge steam from the pressurizer to a quench tank located in the containment (Ref. 2). The discharge flow is indicated by an increase in temperature downstream of the safety valves and by an increase in the quench tank temperature and level.
Thelaskf00Adid ertpres'sureit01shncellisitMf33Ris4ased onslimitingith .RCS; pressure 4to1110%Joftdesig Epressure.i?for infrequentsdesignLbasisteventscandil20%1of designJpres'sure forilfmitingifaultedfevents. ITheras-found lowerzpressure-tolerance /1imit.:Lof52%AistbasedJon; ensuring a. reactoritrip occurston:-highipressurizeripressure prior to safetp valve actuation [(Ref;d)v,Theupper and lum f essute i hnj n ar e vascu vu Luc A v.-tuiciante a cqu i s tiuta n pt s . Aj ivi iiicing pie 33uic3 abuve 1000 p3 9 The lift setting is for the ambient conditions associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between hot and cold settings be established.
The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated accidents. OPERABILITY of the safety valves ensures that the RCS pressure will be limited to.110%J r): 120% of design pressure sdepending:fonithelfrequencyiclassification ofithe designTbasisxevent.~ The'conseguences of exceeding the ASME pressure' limit'(Ref. 1) could include damage to RCS components, increased leakage, or a requirement to perform additional stress analyses prior to resumption of reactor operation.
(continued)
SAN ON0FRE--UNIT 3 8 3.4-51 Amendment No. 116
Pressurizer Safety Valves B 3.4.10 BASES (continued)
APPLICABLE All accident analyses in the UFSAR that require safety valve SAFETY ANALYSES actuation assume operation of both pressurizer safety valves to limit increasing reactor coolant pressure (Ref. 3). The overpressure protection analysis is also based on operation of both safety valves and assumes that the valves open at the high range of the setting (2500-psia system design pressure plus 1%). These valves must accommodate pressurizer insurges that could occur during a startup, rod withdrawal ejected rod loss of main feedwater or main feedwateriinebreakacc,ident. Thecombinedreliefcapacity of these valves is sufficient to limit the System pressure to within its Safety Limit of 2750 psia following a complete loss of turbine generator load while operating at RATED THERMAL POWER and assuming no reactor trip until the first Reactor Protective System trip setpoint (Pressurizer i.e., no credit is taken for a Pressure-High) direct reactor trip is on reached the (loss of turbine) and also assuming no operation of the steam dump valves. The startup accident establishes the minimum safety valve capacity. The startup accident is assumed to occur at < 15% power. Single failure of a safety valve is neither assumed in the accident analysis nor required to se addressed by the ASME Code.
Compliance with this specification is required to ensure that the accident analysis and design basis calculations remain valid.
The pressurizer safety valves satisfy Criterion 3 of the NRC Policy Statement.
LCO The two pressurizer safety) designpressure(2500 psia and valves withinare thesetASMEto open at the RCS specified tolerance to avoid exceeding the maximum RCS design pressure SL, to maintain accident analysis assumptions with . ASME . Code. requirements. ._Theias-found ~
rupp, and,to comply eripressure tolerancellimitfof n3%fis; based ontlimitingi: thel:RCS pressure toil 10%jofldesi eventsi and ?l20%gnipressure?fordnf
- ofcdesign
- pressure +for;< requent$ design?
limiting? basi sT ~ ~
faulted events N The;askfoundflowerfpressureitolerancetlimit(ofM2%
istbasedion?ensuringiaireactorftriproccurston high' pres su ri zeripres sure/ pri orntof s afe,tysv al ve J actu a ti ont(Rsf i 4). ine upper aliu !vner p a c3 3u r c , l un a c3, a s,t vastu un cut 2
- v. - c u i c i a u t.e a cqu a i tiacu c pei . Aj ivi aiscing pit 33ures a'uve u 1000 p3is. The limit protected by this s is the reactor coolant pressure boundary (RCPB)pecification SL of 110%
ort 120% of design pressure. Inoperability of one or both l valves ~could result in exceeding the SL if a transient were I to occur. The consequences of exceeding the ASME pressure limit could include damage to one or more RCS components, increased leakage, or additional stress analysis being required prior to resumption of reactor nperation.
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SAN ON0FRE--UNIT 3 B 3.4-52 Amendment No. 116
Pressurizer Safety Valves B 3.4.10 BASES l
ACTIONS B.1 and B.2 (continued) l The 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed is reasonable, based on operating experience, to reach MODE 3 from full power without challenging plant systems. Similarly, the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed is reasonable, based on operating experience, to reach MODE 4 without challenging plant systems. The change from MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power j and pressure), lowers the potential for large pressurizer ;
insurges, and thereby removes the need for overpressure protection by two pressurizer safety valves.
I SURVEILLANCE SR 3.4.10.1 REQUIREMENTS SRs are specified in the inservice testing program.
Pressurizer safety valves are to be tested one at a time and in accordance with the requirements of Section XI of the ASME Code (Ref. 1), which provides the activities and the Frequency riecessary to satisfy the SRs. No additional requirements are specified.
The 'a'-fou~nd s pressurizer safMy valve toleranceffs +3% or
-2% for:0PERABILITY: . LFolloWing{testi_ng,L pressurizer safety valvestshall'beiset'withinii1%iofithe:specified setpoint.
s t ipu un. o i le fur GFETABILITs.
REFERENCES 1. ASME, Boiler and Pressure Vessel Code,Section III, Section XI.
- 2. UFSAR, Section 5.4
- 3. UFSAR, Section 15.
~
- 4. ABBl Letter:No.t~ ST-96-6231 dated December 19,_::1996i- .
subject Transmittal andicompletionfof:the SCE. SONGS 2/3_PSV3 Tolerance-Stub I
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SAN ON0FRE--UNIT 3 B 3.4-54 Amendment No. 116 l
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PCN 493 Attachment E Proposed Technical Specifications SONGS Unit 2 l
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Pressurizer Safety Valves 3.4.10 h
3.4 REACTOR C0OLANT SYSTEM (RCS) 3.4.10 Pressurizer Safety Valves LC0 3.4.10 Two pressurizer safety valves shall be OPERABLE with as-found lif t settings of 2500 psia, +3% or -2%.
APPLICABILITY: MODES 1, 2, and 3.
NOTE--------------------------_-
The lift settings are not required to be within LC0 limits <
during MODE 3 for the purpose of setting the pressurizer i safety valves under ambient (hot) conditions. This exception is allowed for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> following entry into MODE 3 provided a preliminary cold setting was made prior to heatup.
Each pressurizer safety valve has an as-found tolerance of
+3% or -2%. Following testing in accordance with TS 5.5.2.10, pressurizer safety valves shall be set within *'
11% of the specified setpoint.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME 1
A. One pressurizer safety A.1 Restore valve to 15 minutes ,
valve inoperable. OPERABLE status.
