ML20211B788
| ML20211B788 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom, Oconee, Limerick, South Texas, Fort Calhoun  |
| Issue date: | 08/10/1999 |
| From: | Beckner W NRC (Affiliation Not Assigned) |
| To: | Clarkson N, Hackerott A, Harrison W, Krueger G DUKE POWER CO., HOUSTON LIGHTING & POWER CO., OMAHA PUBLIC POWER DISTRICT, PECO ENERGY CO., (FORMERLY PHILADELPHIA ELECTRIC |
| References | |
| NUDOCS 9908250094 | |
| Download: ML20211B788 (95) | |
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August 10, 1999 Mr. Alan Hackerott Mr. Greg Krueger Omaha Public Power District PECO Energy Company Ft. Calhoun Nuclear Station Mail Code 63A-3 P.O. Box 399 965 Chesterbrook Boulevard Ft. Calhoun, NE 68023-0399 Wayne, PA 19087 Mr. Noel Clarkson Mr. Wayne Harrison Duke Enerby/Oconee South Texas Project Electric Generating Mail Code: ONO3RC Station
- Highways 130 & 183(29678)
STP Nuclear Operating Company P.O. Box 14393652 P. O. Box 289 Seneca, SC 29679-1439 Wadsworth, TX 77483 Gentlemen.
The purpose of this letter is to transmit the summary of two meetings with the Risk-Informed Technical Specifications Task Force held at the U.S. Nuclear Regulatory Commission (NRC) Headquarters offices in Rockville, Maryland, on May 14 and July 14, 1999.
Sincerely, Original Sfgned By William D. Beckner, Chief Technical Specifications Branch j
Division of Regulatory improvement Programs Office of Nuclear Reactor Regulation
Enclosures:
- 1. Meeting Summaries
- 2. Attendance Lists
- 3. Meeting Presentations f
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- 4. Draft Phase i Action Plan f
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NUCLEAR REGULATORY COMMIS810N l
WASHINGTON, D.C. 30006 4001 August 10, 1999 Mr. Alan Hackerott Mr. Greg Krueger Omaha Public Power District PECO Energy Company Ft. Calhoun Nuclear Station Mail Code 63A-3 P.O. Box 399 965 Chesterbrook Boulevard Ft. Calhoun, NE 68023-0399 Wayne, PA 19067 Mr. Noel Clarkson Mr. Wayne Harrison Duke Enerby/Oconee South Texas Project Electric Generating Mail Code: ONO3RC Station Highways 130 & 183 (29678)
STP Nuclear Operating Company P.O. Box 14393652 P. O. Box 289 Seneca, SC 29679-1439 Wadsworth, TX 77483 Gentlemen:
The purpose of this letter is to transmit the summary of two meetings with the Risk-Informed Technical Specifications Task Force held at the U.S. Nuclear Regulatory Commission (NRC) Headquarters offices in Rockville, Maryland, on May 14 and July 14, 1999.
Sincerely, i
Ms b8 W William D. Beckner, Chief Technical Specifications Branch Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation
Enclosures:
- 1. Meeting Summary
- 2. Attendance List
- 3. Meeting Presentations
- 4. Draft Phase 1 Action Plan ec: See attached list
V Multiple Addressees GG:
Mr. Biff Bradley Mr. Thomas Hook Nuclear Energy Institute San Onofre Nuclear Generating Station j
Suite 400 Southern California Edison 1776 i Street, NW 5000 Pacific Coast Highway Washington, DC 20006-3708 San Clemente, California 92674-0128 Mr. Rick Grantom Ms. Sharon Mahler South Texas Project Electric Generating San Onofre Nuclear Generating Station Station Southern California Edison STP Nuclear Operating Company 5000 Pacific Coast Highway Mail Code N5010 San Clemente, California 92674-0128 P. O. Box 289 Wadsworth, TX 77483 Mr. Frank Rahn Electric Power Research Institute Mr. Jack Stringfellow P. O. Box 10412 Southern Nuclear Operating Company Palo Alto, CA 94303 P.O. Box 1295 Birmingham, AL 35201-1295 Mr. Donald Hoffman l
EXCEL Services Corporation 11921 Rockville Pike, Suite 100 Rockville, MD 20852
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NRC/ INDUSTRY MEETING OF RISK-lNFORMED TECHNICAL SPECIFICATION TASK FORCE MEETING SUMMARIES MAY 14 AND JULY 14,1999 Two meetings between the NRC staff and industry representatives comprising the Risk-informed Technical Specifications Task Force (RITSTF) were held on May 14 and July 14, 1999. The attendees are listed in Enclosure 2. The meetings were a continuation of earlier meetings held in December 1998, Janeary 1999, and March 1999, where the main topic of discussion was the creation of a fully risk-informed set of standard technical specifications (RI-STS).
At both meetings, the Combustion Engineering Owners Group (CEOG) made presentations covering several of the proposed industry initiatives. Presentations made by Ray Schneider of ABB Combustion Engineering Nuclear Operations, Alan Hacherott of Omaha Pulic Power District and Chairman of the CEOG Probabilistic Safety Assessment Committee (PSAC), and Dennis Henneke of Southern California Edison's San Onofre Nuclear Generating Station (SONGS) are provided in Enclosure 3.
At both meetings, the group discussed a revised version of the RITSTF's draft Phase I Action Plan distributed at the previous meeting on March 23-24,1999 (Enclosure 4). The group discussed a general proposed schedule and process. The NRC staff commented in the July meeting that the proposed NRC review schedules seemed overly optimistic.
The July meeting adjourned after the group agreed to a telephone conference on August 2, 1999, to discuss the industry's proposed schedule and process.