B. -Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND t-
-OR B.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Two pressurizer safety valves inoperable.
SAN ON0FRE--UNIT 2 3.4-28
Pressurizer Safety Valves 3.4.10 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify each pressurizer safety valve is In accordance ,
OPERABLE in accordance with inservice with the I testing program. Following testing as-found Inservice lift settings shall be within +3% or -2%. Testing Program However, pressurizer safety valves shall be set to within *1% of the specified setpoint. i l
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l SAN ONOFRE--UNIT 2 3.4-29
PCN 493 l
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I Attachment F I l
Proposed Technical Specifications )
l SONGS Unit 3
Pressuriger Safety Values 3.4.10 3.4 1 REACTOR COOLANT SYSTEM (RCS) 3.4.10 Pressurizer Safety Valves-LC0 3.4.10 Two pressurizer safety valves shall be OPERABLE with as found lift settings of 2500 psia, +3% or -2%.
' APPLICABILITY: MODES 1, 2, and 3.
NOTE---------------------------.
The lift settings are not required to be within LC0 limits during MODE 3 for the purpose of setting the pressurizer safety valves under ambient (hot) conditions. This exception is allowed for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> following entry into MODE 3 provided a preliminary cold setting was made prior to heatup.
Each pressurizer safety valve has an as-found tolerance of
+3% or -2%. Following testing in accordance with TS 5.5.2.10, pressurizer safety valves shall be set within.
- 1% of the specified setpoint.
ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One pressurizer safety A.1 Restore valve to 15 minutes valve inoperable. OPERABLE status.
B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion -
Time not met. AND OR B.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> .
Two pressurizer safety i valves inoperable. i SAN ON0FRE--UNIT 3 3.4-28
Pressurizer Safety Valves 3.4.10 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.10 i Verify each pressurizer safety valve is In accordance OPERABLE in accordance with inservice with the testing program. Following testing as-found Inservice lif t settings shall be within +3% or -2%. Testing Program However, pressurizer safety valves shall be set to within 11% of the specified setpoint.
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SAN ON0FRE--UNIT 3 3.4-29
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Attachment G (For Information Only)
Updated Final Safety Analysis Report (UFSAR) Chapter 15 Analysis Sections for Loss of Condenser Vacuum, Chemical and Volume Control System Malfunction, and Feedwater System Pipe Breaks Analyses.
I
15.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM TURBINE PLANT 15.2.1 MODERATE FREQUENCY INCIDENTS 15.2.1.3 Loss of Condenser Vacuum 15.2.1.3.1 Identification of Causes and Frequency Classification The estimated frequency of a loss of condenser vacuum classifies it as a moderate frequency incident, as defined in reference 1 of section 15.0. A loss ofcondenser vacuum may occur due to failure of the circulating water system to supply cooling water, failure of the main condenser evacuation system to remove noncondensible gases, or excessive leakage of air through a turbine gland packing.
in accordance with the direction given in Sections 15.0 and 15.0.7, additional information whict.
completes the presentation of this event is provided in Section 15.10.2.1.3.
I5.2.1.3.2 Sequence of Events and Systems Operation The turbine generator trip that occurs due to a loss of condenser vacuum would normally generate an immediate reactor trip signal from the turbine stop valves (through unitized actuator pressure monitors). If credit is not taken for reactor trip on turbine trip, reactor trip would occur as a result of high-pressurizer pressure. The turbine bypass valves are unavailable following a loss of condenser vacuum due to the actuation of the condenser vacuum interlock on the turbine generator trip. The feedwater pumps would trip on low suction pressure soon aner turbine trip.
It is conservatively assumed that feedwater flow is terminated immediately aner turbine trip. The pressure increases in the primary and secondary systems following reactor trip are limited by the pressurizer and steam generator safety valves. Following turbine trip, offsite power is available to provide ac AC power to the auxiliaries. The case ofloss of all normal ae AC power is presented in paragraph 15.2.1.4. The operator May may cool the NSSS using manual operation of the auxiliary feedwater system and the atmospheric steam dump valves any time aner the reactor trip occurs.
The analysis presented herein conservatively assumes that operator action is delayed until 30 minutes aner the first indication of the event.
The consequences of a sin 3:u nie! function of en ective coniponaii vi spieni fo!loivin3 e loss of condenser iecunni Loss of Condenser Vacuum are discussed in peregrepli ! 5.2.2.3.
Tab!v 15.2-1 gis cs e scquencu of events no more adver'se thet occur than those following a loss Loss of condenser incunni Condenser Vacuum' with a single failure; which is described in 15.2.2.3. Therefore, refer to the finel steb!lkcd condition sequence ofevents and results of the
~
LOCV with Single Failure ~ (Section 15.2.2.3) for. event sequence details.
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15.2.1.3.5. Radiological Consequences The radiological consequences due to steam releases from the secondary system are less severe than the consequences of the inadvertent opening of the atmospheric dump valve discussed in paragraph 15.1.1.4, I
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15.2.2.3 Loss of Condenser Vacuum with a Concurrent Single Failure of an Active Comnonent 15.2.2.3.1 Identification of Causes and Frequency Classification The estimated frequency of a loss of condenser vacuum with a concurrent single failure of an active component classifies this incident as an infrequent incident as defined in reference 1 of section 15.0. The cause of the loss of condenser vacuum is discussed in paragraph 15.2.1.3.1.
Various active component single failures were considered to determine which failure had the most adverse effect following a loss of condenser vacuum. The single failures considered were (1) a loss of all AC power on turbine trip, and (2) failure of a pressurizer level measurement channel associated with the pressurizer level control system. The failure of a pressurizer level measurement channel produces the most adverse effect following a loss of condenser vacuum.
This failure is assumed to produce a false low level signal, resulting in activation of both standby charging pumps and the closing of the letdown control valve to its minimum flow area.
In accordance with the direction given in Sections 15.0 and 15.0.7, additional information which completes the presentation of this event is provided in Section 15.10.2.2.3.
15.2.2.3.2 Sequence of Events and System Operation The systems and reactor trip which operate following a loss of condenser vacuum with failure of a pressurizer level measurement channel are the same as those described in paragraph 15.2.1.3.2 following a loss of condenser vacuum.
Table 15.2-5 and Table 15.2-7 give a sequence of events that occur following a loss of condenser vacuum with concurrent failure of a pressurizer level measurement channel for peak RCS pressure and peak secondary pressure cases.
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l Table 15.2-5 SEQUENCE OF EVENT S FOR THE LOSS OF CONDENSER VACUUM EVENT WITH CONCURRENT SINGLE FAILURE - PEAK RCS PRESSURE CASE
- Time (sec) Event Setpoint or Value 0.0 Closure of turbine stop valves on turbine trip due to loss of condenser vacuum 9-8.84 High pressurizer pressure trip condition 2;439 241.0 psia occurs 1
8-79,5 Trip breakers opeii, pressurLsi sefety velves (Ten 10.3 Pressurizer safety valves begin to open, psia 2:536 2575 psia iM Main steam safety valves open +H31122 psia 10 5 9S CEAs begin to drop into core 10.51 R5 Maximum RCS pressure occurs 2744 +2-750 psia lli3 1 Me Peak secondary pressure occurs <l210 psia 15.'2 MB Pressurizer safety valves close 2Mie 2459 psia 15.67 1800 Operators bhgin plasticoold6wn thiough - --
atmosph'eric; dun p valves.
The sequeiice of evciits picss ited is for the peek RCS picssure cosc which esadiiica &
MSSV sctpun i tolersiice of ;3% The peek RCS pressure cese .c.ievied eiid Appivved by the NRC essuiiied e MSSV sctpoiiit tolerer.ce of : 2W
Table 15.2-6 KEY PARAMETERS ASSUMED IN THE LOSS OF CONDENSER VACUUM ANALYSIS WITH CONCURRENT SINGLE FAILURE - PEAK RCS PRESSURE CASE PARAMETER, UNIT VALUE Initial Core Power, MWt 3,478 Initial inlet Coolant Temperature, F 5+2 537F Initial volumetric Flow Rate,4#4bm/hr, gpm iM9 376,200 Initial RCS Pressure, psia 2,000 Initial Steam Generator Pressure, psia 796 Moderator Temperature Coeflicient,10" Ap/ F &O -0.3(")
Fuel Temperature Coeflicient Multiplier 0.75 Minimum CEA Worth at Trip, % Ap -6.0 Pressurizer Safety Valve Opening Setpoint Tolerance +3%
Main Steam Safety Valve Opening Setpoini Tolerance +2%
Steam Bypass Control System Inoperative Reactor Trip on Turbine Trip Inoperative Pressurizer Pressure Control System Inoperative Pressurizer Level Control System Single Failure is Assumed
(*) The initial core inlet tsmperature (Ta) was varied from 532 F to 560 F to' determine the (Ta)which maximizes peak RCS pressure
(**) This analysis supports a most positive MTC of-0.3x104 Ap/ F at IIFP. (Technical ,
Specification LCS 3.1.100) l I
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Table 15.2-7 SEQUENCE OF EVENTS FOR THE LOSS OF CONDENSER VACUUM EVENT XNALYSIS WITH CONCURRENT SINGLE FAILURE - PEAK SECONDARY PRESSURE l CASE
- i i
Time (sec) Event Setpoint or Value 0.0 Closure of turbine stop valves on turbine trip -----
due to loss of condenser vacuum 1
4-6.4.0 Main Steam Safety Valves Open i+B .1122 psia M 9.9 High pressurizer pressure trip condition ?;4M 2,4.10 psia !
occurs th410.8 Trip breakers open ------
B Picssurizer aefdy ,el,c, opeii 2;538 psie I M Md.uniiniii ECS P esause occuis < 2,600 paia M 11,9 CEAs begin to drop ^intofcore 49-5 Mo.umuni Pressurizer Liquid Voluiiic ocenia 40M-#
its Pressurizcr >&feij 4 elves close 2,410 psie 44-9 13.1 Peak secondary pressure occurs ; 1,2101178 psia 13 3 Maximuni RCS pressure' occurs 4,600 psia l 1800 Operat6rs begin plant cooldown througli -----
! atmospheric' dump valves
- The scqusiice of cweiits pasciited is fcw the pcek RCS psssure cese ishich essuiiied a MSSV sdponni tolerence of :"G. The peek RCS pressure cese essuiiied & MSSV seipuini 10'ei Anve vf t 2%.
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3 Table 15.2-8 KEY PARAMETERS ASSUMED IN TiiE LOSS OF CONDENSER VACUUM ANALYSIS WITH CONCURRENT SINGLE FAILURE -' PEAK SECONDARY PRESSURE CASE ,
PARAMETER, UNIT VALUE Initial Core Power, MWt 3,478 Initial Inlet Coolant Temperature, F 560 Initial Core Mass VolUmetiic Flow Rate, M*-lbm/hr gpm MOS 443,520 Initial RCS Pressure, psia 2,000 Initial Steam Generator Pressure, psia 955 964 Moderator Temperature Coefficient,10" Ap/ F 0.0 Fuel Temperature Coeflicient Multiplier 0.75 Minimum CEA Worth at Trip, % Ap -6.0 Piessurizer SafetyValve Opening'Setpdint T61erance +3%
~
Main Steam Ssfetp Valve; Opening Setpoint Tolefance t2%
Steam Bypass Control System Inoperative Reactor Trip on Turbine Trip Inoperative Pressurizer Pressure Control System Automatic Pressurizer Level Control System Automatic l
1 l
- . - - . . . - .~ - -- -. . - -. .. -- --
15.2.2.3.3 Core and System Performance 15.2.2.3.3.1 Mathematical Model.--The niethenietice! niodel used for c,oluetion of corv oiid systeni pu funiience is idwiiicel to that ds ciibed in peregrayli 15.2.1.3.3 The NSSS response to'a loss of coridenser vacuuni with concurrent single failure was simulate'd using the CESEC
~
computer program described in section 15.0.~
l 15.2.2.3.3.2 Innut Parameters and Initial Conditions. The input parameters and initial conditions used for evaluation of core and systems performance are listed in Table 15.2-6 and Table 15.2-8 l for peak RCS pressure and peak secondary pressure cases. I 15.2.2.3.3.3 Results The results presented below are for the peak RCS pressure and peak secondary pressure cases which assumed a MSSV setpoint tolerance of+3% +2%. The peel- l RCS pre >>uis end peek secondery pressure ceses is,-icved end epproved by the NRC essunied e MSSV seipoint tolerancs of l 2%.JThe dynamic behavior ofimportant NSSS parameters following a loss of condenser vacuum with a concurrent failure of the pressurizer level control system is presented in figures 15.2-H 22 through 15.2-M 30 for the peak RCS pressure case.
The loss of steam flow due to closure of the turbine stop valves produces a rapid increase in the secondany pressure. This produces a rapid decrease in the primary-to-secondary heat transfer, which causes a rapid heatup of the primary coolant. The insurge to the pressurizer increases the pressurizer pressure producing a high-pressurizer pressure reactor trip condition et 7.8 seconds.
The CCAs begin droppin3 into the coie et 9.8 seconds.