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Meeting Attendees May 14,1999 NEng Affiliation Ray Schneider ABB-Combustion Engineering Nuclear Fuel Company Alan Hackerott Omaha Public Power District Dennis Henneke Southern California Edison Frank Rahn Electric Power Research Institute Biff Bradley Nuclear Energy Institute Bryan Ford Entergy Noel Clarkson Duke Power Wayne Harrison South Texas Project Donald Hoffman EXCEL Services Rick Hill General Electric Dennis Buschbaum Texas Utilities Electric Company
/ Westinghouse Owners Group Harry Pontiou's Commonwealth Edison / Boiling Water Reactor Owners Group Thomas Morgan Scientech-NUS Altheia Wyche SERCH Licensing /Bechtel Bill Vesely Consultant Mark Reinhart NRC/NRR/SPSB Millard Wohl NRC/NRR/SPSB Bob Dennig fJRC/NRR/TSB Nanette Gilles NRC/NRR/TSB
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Meeting Attendees July 14,1999 blAma Affiliation Ray Schneider ABB-Combustion Engineering Nuclear Fuel Company Alan Hackerott Omaha Public Power District Dennis Henneke Southern California Edison Brian Woods Southern California Edison Sharon Mahler Southern California Edison Vince Gilbert Nuclear Energy institute Frank Rahn Electric Power Research Instituto Noel Clarkson Duke Power Wayne Harrison South Texas Project Rick Grantom South Texas Project 1
Steve Rosen South Texas Project Donald Hoffman EXCEL Services Rick Hill General Electric Jerry Andrd Westinghouse Jim Andrachek Westinghouse Jack Stringfellow Southern Nuclear Gene Eckholt Northern States Power Don McCamy Tennessee Valley Authority Mike Kitlan Duke Power Thomas Morgan Scientech-NUS Joe Williams NRC/NRR/DLPM Mark Reinhart NRC/NRR/SPSB Mark Rubin NRC/NRR/SPSB Millard Wohl NRC/NRR/SPSB Nick Saltos NRC/NRR/SPSB Chu-yu Liang NRC/NRR SRXB William Beckner NRC/NRR/RTSB Tilda Liu NRC/NRR/RTSB Bob Dennig NRC/NRR/RTSB Nanette Gilles NRC/NRR/RTSB j
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I M
k RISK-INFORMED TECHNICAL SPECIFICATION OPTIMUM END STATES R. Schneider (ABB/CENP)
July 14,1999 t
BACKGROUND eOverview of End State Effort e Benefits of End State Change o Basis for Recommendations 4
i ENCLOSURE '3
x Strategy for Justifying R-I Technical Specifications i
strategy based on Risk informed RG and SRPs Justification of Need o
Deterministic Assessment
- Role of equipment in the lower modes
- Redundancy and diversity issues 1
- Strategies for coping for lower mode transients Risk Evaluation Mode Mode risk comparison for Typical Plant (SCE) l e CDF.LERF Metrics Transition issues
)
- Qualitative assessment of risk insights on Plant differences
- Qualitative discussion of extemal events Developing R-I End States within the Technical Specification is a Win-Win Solution for both the NRC, Industry and the Public Modifying End States Minimizes need for Unnecessary Mode Transitions e Enhanced plant safety New End State poses lowest risk l
Mode transitions risk minimized i
l Risks associated with plant realignment reduced I
e Reduced cost of operations Reduces equipment repair shutdown /startup times Minimizes need to enter LTOP operation l
Added flexibility in allocating resources 3
1 l
i i
l 1
l
f.
End State changes Recommended for:
l e Boration Systems (3.1.9; SONGS, 3.5.4-Boron Limits) l e instrumentation (3.3.4,3.3.5,3.3.8/9/10 (Analog) 3.3.5,3.3.6,3.3.8/9 (Digital))
e RCS Loops (3.4.6, Condition B) e Containment
. Containment antegrity (3.6.112/3)
Containment conditions (3.6.N5)
Most End State Changes Heat Cooling (3.6.6.2)
Involve a change from o Plant Systems Mode 5 to Mode 4 sG Heat Removal (3.7.4/5/6)
Cooling Water (3.7.7/6/10)
RadiologicalProtection (3.7.11/12) l e Power Sources (3.8.1/4/7)
Safety Benefits of Mode 4 End States (SG used for Heat Removal) e Has the greatest redundancy and diversity for hat removal of all shutdown modes 1
- AFW MDAFW,TDAFW, Diesel driven AFW (FCS). Condensate FW pumps Cooling via sDC system following sDC entry
- Once through Core Cooling (Plants with PORVs, or on LTOP) e Lowest susceptibility to LOOP /SBO due to Availability of TD AFW l
LTOP LOCAs may be avoided e Limits alignment Changes (Minimizes primary side alignments, reduces potential errors of commission) e increased resiliency to cope With LOCAs (HPSI availability /LPSI NPSH) e Lower susceptibility to consequences of extemal events l
i i
l l
Disadvantages of Mode 4 End States SG used for Heat Removal e Mode 4 allows high pressure (up to full RCS pressure)
. Mode 4 operation requires greater RCS temperature than Mode 5
- restricts maintenance
- Mode 4 temperatures will result in greater inventory loss following a LOCA (flashing) 9 Safety Benefits of Mode 4 End States (SDC Operation)
Mode 4 End State in SDC Mode of Operation e Once SDC entered Mode 4 / Mode 5 Risks similar e Subtle differences include Advantages
. Mode 4 has formal restraints on minimum equipment Greater range and understanding of recovery procedures
- in. Mode Recovery Disadvantages
> Post LOCA inventory loss greater in Mode 4 than Mode 5.due to increased flashing of RCS inventory Increased potential for LTOP LOCA following LOSDC l
Comparison of Mode 4 Design l
Features Operation for CE PWRs lFCS l 2700 mWT +
ANO 2 l3410 PVNG5 l
MDAFW lV lV V
lV V
TD AF W++
V W
V V
v I
CO ND. PM P W ** '
V V
V SUPPORTS l
HT. RE MOVAL MD
^
__ ;rE 1 O
V 6A v
vECCS "4
7 PORVS VENT
. [,'-
v v
v v
sDC C&P BACKUP l*
l v **
v lV V
FOR SDC I
l l
+ ncivees Pahsaces
- N ot en units
++ use of To AFw sepensenion asians or LuFRo l
- Penial Capabihty l
l l
1 DEFINITIONS MODE 3: HOT STANDBY RCS TEMP > 350 F 1
MODE 4: HOT SHUTDOWN 350 F > RCS TEMP > 200 F l
l MODE 5: COLD SHUTDOWN RCS TEMP < 200 F l
PRESSURE < SDC ENTRY i
l l
l l
l 1
l i
e i
i i
1 l
l j
1 Comparison of Relative Frequency of Mode 3/4/5 Initiating Events Challenges i
i
- m. a. _, _
n.om i
supe Feture ine.eguale NPSH.
- 2. PotertalLERF sceneno j
L NA 2
Appece 6 Diversianteeks 5
'2 NA NA
,_e....nt.n.,s. e.en.
Loss of R Meet 2,3
'3 2
c Removal (non.
SBO) 1 Dreatest Frequency least Frequency I
i i
Comparison of Mode 3/4/5 Coping Capabilities 4
6ecos e cosmEur g amoe a ge to -
2
- i. coss, soc
. <0c..u..
pipe Fasiure aneceouste NPSH,
- 2. PotentalLERF sceneno WC in W
C lNA it it wants assocateo mes eve Dwson/ Leeks e l
t reshonments a
6GTR l1 gNA 1
NA LOOPISBO/ BUS [.
I1 i+
increase m pent canaireo events I
I i wtri meruenena Meel verils mCluas loss heet sents I
-5 Greatest Capotely Least Capotety l
i
~
Summary Bases for Proposed Mode Changes e Risks associated with plant operation in a Mode 4 steam condition are low compared with all other Modes.
. Mode 4 power level is lower than Modes 1 thru 3
, Mode 4 heat removal capabilities are greater than for i
Mode 5 e For certain components out of service, operating in Mode 4 poses much lower risks than for operating in Mode 5.
o Degraded system operation in Mode 4 will not violate design ilmits l
Open Issues i
e Level / Mix of deterministic and risk j
analyses j
e Mix for plant specific and generic j
support.
I I
i d
1 l
l Conclusion e Requested TS Mode changes
> Enhance plant safety
. Improve plant operation n Improve plant economics e Task is on schedule o Open issues should be discussed
.a l
l l
l l
l t
l l
4 l
l i
1
4 RISK-INFORMED TECHNICAL SPECIFICATION OPTIMUM END STATES R. Schneider (ABB/CENP)
July 14,1999 l
4 BACKGROUND eOverview of End State Effort I
e Benefits of End State Change l
e Basis for Recommendations l
ENCLOSURE
1 Strategy for Justifying R-I Technical Specifications strategy based on Risk Informed RG and SRPs Justification of Need a
, Deterministic Assessment
- Role of equipment in the lower modes
- Redundancy and diversity issues
- Strategies for coping for lower mode transients Risk Evaluation
- Mode - Mode risk comparison for Typical Plant (SCE) e CDF,LERF Metrics
- Transition issues
- Qua!itative assessment of risk insights on Plant differences
- Qualitative discussion of extemal events i
Developing R-I End States within the Technical i
Specification is a Win-Win Solution for both the NRC, Industry and the Public Modifying End States Minimizes need for Unnecessary Mode Transitions e Enhanced plant safety
. New End State poses lowest risk
. Mode transitions risk minimized Risks associated with plant realignment reduced e Reduced cost of operations Reduces equipment repair shutdown /startup times
. Minimizes need to enter LTOP operation l
Added flexibility in allocating resources
1 l -
i End State changes Recommended for:
l e Boration Systems (3.1.9; SONGS, 3.5.4-Boron Limits) e instrumentation (3.3.4,3.3.5,3.3.8/9/10 (Analog) 3.3.5,3.3.6,3.3.8/9 (Digital))
e RCS Loops (3.4.6, Condition B) e Containment i
Containment integrity (3.6.1/2/3)
Containment condibons (3.6.45)
Most End State Changes Heat Cooling (3.6.6.2)
Involve a change from o Plant Systems Mode 5 to Mode 4 sG Heat Removal (3.7.W5/6)
. Cooling Water (3.7.7/8/10)
RadiologicalProtection (3.7.11/12) e Power Sources (3.8.1/4/7) l 1
i Safety Benefits of Mode 4 End States (SG used for Heat Removal) e Has the greatest redundancy and diversity for heat removal of all shutdown modes
- AFW-MDAFW.TDAFW,Deseldriven AFW(FCs) Condensate FWpumps Cooling via SDC system following sDC entry
+ Once through Core Cooling (Plants with PORVs, or on LTOP) e Lowest susceptibility to LOOP /SBO due to Availability of TD AFW LTOP LOCAs may be avoided e Limits alignment Changes (Minimizes primary side alignments, reduces potential errors of Commission) e increased resiliency to Cope With LOCAs (HPSI availability /LPSI NPSH) e Lower susceptibility to Consequences of extemal events j
I
f.