The opening of the steam generator safety valves et 10.8 sccends and the pressurizer safety valves et 8.7 ssconds combined with the decreasing core power due to reactor trip to rapidly reduce the primary and secondary pressures after reaching a maximum pressurizer pressure less than 2750 psia. The pressuriur sefciy vel,e> cl esc at 14.8 sucunds. Pcak avvundeiy picasucc end Peak pressurizer water volunn are is calculated in e scperatu sose to be less than 12!0 pais end ! css than the volume which would release liquid through the pressurizer safety valves, respcsiimly.
Peak secondary pressure is calculated in a' separate case'to be less than 1210 psia'.
The steam generator valves continue to relieve steam to the atmosphere until the atmospheric steam dump valves are opened by operator action at 30 minutes. The plant is then cooled to 350 F at which time shutdown cooling is initiated.
The detaild iequence of events for the peak' primary pressure and the peak' secondary pressure cases are presented in Tables.15.2-5_ and 15.2-7 respectively.
The maximum RCS and secondary pressures do not exceed 110% of design pressure following a loss of condenser vacuum with concurrent failure of the pressurizer level control system, thus assuring that the integrity of the RCS and main steam system is maintained.
. - . . .~. . - - . . . - - . _ - . - - - - . -. -- - . - . - - - - . . - . -
i i
15.2.2.3.4 Barrier Performance 15.2.2.3.4.1 Mathematical Model. The mathematical model used for evaluation of barrier j performance is identical to that described in paragraph 15.2.1.3.315,2.2.3.3.
15.2.2.3.4.2 Inout Parametersand Initial Conditions. The input parameters and initial conditions j used for evaluation of barrier performance are listed in Table 15.2-6land Table'15/2-8.
15.2.2.3.4.3 Results Figures 15.2-M 29 and 15.2-24 30 give the pressurizer and steam generator safety valve flowrate versus time following a loss of condenser vacuum witn concurrent failure of the pressurizer level measurement channel. Until operator action is taken at 30 minutes,
. the total steam release to atmosphere discharged through the steam generator safety valves has been no more than 99;ies 100,000 pounds. The operator would then begin a controlled NSSS 4
cooldown at 75 F/hr by opening the atmospheric steam dump valves. After the 3-hour a cooldown, the primary system will have reached an average temperature of 350 F at which point
, the shutdown cooling system may be placed in operation The total steam release to atmosphere during the course of this transient is 759,100 760,000 pounds.
I 15.2.2.3.5 Radiological Consequences i
j The radiological consequences of this event are less severe than the consequences of the inadvertent opening of an atmospheric dump valve discussed in paragraph 15.1.2.4.
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Figure 15.2-30
San Oncfre 2&3 FSAR Updated INCREASE IN REACTOR COOLANT SYSTEM INVENTORY 15.5 INCREASE IN REACTOR COOL ANT SYSTEM INVENTORY 15.5.1 MODERATE FREQUENCY INCIDENTS 15.5.1.1 Chemical and Volume Control System Malfunction 15.5.1.1.1 Identification of Causes and Frequency Classification The estimated frequency of a Chemical and Volume Control System (CVCS) malfunction classifies it as a moderate frequency incident as defined in Reference 1 of section 15.0. A CVCS malfunction that produces an unplanned increase in reactor coolant inventory may be caused by equipment or electrical malfunction or operator error that erroneously activates one or more standby charging pumps or decreases letdown flow. The CVCS malfunction is assumed to occur without increasing or diluting the primary coolant initial boron concentration. The case of a CVCS malfunction that produces a boron dilution is presented in paragraph 15.4.1.4.
15.5.1.1.2 Sequence of Events and System Operation Under normal operating conditions at power, the Pressurizer Level Control System (PLCS) responds to an increase in pressurizer level by increasing the letdown flow to maintain the programmed level. There are two pressurizer level measurement and control channels, each having a process signal indicator and a low-level and high-level alarm associated with it. Only one channel at a time, selected by the operator, is in control of the PLCS. The PLCS can be operated either in manual or automatic to maintain programmed pressurizer level. Usually at
. least one charging pump is running, matched by letdown and reactor coolant pump seal bleedoff.
Several faults or errors can be postulated that will lead to a mismatch between charging and letdown flow and in turn result in an increasing pressurizer level and pressure. For example, with the PLCS in manual, the letdown valve could close, reducing letdown flow to zero, while 1 charging flow remains constant. In the same mode, a standby charging pump could start as the result of a single equipment fault or operator error; in this event, with constant letdown flow, pressurizer level would increase.
The limiting moderate frequency incident, (i.e., the event that would lead to the most rapid increase in RCS inventory) occurs in the automatic mode. This incident causes the pressurizer level controller to fail and transmit a signal to start both non-operating charging pumps
. (assuming that both are in standby) and close the letdown control valve.
San Onofre 2 & 3 FSAR Update CHEMICAL AND VOLUM. "ONTROL SYSTEM MALL JNCTION A low level alarm will be annunciated inuaediately by the defective level instrument channel, and low-low level alarm will be annunciated if the failure was off-scale low or sufficiently on-scale low. A high level and then a high-high level alarm will be annunciated by the alternate channel as actual level increases. In this discussion the alternate channel refers to the level control channel that has not been selected for control. The initial pressurizer level is assumed to be just below the high level alarm setpoint such that the alarm is present shortly after the beginning of the event. Indications include the second channel of pressurizer level, charging and letdown flow rate and all charging pumps running.
\
The operator is expected to respond to the alarms and indications either by switching to the !
second level channel for control, or by stopping the charging pumps manually, or by restoring letdown.
The primary pressure is limited by the High Pressurizer Pressure (HPP) trip and pressurizer safeties, or by operator action to terminate the event.
The secondary pressure is limited by the steam bypass control system (SBCS) valves, or by the steam generator safety valves if SBCS is not available.
The consequences of a single component or system malfunction following this event are discussed in paragraph 15.5.2.1.
8 .
15.5.1.1.3 Core and System Performance A. Mathematical Model The NSSS response to the CVCS malfunction was simulated using the CESEC-III computer program described in Section 15.0.
A bounding calculation was done for the CVCS malfunction to determine if the potential existed for filling the pressurizer before operator action can terminate the charging-letdown flow imbalance. Thejotal volume added by the charging-letdown flow imbalance over a 15 minute period, whi6 is the conservative time assumed for operator action, was determined. Fiiially, a liquid volume increase is produced by condensing the steam in the pressurizer due to the proportional sprays. This volume wcs conservatively assumed to be the liquid volume that would result from condensing the total initial steam region in the pressurizer. The sum of these two volumes, plus the initial pressurizer liquid volume, produces the pressurizer liquid volume based on initial conditions that could be produced during a CVCS malfunction.