\\.
l Disadvantages of Mode 4 End States SG used for Heat Removal e Mode 4 allows high pressure (up to full RCS pressure)
, Mode 4 operation requires greater RCS temperature than Mode 5
. restricts maintenance
- Mode 4 temperatures will result in greater inventory loss following a LOCA (flashing) 1 l
l 9
1 l
l Safety Benefits of Mode 4 End States l
(SDC Operation)
Mode 4 End State in SDC Mode of Operation e Once SDC entered Mode 4 / Mode 5 Risks similar e Subtle differences include Advantaces j
Mode 4 has formal restraints on minimum equipment Greater range and understanding of recovery procedures l
l
- In - Mode Recovery Disadvantaces
. Post LOCA inventory loss greater in Mode 4 than Mode 5.due to increased flashing of RCS inventory l
, increased potential for LTOP LOCA fallowing LOSDC l
l a
i l
I
r c
h Comparison of Mode 4 Design Features Operation for CE PWRs lFC8 l 2700 mWT
lV v
TDAFWe+
W W
V V
v "C 6h 6TPidP -
W v
SUPPORTS HT REMOVAL A W W
PORV8 VENT LPsiP #6R V
W W
v v
SDC C8P SACKUP l*
lV" V
lV v
FOR SDC I
I l
+- ecludes Pahsacos " Not eli unsts
++ Use of TO AFW cependent on detsds of LMFRG
- Partiel Carat >dity l
a DEFINITIONS MODE 3: HOT STANDBY RCS TEMP > 350 F MODE 4: HOT SHUTDOWN 350 F > RCS TEMP > 200 F I
MODE 5: COLD SHUTDOWN RCS TEMP < 200 F PRESSURE < SDC ENTRY l
i i
i i
l l
l l
Comparison of Relative Frequency of Mode 3/4/5 Initiating Events Challenges l
l heues 3 heODE 4 4 6000E 5 COMMENT
)
L noom 3
3
- 1. Lose ' ounng L oue to ppe Fadure kindequate NPSH.
- 2. PotentialLERF ocensrto
-L OP NA 2
L NA NA Evenu assoasted wei verve reengnmens
-ee m 2
NA NA t
, S.
uS,
,_.,,ent c.nte,s. evene i
s Losa of R Heat 2,3 3
2 Events mceude toes of host osas 1
Removal (non-Seo) 1
-3 ormaiset Frequency Leest Frequency i
Comparison of Mode 3/4/5 Coping Capabilities asass a 4
g4 neopa s conesswT LOCA -Ranoom 2
- 2. Potental LERF scenano L
I I,
I, h,.
SGTR 1
MA NA g
o i.
incree
.n p.ni con reo evene.
log 4 heet 580) t
- S Greatest Capetukty Least Capetunty I
i l
Summary Basas for Proposed Mode i
Changes e Risks associated with plant operation in a Mode 4 steam condition are low compared with all other Modes.
. Mode 4 power level is lower than Modes 1 thru 3
. Mode 4 heat removal capabilities are greater than for Mode 5 e For certain components out of service, operating in Mode 4 poses much lower risks than for operating in Mode 5.
e Degraded system operation in Mode 4 will not violate design limits i
'9 i
i Open Issues i
e Level / Mix of deterministic and risk i
analyses l
e Mix for plant specific and generic support.
I e
i
O O
Conclusion e Requested TS Mode changes
. Enhance plant safety
. Improve plant operation
. Improve plant economics e Task is on schedule e Open issues should be discussed i
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1
LCD 3.1.9 - Soration Systems t 3. 4.s "" for Tach Sw The borabon systems are required to ensure that adequate shutdown reactMty margin edsts to bring the plant to Mode 5 with the worst CEA stuck out and the decay anon poison. The systems are also intended to mitigate possible retum to power scenarios followin an MSL8 Per the Tech Specs, the two boration paths that are to remain available are 1) the RWST and its feed to the charging pumps, and 2) one or both BAMU tanks with their respective feed paths the charging pumps.
- ra for t:aina to the End % If a boration path is unavailable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, then the plant must proceed to Mode 3. If the path cannot be restored within the next 7 days, then the must proceed to Mode 5.
PRA Bass: The CVCS injection functions are modeled only for small-small LOCA, SGTR, and ATW Both the BAMU and RWST sources are modeled. Because the PRA does not ccmsider long-term shutdown to Mode 5 (only achieving a stable shutdown over a 24-hour period), modeling of the CVCS to bring the plant to Mode 5 is not considered. Use of CVCS also is not considered for t event.
While one boration path is unavailable, there is a slightly increased risk of core damage due any initiator occurring that requires CVCS injection, particularly if the inoperable path is the one from the RWST. -
' Ch% W: Allow the plant to stay in Mode 3 until the boradon path is restored.
p,.6,.a.,n Anora=< h-A conservative comparison of the relative risks of Mode 3 operation vs. Mode 5 operation can be made by re-solving the PSA model, with the RWST input to the CVCS unavailable, in both Modes 3 and 5.
Conciumians: Modification of the end state of this Technical SpedLW,a to Mode 3 should be acceptable.
L L-----..-- --
[-
f LCO 3J.5 -ISFAS Instrumentation Licensina Bass for Tedi Snac: ESFAS provides automatic actuation of the Engineered Safety Features, which are required for accident mitigation. At least two diannels must be able to trip in order for ESFAS to actuate. Most of the ESFAS fundions are required to be operable only in Modes 1 through 3.
The end state for these functions is theredbre Mode 4, which is arrar*= hie. The Racirculation Actuation Signal (RAS) must be operable in Mode 4 as well, so the current and state for this ESFAS function is Mode S.
l I
Ransons for Going to the End State: 1) Failure to place an inoperable RAS channel in trip or bypass i
within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. 2) Failure to restore an inoperable diannel to operable prior to reaching Mode 2 following the next Mode 5 entry.
I PRA Basis: The RAS fundion is modeled in the PRA for all safety injedion functions that require recirculation operabon. Should a design basis event occur in Mode 4, more time would be available until the switchover to recirculation would need to begin. So, even with one train of RAS unavailable, sumcient time would exist for manual actions to be taken in the event of RAS failure. Note that these manual actions are not included in the current PRA model. Therefore, any evaluation of the impacts of extended operation in Mode 4 with a disabled RAS channel should be conservative.
Situations Considered: Allow the plant to stay in Mode 4 until the RAS channel is restored.
l Evaluation Anoroach:
l A conservative comparison of the relative risks of Mode 4 operation vs. Mode 5 operation can be made by re-solving the PSA model, with one channel of RAS unavailable, in both Modes 4 l-and 5.
==
Conclusions:==
Modificabon of the end state of this Technical Simdh006 to Mode 4 should be W.
i
LCO SJ.6-ESFAS Logic and Manual Tdp Licanana Basis for Tech Scac: ESFAS prwides automatic actuation of the Engineered Safety Features, which are required for accident mitigation. Trip signals from the fbur bistable channels are processed through a set of sk matrix logic circuits to determine if two valid signals edst. If a two-of-four coincidence is detected, four ar*u*wi logic circuits are ar* *, whidi in tum actuate four ESFAS initiation drcuits. A set of two manual trip circuits are also provided, which use the actuation logic and initiation logic circuits to perform the trip function. Many of the ESFAS functions are required to be operable only in Modes 1 through 3. The end state for these functions is therefore Mode 4, which is arraf aN* However, the Recirculation Actuation Signal (RAS) must be operable in Mode 4 as well, so t
the matrix logic drcuits must remain operable in Mode 4. Also, manual actuation capabilty must be prtuded in Mode 4 for SIAS, CIAS, and CCAS, so the manual trip, aduation logic and initiation logic circuits for these signals must be operable.
Ransons for Goina to the End State: 1) One RAS matnx logic drcuit inoperable for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
- 2) One manual trip drcuit, initiabng logic drcuit, or actuation logic drcut inoperable for RAS, SIAS, CIAS or CCAS fbr more than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. 3) Two initiating logic drcuits in the same trip leg for RAS, SIAS, CIAS, or CCAS inoperable for more than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
PRA Basis: The RAS, SIAS, CIAS, and CCAS functions are modeled in the Pl A. Should a design basis event occur in Mode 4, more time would be available to actuate the required NFAS functions, if automatic actuation did not occur.' So, even with portions of the ESFAS logic uni.vailable, suffloent time would exist for manual actions to be taken. Note that these manuel actions are not induded in the current PRA model. Therefore, any evaluation of the impads of extended operation in Mode 4 1
with inoperable ESFAS drcuits should be conservative.
Situations Canadered: Allow the plant to stay in Mode 4 until the RAS, SIAS, CIAS, or CCAS functions are restored. Four specific conditions can be defined to evaluate in Mode 4: 1) one RAS matrix logic channel inoperable; 2) 1 manual trip drcuit inoperable for SIAS, CIAS, or CCAS; 3) one initiating logic drcuit or actuation logic drcut inoperable for RAS, SIAS, CIAS, or CCAS; and 4) two initiating logic drcuits in the same trip leg inoperable for RAS, SIAS, CIAS, or CCAS. Because the actuation logic drcuit failure is the limiting one for cases 2,3, and 4, only cases 1 and 3 need to be explidtly evaluated.
Evaluation Apornach:
- 1) a comparison of the relative risks of Mode 4 vs. Mode 5 opersbon wth one RAS matrix logic circuit inoperable.
- 2) A conservative comparison of the relative risks of Mode 4 operation vs. Mode 5 operation can be made by re-solving the PSA model, with one actuabon logic channel of RAS,51AS, C1AS, and CCAS unavailable, in both Modes 4 and S. This would be conservative since R would assume that all four signais had inoperabilty issues at the same time.
Cancinaions: Modificabon of the end state of this Technical Spedfication to Mode 4 should be
- ~**;
i I
. LCO 3.3.8 - Containment Purge Isolation Signal Licensino Basis for Tech Snec: CPIS provides automatic and manual isolation of any open containment purge valves upon indication of high containment airbome radiation. For Mode 1 through 4, only the containment mini-purge valves may be open. These valves recehm closure signals on SIAS and CIAS.
CPIS is not required for (nor is it credited for) design basis accidents. It wouid be used in Modes 1 through 4 only for instances of unusual buildup of containment radiation levels due to operating leakage.
Reasons for Going to the End State: Failure to enter LCO 3.6.3 and/or 3.4.15 upon detection of CPIS or containment airbome radiation monitor inoperability while mini-purge valves are open.
PRA Basis: The actions of CPIS are not considered in the PRA, since ESFAS functions are credited containment isolation under accident conditions.
Situations Considered: Allow the plant to stay in Mode 4, with the use of the mini-purge valves open, until the CPIS or the containment airborne radiation monitors are made operable.
Evaluation Anoroach:
CPIS does not have a significant plant safety imped in Modes 1 through 4. This system is primarily designed to protect the public from fuel handling incidents, which would not occur in Mode 4. The only situation in which CPIS would help to minimize release (non-acodent) to
' the environment would be under conditions of excessive RCS leakage (or unusually radioactive leakage). Placing the plant in Mode 4 reduces RCS pressure (which would reduce the likelihood of a leak occurring) and RCS actMty (due to decay of radioacthe byproducts) while corrective action is taken.