~ . - ._. _ _ _ . _._ _ . _ __ _ =._ _ _ _ _ ._
San Onofre 2 & 3 FSAR Update CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION B. Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to the CVCS malfunction are discussed in Section 15.0. In particular, those parameters unique to this analysis are listed in Table 15.5-1.
Since the primary coolant pressure transient before the reactor trip is caused by an increase in primary coolant inventory and not by reactor power increase, no 1 l' power, coolant temperature, or DNB transient is produced before the trip.
MinimizinF the initial RCS pressure results in the longest time possible for filling the pressurizer, which makes the pressure spike worse on a trip. However, maximizing initial RCS pressure causes an earlier trip and allows enough time for j the charging pumps to raise RCS pressure again before operator action is credited.
The peak RCS pressure on repressurization is worse than on the trip.
C. Results The following scenario describes the sequence of events that would occur during _
the limiting CVCS malfunction.
The increase in reactor coolant' inventory initiated by the startup of the CVCS '
charging pumps and loss ofletdown produces an over pressurization of the reactor coolant system (RCS). The increasing pressurizer pressure activates the proportional sprays which slow the pressure increase by condensing steam in the pressurizer.
J The addition of water to the RCS by both sprays and charging increases the i
pressurizer liquid volume and hence raises the water level in the pressurizer. The
. rate of filling is slow enough so that operator action in 15 minutes to terminate the charging-letdown flow imbalance is sufficient to prevent filling the pressurizer. The total increase of waterjevel in the pressurizer during the first 15 l minutes of the transient is approximately 80% of the available steam volume.
l
- -If pressurizer sprays were not available the RCS pressare increases so that a y high-pressurizer pressure reactor trip is required. The RCS coolant contraction on E trip decreases the rate ofliquid level rise in the pressurizer so that operator action ,
in 15 minutes is sufficient to prevent filling and produces an immediate reduction i
- of the RCS pressure.
! The maximum RCS pressure is limited by the high-pressurizer pressure reactor i
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San Onofre 2 & 3 FSAR Update CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION trip and the primary safety valves to 110% of design pressure. Also, the steam generator safety valves limit the main steam system pressure to within 110% of design. Therefore, the integrity of the RCS and main steam system is maintained.
The CVCS malfunction transient is slow enough so that the core protection calculators will assure therejsjhe: ic mininuun ONC" is gaa:c ian 1.31 iraughou;ic CVCS ma:Sa;&n :ia..ia:indiceng no violation of the fuel thermal limits.
The dynamic behavior of the significant NSSS parameters following a CVCS
.i . malfunction are shown in Figures 15.5-1 through 15.5-12, and the sequence of events is given in Table 15.5-2.
15.5.1.1.4 Barrier Performance i:
} A. Mathematical Model y
4
- The mathematical model used for evaluation of barrier performance is identical to j that described in paragraph 15.5.1.1.3.
B. Input Parameters and Initial Cdnditions
, The input parameters and initial conditions used for evaluating barrier
- performance are identical to those described in paragraph 15.5.1.1.3, t
b C. Results Any steam discharged by the primary (pressurizer) safety valves is completely condensed in the quench tank and not released to the atmosphere. The steam releases to atmosphere through the steam generator safety valves and maximum RCS pressure reached during the CVCRmalfunction transient are not worse than those of the loss of condenser vacuum shown in paragraph 15.2.1.3. This is due to the less severe primary and secondary transient with a CVCS malfunction.
15.5.1.1.5 Radiological Consequences The radiological consequences due to steam releases from the secondary system are less severe than those due to the inadvertent opening of the atmospheric dump valve discussed in paragraph 15.1.1.4.
_ __ . . _ _ . _ _ . _ _ _ _ , _ . _ . . _ . _ ~ ~ . _ _ _ _ _ _ _ _ _ m . _ _ _ . _ _. ._.- _ _ _ . - . .
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[ San Onofre 2 & 3 FSAR Update 1
I CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION i- 15.5.2 INFREQUENTINCIDENTS 15.5.2.1 Chemical and Volume Control System Malfunction with a Concurrent Single j Failure of an Active Comoonent 1
15.5.2.1.1 Identification of Causes and Frequency Classification i
f ' The estimated frequency of a CVCS malfunction with a concurrent single failure of an active
]_ - component classifies this incident as an infrequent incident as defined in reference 1 of Section F 15.0. The cause of the CVCS malfunction is discussed in paragraph 15.5.1.1.1. Various active i component single failures were considered to determine which failure has the most adverse effect ]
!' following a CVCS malfunction. The worst single active failure is the loss of offsite power at the j- time of reactor trip.
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- 15.5.2.1.2 Sequence of Events and System Operation
! The systems and reactor trip that operate following a CVCS malfunction with single active
} ' failure are the same as those described in paragraph 15.5.1.1.2 .
f' 15.5.2.1.3 Core and System Performance i .
) A. Mathematical Model !
- The mathematical model used for evaluating core and system performance is
-identical to that described in paragraph 15.5.1.1.3.
\
j B. Input Parameters and initial Conditions ;
o i- The input parameters and initial conditions used for evaluation of core and system performance in response to the CVCS malfunction with a single active failure are
[ discussed in paragraph 15.0. Those parameters unique to this analysis are listed in
?
Table 15.5-3. The single active failure is the loss of offsite power at the time of I reactor trip. Minimizing initial RCS pressure delays the high pressure trip and causes a higher peak RCS pressure.
[
C. - Results The dynamic behavior of the NSSS following a CVCS malfunction with loss of i- offsite power at the time of trip is similar to that following a CVCS malfunction, j which is described in paragraph 15.5.1.1.3. Operator action will correct the y i p !
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- CVCS malfunction and prevent filling the pressurizer even if such action is delayed until 15 minutes after first indication of the event.
, The peak RCS and main steam system pressures are within 110% of design
! ensuring that the integrity of the RCS and main steam system is maintained following a CVCS malfunction with loss of offsite power at the time of reactor trip. The minimum DNBR is greater than 1.31 indicating no violation of the fuel thermal limits.
The dynamic behavior of the significant NSSS parameters following a CVCS malfunction with single failure is shown in Figures 15.5-13 through 15.5-24, and the sequence of events is given in Table 15.5-4.
15.5.2.1.4 Barrier Performance 1'
A. Mathematical Model The mathematical model used for evaluating barrier performance is identical to that described in paragraph 15.5.1.1.3.
B. Input Parameters and Initial Conditions The input parameters and initial conditions used for evaluating barrier
- performance are identical to those described in paragraph 15.5.2.1.3 .
C. Results As in the CVCS malfunction, described in paragraph 15.5.1.1.4, the steam
. released to containment or atmosphere and maximum RCS pressure reached are no worse than that released in the loss of condenser vacuum discussed in paragraph 15.2.1.3.
15.5.2.1.5 Radiological Consequences The radiological consequences of this event are less severe than the consequences of the inadvertent opening of a steam generator atmospheric dump valve as discussed in paragraph
- 15.1.2.4.
. 15.5.3 LIMITING FAULTS
?
l There are no limiting faults resulting from an increase in RCS inventory, t
San Onofre 2 & 3 FSAR Update
, CHEMICAL AND VOLUME CONTROL SYSTEM MALFUNCTION TABLE 15.5-1 ASSUMPTIONS FOR THE CVCS MALFUNCTION ANALYSIS Parameter Assumotion Initial core power level, Mwt 3,478 Core inlet coolant temperature, F 54i2-53.3 Core mass flow rate, E+6 lbm/hr 143.7 Reactor coolant system pressure, psia 2,300 Moderator temperature coefficient, E-4 0.0
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Updated Safety Analysis Report CVCS MALFUNCTION RCS PEA.K PRESSURE CASE CORE REACTMTY vs. TIME Figure 15.5 5
. . _ . ~ . - . . .. . - - . - .
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Updated INCREASE IN REACTOR COOLANT SYSTEM I!NENTORY CVCS Malfunction ,
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!- RCS PEAK PRESSURE CASE RCS TEMPERATURE vs. TIME i
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San Cnofre 2&3 FSAR Updated INCREASE IN REACTOR COOLANT SYSTEM INVENTORY CVCS Malfunction 20 , , , , , , , , ,
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San Cno f re 2 & 3 FSla Updated INCREASE IN REACTOR COOLANT SYSTEM INVENTORY CVCS Malfunction 2500 , , , , , , , , ,
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Updated Safety Analysis Report CVCS MALFUNCTION RCS PEAK PRESSURE CASE STEAM GENERATOR' STEAM FLOW RATE vs.
TIME FIGUre 15.5-11
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Updated Safety Analysis Repost CVCS MALFUNCTION RCS PEAK PRESSURE CASE FEEDWATER FLOW vs. TIME Figure 15.5-12
San Onofre 2&3 ESAR Updated INCREASE IN REACTOR COOIANT SYSTEM INVENTORY CVCS Malfunction with Single Failure i i i i i i i i i 1 -
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San Onofre 2&3 FSAR !
Updated INCREASE IN REACTOR COOLANT 1 SYSTEM INVENTORY )
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NUCLEAR' GENERATING STATION Units 2 & 3 Updated Safety Analysis Report CVCS MALFUNCTION WITH SINGLE FAILURE RCS PEAK PRESSURE C ASE CORE HEAT FLUX vs. TIME Figure 15.5-14
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TIME Fi0ure 15.5-23 i
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1 4
15.2.3 LIMITING FAULTS 1
- 15.2.3.1 Feedwater System Pine Brenh t l 15.2.3.1.1 _ Identification of Causes and Frequency Classification i-The'_ estimated frequency of a feedwater system pipe break classifies it as a limiting fault incident as defined in Reference 1 of section 15.0. A feedwater system pipe break may occur due to a pipe faihtre in the main feedwater system.
i g 15.2.3.1.2 Sequence of Events and Systems Operation A'feedwater system pipe break may produce a total loss of normal feedwater and a blowdown of one steam generator. If normal plant electrical power is lost, this superimposes a loss of primary coolant flow, turbine load, pressurizer pressure and level control, and steam bypass control. The culmination of these events is a rapid decrease in the heat transfer capability of both steam generators and eventual elimination of one steam generator's heat transfer capability. The result is an RCS heatup and pressurization. The NSSS is protected during this transient by the pressurizer safety valves and the following reactor trips: (1) steam generctor low water level, (2) steam generator low pressure, (3) high pressurizer pressure, (4) low DNBR and (5) high containment pressure. Depending on the particular initial conditions, any one of these trips may terminate this transient. The NSSS is also protected by main steam isolation valves, the feedline check valves, the steam generator safety valves, and the auxiliary feedwater system which serve
- to maintain the integrity of the secondary heat sink following reactor trip. In this analysis, however, the most adverse single active failure assumed is equivalent to the failure of the electric driven auxiliary feedwater pump associated with the intact steam generator. The operator can initiate a controlled plant cool-down using the atmospheric steam dump valves any time after reactor trip occurs. The analysis presented herein conservatively assumes that operator action is delayed until 30 minutes after the first initiating event. Table 15.2-8 gives the sequence of events that occurs following a feedwater system pipe break to the final stabilized condition; 15.2.3.1.3 Core and System Performance 15.2.3.1.3.1' Mathematical _Model. The NSSS response to a feedwater system pipe break was simulated using the CESEC III computer program described in section 15.0 along with the blowdown model described below. A detailed description of the method of analysis, the initial conditions, and the input parameters is presented in Appendix 15E. Using the core heat flux and core inlet conditions calculated by CESEC-III, the thermal margin on DNBR in the reactor core
- was simulated using the CETOP-D, the thermal margin on DNBR in the reactor core was simulated using the CETOP-D computer program described in section 15.0 with the CE-1 CHF correlation described in Chapter 4.
/- - Blowdown of the steam generator nearest the feedwater line break was modeled assuming
I frictionless critical flow calculated by the Henry-Fauske correlationm. The enthalpy of the blowdown is assumed to be that of saturated liquid until no liquid remains, at which time saturated steam discharge is assumed. This model conservatively underestimates the blowdown energy and overestimates the discharge rate, thereby leading to a more rapid blowdown and thus minimizing the steam gene ator heat removal capability.
A sensitivity study was performed to determine the influence on peak RCS pressure of the rate of decrease of effective heat transfer area in the ruptured steam generator. The effective heat transfer area is assumed to decrease linearly (from design valuc to zero) as the steam generator mass decreases (from selected value to zero). Thus, decreasing the mass interval over which the rampdown is assumed to occur implies a more rapid loss of heat transfer in the ruptured steam
- generator. This study showed that maximizing the rate of decrease of heat transfer area
! maximizes the peak RCS pressure. Therefore, a conservatively high rate ofloss of heat transfer is assumed.
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- 36.9 H.. igh_'P.re_ssdr.i.z_erPr_essu. reTri ~ Con.d_iti_o.~. P_ n" 7.2434 psia 37.8 Trip Breakers;Open; d':---
Normal'On.s...i.te.Po.wer.
L'o. st " .u--.
38.1 Emergencyfeedwater Actuation Signal,"ft 126.27 3_8.5 Affeicte& Steam Ge_nerator EmLties'I_b_m_,
u _? _5000 3 8...s.8.