==
Conclusions:==
Modification of the end state of this Technical SpeciL&i. to Mode 4 should be acceptable.
i
LCD 3.4J - RCS Pressure T1.-;
. e Limits
^
I.kansing Basis: Umits are required to prevent trittle fracture of Reactor Coolant Pressure Soundary (RCPB), parbcularly the Reactor Vessel.
Ransons for Goino to the End State: 1) Pressure / temperature condition is outside the limits and has not been corrected within 30 minutes; g 2) P/T conditions were restored within 30 minutes, but the acceptability evaluation of RCPB integrity was not completed in the required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
PRA Basis: Failure probability of the Reactor Vessel is considered in the VR event, which goes diredly to core damage.
Situabons to Consider:
Gang.h P/r not restored to acceptable value within 30 minutes There is an increased likelihood of vessel rupture. Risk increase is tied directly to rupture frequency increase, which is related to severity of the violation of P/r limits and the exposure time. Dropping to Mode 4 in this case could still keep RCS pressure at a fairiy high value (higher than Mode 5) and hence risk would be higher in Mode 4 than the current requirement to go to Mode 5.
Cast.2: P/T excursion restored in timely manner, but not yet evaluated In this case, the chance of reactor vessel damage is reduced (but still depends on the extent of the excursion). If evaluation, once completed, says everything is OK, then going only to Mode 4 incurs no more risk than going to Mode 5. If, however, the completed evaluation determined that rupture probability is higher, then remaining at Mode 4 would incur higher risk than Mode 5.
==
Conclusions:==
This item is probably NOT a candulate for end state modification 1
Lr
LCO 3.4J.1 - Preneuriser Hestup/Cooldown Unilts Licensing Basis: Limits are required to prevent thermal fatigue of the pressurizer, especially the spray nozzles and the surge line.
Raasons for Goeng to the End State: 1) heatup/cooldown rate is outside the limits and has not been corrected within 30 minutes; g 2) heatup/cooldown rate was restored within 30 minutes, but the acceptability evaluation of pressurizer integrity was not completed in the required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
fMjass; Thermal fatigue in the pressurizer would increase the lilelihood of pressurizer failure (i.e.,
LOCA). Size of the LOCA would be limited to a maximum of the surge lire diameter (most likely a Medium LOCA)
I Situations to Consider:
Casgit Hestup/cooldown rate not restored to acceptable value within 30 minutes There is an increased likelihood of pressurtzer failure. Risk increase is tied directly to rupture frequency increase, which is related to severity of the violation of limits and the exposure time.
Dropping to Mode 4 in this case could still keep RCS pressure at a fairly high value (higher than Mode 5) and hence risk would be higher in Mode 4 than the current requirement to go to Mode 5.
Cast 2: Heatup/s,0;&mii rate excursion restnred in timely manner, but not yet evaluated In this mee, the chance of pressurizer damage is reduced (but still depends on the extent of the excursion). If evaluation, once completed, says everything is OK, then going only to Mode 4 incurs no more risk than going to Mode 5. If, however, the completed evaluation determined that failure probability is higher, then remaining at Mode 4 would incur higher risk than Mode 5.
==
Conclusions:==
This item MAY BE a candidate for end state modification. Further evaluation is required.
e 6
LCO 3.4.6 -ItCS Loope - Mode 4 1.icansina Basis: A means (either via use of one RCS loop or one SDC train) must be prcmded to pnwide forced flow in the RCS for decay heat removal and to drculate boron. RCS circulation is assumed in the safety analyses for the mitigation of boron dilution events. A second means of forced drculatiorg/ hest removal must be available to provide redundancy.
Raanons fbr Goina to the End State: The particular end condition for which a dunge is sought it is the condition in which only one SDC train is operable (i.e., both RCS loops and the other SDC train are inoperable). [It should be noted that in the Bases for the Tech Spec, it is explicitly noted that for a
. case in which only one SDC train is available that it would be safer to initiate a loss of SDC transient from Mode 5 than from Mode 4.)
ERA. Bag lL In the PSA, if the plant is still using RCS loops for heat removal, then it is implicitly assumed that the plant will continue to remove decay heat via natural drculation if the RCPs are lost.
An explidt event is not modeled for a loss of AFW while in Mode 4 (it is assumed bounded by the loss of PCS initiator for Mode 1.) If the plant is operating on SDC, then loss of SDC is modeled, but a transition back to using the Steam Gerwrators and an RCP is conservabvely not modeled. In the PSA,
' Mode 4"is considered to be use of the RCS loops. Once the SDC is brought into operation, the PSA considers this to be ' Mode 5" operation, even though the RCS temperature might officially consider this to be Mode 4.
Situations to Consider:
Case 1: The plant is operating on one RCS loop, with one SDC train available (the other SDC train and the other RCS loop are inoperable), and the RCS loop becomes inoperable In the PSA, loss of the RCS loop would not consider a transition to SDC as a recovery action.
As noted above, if the reason for the loss of the RCS loop was failure of the RCP, then the PSA
- would show no risk impact, due to the availability of natural drculation cooling (boron dilution events are not considered to result in core damage). Loss of cooling water to the steam generator could be evaluated conservatively using the PCS initiator in the full power model.