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v to D rop e-
- ? T
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39.6 Pressurizer S_afetyJalves Start to_ Ope,n; psia ,22575 41'.1, P_eak RCS Pressure,0ccurs, psia J 2832.2 4 511 Pealf SteamiGeneratoLressure P Occursipsia al156.8 4- .7_.57
- M_a.xim._um._
Pre _ssuri.z._e.. r L.- i..qu.. -.
id.,V_ol_um.e .O...ccurs..l .f. t' , <1465.7 48.2 Pressurizer SafetyJ,alves.Close[ psia 12356.1 92.0-A_ux_iliary_Feedw,_.,_ ate _r Ent.ers_Intac_t _
Stea.,m,G_ener_a. tor +-..
212.2 Steam Generator LowJressure Trip;Qondition and._MSIS {675 Ini_tiatedfpsia -
21.3:1 .
M. < ._ain. ~.S_ tea.m_~Is_ola.ti.o__n. - --
i Va_lves B_e. 8 n. J Close 223:1 Complete, Closure;of Main Steam _ Isolation Valves Terminating > ~R B_16wdown... fro._m._the In. tact .Ste. a.m.. ._G._e.nerato. r
__ - . . .~
250.2 Minimum Liquid Mass in the Steam Generator .Qonnected to 1.6990 Intactleediineilbm
414.4 Main Steam Safety Valves Ope.n on the Intact Ste_am Generator, 1133 Psia 1800.0 Operatgr Opens the Atmospheric Steam Dump Valves to begin --
Plant Cooldgwn to Shutdgwn.. Cooling 10 7,2,,_8 1 -
n Coo.-o.in.
Shut,d, ow. 4m, r- s l .. g Initiated I
e
15.2.3.1.3.2 Innut Parameters and Initial Conditions. The input parameters and initial conditions used to analyze the NSSS response to a feedwater pipe break are discussed in Section 15.0, in particular, those parameters which were unique to the analysis discussed below are listed in Table 15.2-9.
The initial conditions for the principal process variables monitored by the COLSS were varied within the reactor operating space given in Table 15.0-4 to determine the set of conditions that would produce the most adverse consequences following a feedwater system pipe break. The full spectrum of break areas was considered up to a break size of the combined area of the flow distributing nozzles in the feedwater ring. For each break, the initial steam generator liquid inventory and the initial pressurizer pressure were adjusted within the plant operating space to maximize the mismatch between core power and steam generator heat removal capacity prior to the CEAs dropping into the core. This mismatch will thus, maximize the peak RCS pressure and
. pressurizer volume. In order to eliminate any impact of uncertainty in the calculated water level in the ruptured steam generator, no credit was taken for low water level trip in the ruptured steam generator. This delays the reactor trip, prolonging the RCS heatup and increasing the peak RCS _ )
pressure. Loss of AC is assumed to occur at the time of turbine trip. This causes the RCS pumps to coastdown, resulting in higher peak RCS pressure.' In addition, in response to loss of non-emergency AC power upon trip, turbine stop valves are assumed to close immediately.
Core inlet temperature and flow had negligible effects on the peak RCS pressure for a gi /en blowdown rate. However, maximizing the core inlet temperature also maximizes the steam generator pressure, which increases the maximum blowdown rate. The maximum inlet temperature of 560*F also maximizes the RCS energy content and thereby increases the radiological releases associated with steam generator safety valve and atmospheric steam dump valve flows. The pressurizer control system is maintained in the automatic mode so that it suppresses the pressure transient before trip. This delays the time of reactor trip, prolonging the RCS heatup and increasing the over-pressurization. However, this control system mode had a small impact on peak RCS pressure.
Of those systems and components called upon to mitigate the consequences of a feedwater system pipe break; i.e., pressurizer and steam generator safety valves, feed line check valves, auxiliary feedwater system, and reactor protective system, failure of the pressurizer or steam generator safety valves, or the feed line check valves, is not considered credible. With respect to the reactor protective system, the most reactive CEA is conservatively assumed to be stuck in the fully withdrawn position. Therefore, the worst active single failure, in addition to the stuck CEA, is the failure of one out of the two auxiliary feedwater pumps. This failure leads to larger radiological releases through the steam generatar safety valves with only one-half the auxiliary feedwater flow available.
15.2.3.1.3.3 Results The dynamic behavior ofimportant parameters following a feedwater system pipe break for abreak size of 0.2 R.2, which gives the maximum of the peak pressure, is
. presented in figures 15.2-37 through 15.2-50.
1 Table 15.2.3-9 4
ASSUMPTIQNS FOR TIIE FEEDWATER SYSTEM PIPE BREAK 4
l - Parameter. Unit Value Initial Core Power, Mwt 3478 i Initial Inlet Coolant Temperature,'F 560 Initial Core Mass Flow Rate, gpm 356,400 Initial RCS Pressure, psia 2%92150 Initial Steam Generator Pressure, psia 949961.6 Moderator Temperature Coefficient,104 Ap/ F 0.0 Fuel Temperature Coefficient Multiplier 0.75 Minimum CEA Worth at Trip, % Ap -6.0 Steam Bypass Control System Inoperative Pressurizer Pressure Control System Automatic Mode .
Pressurizer Level Control System Automatic Mode Feedwater Line Break Area, ft2 0.2 Initial Intact Steam Generator Inventory, Ibm 180,000 Auxiliary Feedwater Flow assuming 1 Pump Only, gpm Figure 15.2.3-51 Number of U-tubes Assumed Plugged per Steam Generator 1000 PSV Setpoint, psia EH02575 Initial Pressurizer Volume, fP 9B9,_13@
i a
4
- The rupture of the main feedwater line is assumed to instantaneously terminate feedwater flow to I the steam generators. Critical flow is assumed to be instantaneously established from the steam generator connected to the ruptured feedline due to the break location between the steam generator and the check valve. Check valve closure prevents flow from the intact steam
, generator to the break. The first -384368 seconds are characterized by a gradual heatup of the ,
3
^
primary and secondary systems due to the absence of subcooled feedwater flow to the steam ;
generators. During this stage, the steam generator connected to the ruptured line loses its heat ,
j transfer capability due to the depleted inventory. This initiates an RCS-to-steam generator power
- mismatch, producing a large insurge to the pressurizer, causing its pressure to exceed the high pressure trip setpoint at 38436,9 seconds. A decrease in the steam generator water level
- initiates a reactor trip on low steam generator water level simultaneously. Reactor trip followed j by turbine trip occurs at 38@338, seconds. Pressurizer pressure continues to increase, passing i the pressurizer safety valve setpoint of 25502575 psia at 39:039.6 seconds. Loss of normal onsite and offsite electrical power is assumed to occur simultaneously with the turbine trip, causing the reactor coolant pumps to coast down. The pressure turns around after reaching a maximum of 3893S2_8322 psia in the RCS at 42-641,1 seconds.
i The core heat flux has decayed sufficiently by this time to reduce the RCS-to-steam generator ,
i power imbalance. By 39-042.2 seconds, the steam generator safety valves open, limiting the j steam generator pressure to a maximum of 4%M1'156.8 psia. By 42-645;l seconds, the power imbalance reverses, with the steam generator removing more energy than the core produces. The pressurizer safety valves close at 54_8J2 seconds as the primary coolant temperature decreases, j- The auxiliary feedwater flow reaches the intact steam generator by 9H92.0 seconds. Reverse steam flow from, the intact to the ruptured steam generator and to the break causes the secondary pressure to decrease below the main steam isolation signal (MSIS) setpoint of 675 psia at j 225:0212.2 seconds closing the main steam isolation valves (MSIVs). Closure of the MSIVs
- causes the secondary pressure and temperature in the intact steam generator to rise, decreasing i- the differential temperature (RCS-to-steam generator) and reducing the heat transfer rate. This i i causes the core average temperature and RCS pressure to rise by 300 seconds and to reach a steady state by 500 accc,aaupon the PSVs_ reopening. By 436-0414.4 seconds, the steam generator safety valves open again and continue to relieve steam to the atmosphere until the atmospheric dump valves are opened by the operator at 30 minutes. The plant is then cooled to l 350 F at which time shutdown cooling is initiated.
i j The results indicate that the feedwater system pipe break event will not result in a peak RCS l
- pressure which exceeds the faulted stress pressure limitof 3,000 psia.
15.2.3.1.4 Barrier Performance i 15.2.3.1.4.1 Mathematical Model. The mathematical model used for evaluation of barrier performance is identical to that described in paragraph 15.2.3.1.3.
I 15.2.3.1.4.2' Input Parameters and Initial Conditions. The input parameters and initial conditions i
used for evaluation of barrier performance are identical to those described in Paragraph i e 15.2.3.1.3.
i ,
i a
! l
15.2.3.1.4.3 Results Figures 15.2-48 and 15.2-49 are steam generator and pressurizer safety )
valve flowrates versus time for the feedwater system pipe break transient. By 30 minutes, when the atmospheric dump valves are opened, the steam generator safety valves will have discharged no more than 74,800 pounds of steam. Approximately 934,000 pounds of steam would be discharged through the atmospheric dump valves during the 3.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of cooldown, giving total steam release to the atmosphere of 1,008,800 pounds. The steam generator connected to the ruptured feedwater line discharges 151,033 pounds of fluid to containment. The pressurizer safety valves release BE&less,than 3000 pounds of steam to the quench tank.
15.2.3.1.5 Radiological Consequences The radiological consequences of this event are less severe than the consequences of the main i steam line break discussed in Paragraph 15.1.3.1.B. I l
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l' 0' 10 20 30 40 50 60 l~ Time, Seconds SAN ONOFRE l NUCLEAR GENERATING STATION Units 2 & 3 l
Feedwater System Pipe Break Core Power vs. Time Figure 15.2-37 1
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0 10 20 30 40 50 60 Time, Seconds SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Core Average Heat Flux vs. Time Figure 15.2-38
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SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Reactor Coolant System Pressure vs. Time Figure 15.2-39 I
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i
1 650 640 630 Tout r.u 4 620 8
Ju 610 3
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U 570 Tin 560 550 0 10 20 30 40 50 60 Time, Seconds SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Coolant Temperatures vs. Time Figure 15.2-40 l
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1350 1300 g 1250
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1150 N '
- '1100
$ 1050 8
- 1000 t
950 ,
900 0 10 20 30 40 '50 60 Time, Seconds SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 l
Feedwater System Pipe Break ;
Pressurizer Water Volume vs. Time !
Figure 15.2-41
)
l 1200 1150 -
.2 S. 1100 - Intact SG oI i n
$ 1050 8
%u 1000-8 E 950 Affected SG 900 850 0 10 20 30 40 50 60 Time, Seconds l
SAN ONOFRE i
, NUCLEAR GENERATING STATION Units 2 & 3 1 1
Feedwater System Pipe Break l Steam Generator Pressure vs. Time l Figure 15.2-42 l
1 l
l i
l l
l l
4000 l l
3000 Intact SG l
0 2000 I e l b
. 1000 o> l G 0-o z
E
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-2000
-3000 0 10 20 30 40 50 60 Time, Seconds SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Steam Nozzle Flow vs. Time Figure 15.2-43
0 Intact 3G j l
% l
-500 l l
l E i li I O -1000 i
0 Y -1500 4
8 W Affected SG
-2000
-2500 0 10 20 30 40 50 60 Time, Seconds SAN ONOFRE NUCLEAR GENER ATING STATION Units 2 & 3 Feedwater System Pipe Break Feedwater Flow vs. Time Figure 15.2-44
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2700 !
m 2600 5
w 2500 S
a i s 2400 u
0
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- 2200 2100 2000 0 10 20 30 40 50 60 Time, Seconds i
l SAN ONOFRE HUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Pressurizer Pressure vs. Time Figure 15.2-45 i
l l
I l
180000 160000 140000 b
120000
.o 100000 3
4 80000 D
60000 g Affected SG 40000 20000 0
0 10 20 30 40 50 60 Time, Seconds SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Secondary Liquid Mass vs. Time Figure 15.2-46 l
40000 l
35000 )
o i q
S 30000 i i I
a 25000 3
3 s
j 20000 8
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15000 10000 0 10 20 30 40 50 60 Time, Seconds SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Core Average Inlet Flow vs. Time Figure 15.2-47
1 l
1 a
4 900
@ 800.
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- i y 500 ;
& l 0 400
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-8 Affected SG
$ 200
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0 10 20 30 40 50 60 Time, Seconds l
SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break Steam Generator Safety Valve Flow vs. Time ;
Figure 15.2-48 l
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350 g 300 e
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, 250 !
3 l l
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x I a j g 150 , ,
m en u ,
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o m
m D
s 50 i
1 0 0 10 20 30 40 50 60 4 1 Time, Seconds i
4
[ SAN ONOFRE
- NUCLEAR GENERATING STATION Units 2 & 3 Feedwater System Pipe Break i Pressurizer Safety Valve Flow vs. Time Figure 15.2-49 4
4 e
, 1 1
1
I 2000 1800 --
o e 0
0 1600
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.0 1400 i
O s 1200 - ,
k..
e c
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q' f-
.9_
-200i 0 10. 20 30 40 50 60 Time, Seconds i
SAN ONOFRE NUCLEAR GENERATING STATION Units 2 & 3 ,
l Feedwater System Pipe Break Pressurizer Surge Inlet Flow vs. Time i
Figure 15.2-50 l
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