Cagg;2: The plant is operating on one SDC train, with the other train available and the RCS loops inoperable, and one of the SDC trains becomes inoperable -
The risk of being in this situabon can be considered in the ' Mode 5' model. To consider the difference in risk between remaining in Mode 4 (with SDC) or being in Mode 5 would be based solely on the expected changes in initiating event frequences for loss of inventory, loss of SDC, etc.
conclusians:
b
i~
LCD 3.5.3 - ECt3 - Shutdown Ucanning Bass: HPSI is required as an RCS makeup source for LOCAs, SGTRs, MSLBs, etc. In Mode 4, LPSI would have been realigned to perform Shutdown Cooling functions. Only one train of HPSI is required in Mode 4, since the plant is in a lower decay heat condition and RG pressure is reduced significantly from normally operating pressure. Automatic initiation of ECCS will have been disabled, but adequate time is available for manual initiation of ECG if it is needed.
Raasons for Going to the End State: All trains of HPSI are inoperable for more than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> while in Mode 4.
PRA Basis: HPS! is modeled in the PRA for all operating modes. The PRA is conservative in that it does not consider the realignment of LPSI to perform ECCS injection.
Situations to Consider:
Both trains of HPSI are inoperable in Mode 4.
Evaluation Anoroach:
A comparative evaluation of the risks of operation in Mode 4 vs. Mode 5 with HPSI inoperable was performed.
Candissions: TBD 4
F LCO 3.5.4 - RWST Licensing Basis: Needed in Modes 1 through 4 to pnwide borated water source for ECCS injection.
Must meet volume, temperature, and boron concentration limits to comply with accident analysis assumptions. Note that RWST is not required for ECCS injection in Modes 5 and 6 per Technical Specifkations. However, a boration flow path (either from RWST.or BAMU) must be operable in Modes 5 and 6 per LCO 3.1.10.
Ransons & Going to the End Stata:.1) Temperature or boron concentration is not within limits and not corrected within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />; g 2) RWST is inoperable for other reasons (including low water volume) and not corrected within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
158.333ls; RWST is considered as injection source for HPSI, LPSI, and CVCS (the latter also considers RAMU) for all modes for LOCAs (Large, medium, small, and small-small), SGTR and other transients in which pressurizer safebes lift and fail to re dose. In the vast majority of cases, RWST *inoperability" wlR be the result of boron concentration, temperature, or volume not being with conservative design basis specifkations. Inoperability of this type wouki most likely not have any impact on plant safety, when best estimate conditions are considered. In the event that the RWST was truly unavailable, the loss of functionality would lead directly to core damage in cases in which ECCS injection is required.
RWST injection is also used during shutdown modes as a decay heat removal source under loss of shutdown cooling accidents.
Situations to Consider:
Chat.11 Temperature / Boron limits not corrected within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Water is stlH available for ECCS injection (likelihood of freezing RWST at SONGS is remote), so there would be no real change in CDF. Therefore, and state is probably irrelevant (i.e., there is no reason not to remain in the current mode). However, to ensure that the condition is corrected, we would probably need to propose transitioning to some lower mode (e.g., Mode
' 37)
Can2: Other RWST inoperability not corrected within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Since the RWST is not avaliable, there is an increased risk of core damage due any initiator i
occurring that requires ECCS. CDF increase would be driven directly by initiator frequency for LL, ML, SL, arxi SGTR. SSL CDF would also increase but would be moderated by the ability to still use CVCS and BAMU to provide makeup. The initiator frequency for all of the LOCA events would be less than 3.7e43 per year in Mode 4 and the SGTR frequency would be 1.0e-02, sesulting in a totalinitiating went frequency of concem of about 1.2e-02 per year. The loss of inventory initiating event for Mode 5 is 1.3e-03, which is slightjy higher than the Mode 4 frequency. But, in addition, the contribution of RWST unavailability to CDF due to loss of shutdown cooling will make Mode 5 a less safe end state than Mode 4.
Conchasions: This item IS a candidate for end state modificabon, as the risk results should be able to show a risk reduction due to the modification j
i
LCO 3.6.1-Containneent Ucanang Bass: Containment integrity is required to limit releases of radioactive materials to the environment. Design Basis Accidents of spedfic concem are LOCAs, MSLBs, and CEA Ejection acddents. Containment operability is defined as maintaining total leakage wthin spedfied limits. Note that these limits are based upon at-power LOCA conditions with design basis peak containment pressure.
Raasons for Going to the End State: Leakage (induding leakage from airlocks and isolation valves) avraark limits for greater that one hnur.
PRA Basis: Containment integrity is not explidtly modeled in the PRA. Containment" gross" integrity is implidtly assumed to be available to ensure adequate NPSH for ECCS pumps. In the Level 2 model, containment " leakage"is not consdered to contribute to Large Early Release. Were accidents to occur in Mode 4, resulting containment pressures would be significantly less than the DBA conditions.
Hence, leakage would be further reduced. While in Mode 4, the probability of LOCA and MSLB and LOCA is reduced from Mode l levels. CEA Ejection Acddents are not explidtly modeled in the PRA, but the probability of these events would also be significantly reduced.
Remaining in Mode 4 (vs. Mode 5) while the excess leakage condition is smded would maintain more mitigation systems available to respond to any event that could lead to a loss of RCS inventory or decay heat removal.
Situations to Consider.
Containment leakage is high during Mode 4. (It is assumed that gross failures of the containment would result in the plant proceeding to Mode 5 to effect repairs.)
Evaluation Anoroach:
An increase in containment leakage would not impact the cone damage frequency or LERF in either Mode 4 or 5. Since the overall CDF in Mode 4 is slightly less than that than in Mode 5
()00000( vs. YYYYYY), Mode 4 is an overall safer end state.
==
Conclusions:==
Modification of the end state of this Technical Speciution to Mode 4 should be acceptable.
7 l.
LCO 3.4.2-Containment Airlocks Licensing Basis: Containment integrity is required to limit releases of radmactive materials to the environment. Design Basis Accidents of spedfic concern are LOCAs, MSLBs, and CEA Ejechon accidents. Containment operstdlity is defined as maintainir.g total leakage wthin specified limits. Note that these limits are based upon at-power LOCA conditens with design basis peak containment pressure.
Raasons for Goino to the End State: Leakage (including leakage from airlocks and isolation valves)
)
exceeds limits for greater that one hour.
PRA Basis: Containment integrity is not explidtly modeled in the PRA. Containment" gross" integrity is implicitly assumed to be available to ensure adequate NPSH for ECCS pureps. In the Level 2 model, l
containment ' leakage is not considered to contribute to Large Early Release. Were accidents to occur in Mode 4, resulting containment pressures would be significantly less than the DBA conditions. -
Hence, leakage would be further reduced. While in Mode 4, the probability of LOCA and MSLB and LOCA is reduced from Mode l levels. CEA Ejection Acddents are not explidtly modeled in the PRA, but the probability of these events would also be signifkantly reducad.
Remaining in Mode 4 (vs. Mode 5) while the excess leakage condition is corrected would maintain f
more mitigation systems available to respond to any evert that could lead to a loss of RCS inventory or decay heat removal.
Situations to Consider:
Containment leakage is high during Mode 4. (It is assumed that gross failures of the i
containment would result in the plant proceeding to Mode 5 to effect repairs.)
Evaluation Anornadi:
An increase in containment leakage would not impact the core damage frequency or LERF in either Mode 4 or 5. Since the overall CDF in Mode 4 is slightly less than that than in Mode 5
()o0000( vs. YYYYYY), Mode 4 is an overall safer end state.
conduaians: Modification of the end state of this Technical SMT,cet;ce to Mode 4 should be acceptable.
LCO 3.6.3 - Containment Isolation Valves l
Licensino Basis: Containment integrity is required to limit releases of radioactive materials to the environment. The containment isolation valves form part of the leakage boundary. For systems that communicate with the contamment atmospfere, two redundant isolation valves are provided for each line that penetrates containment. For systems that do not communicate with the containment atmosphere, at least one isolation valve is provided for each line. Design Basis Accidents of specific concem are LOCAs, MSLBs, and CEA Ejection accidents.
Ransons for Going to the End State: 1) One valve in a two valve path inoperable, and that path is not isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; 2) Both valves in a two valve path inoperable, and that path is not isolated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />; 3) One valve in a one valve path is inoperable, and that path is not isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; 4) containment purge valves have leakage in excess of Tech Spec limits and the valves are not isolated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; 5) one or more ESFAS isolation valves inoperable, and that valve is not placed within its ESFS-actuated position within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or the valve (s) is not restored within the required time (within 30 days, or prior to the next Mode 4 entry from Mode 5).
IS&janis; Most containment isolabon valves are not modeled, with the exception of the containment purge valves, which are included in the Level 2 model. The majority of ESFAS valves are modeled (HPSI, LPSI, CS, CC); failure to be in the ESFAS-actuated state would mean that the ESF flow path would be unavailable. This is more of a Level 1 concem (failure to provide ESF flow) than a Level 2 concem for containment leakage. As most systems that penetrate containment do not directly
. communicate with the containment atmosphere, valve leakage or inoperability will not lead to a direct release path.
i Remaining in Mode 4 (vs. Mode 5) while the excess leakage condition is corrected would maintain more mitigation systems available to respond to any event that could lead to a loss of RCS inventory or decay heat removal.
Situations to Consider:
Mini-purge valve remains open while in Mode 4 to effect repairs. (This case should be limiting, from a Livel 2 standpoint.)
Evaluation Anoroach:
An increase in containment leakage would not impact the core damage frequency or LERF in either Mode 4 or 5. Since the overall CDF in Mode 4 is slightly less than that than in Mode 5
()00000( vs. YYYYYY), Mode 4 is an overall safer end state.
Conchaaione: Modification of the end state of this Technical SpedTGG,6 to Mode 4 should be acceptable.
1
r e
LCO 3.6.4 -Containment Pressure Licenang Basis: Containment pressure limits are based on design basis accident assumptions to ensure that post-accident pressure does not exceed design limits. In addition, a negative pressure limit is also estabbshed to protect the containment from under-pressure failure due to inadvertent CS actuation.
Reasons for Going to the End State: Containment pressure not within limits and not seisd d within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
PRA Basis: Initial containment pressure at the start of an event is not explicitly modeled In Mode 4, LOCAs, MSLBs, and other accidents would be much less severe. So, an accident in Mode 4, even with a small amount of containment cverpressure would not challenge the design limits of containment. In addition, containment design limits are conservative with respect to actual structural limits.
Per Tech Spec 3.6.6.2, CS is not required to be operable in Mode 4. While CS is not required to be disabled in Mode 4, the likelihood that one or both trains might be made inoperable at that time would further reduce the potential for an incident in which the containment would expenence too low pressure due to inadvertent actuation.
Situations to Considerft Pressure is not within limits during Mode 4 conditions Ev=!"mHem Anomach:
Since pressure variations would not haw a measurable impact on core damage frequency or large early release frequency, operabon in Mode 4 would not result in an increase in risk.
==
Conclusions:==
Modification of the end state of this Technical Specification to Mode 4 would be acceptable.
i t
i LCD 3.4.5 -Containment Temperature ucensing Basis: Containment temperature limts are based on design basis accident assumptions to ensure that post-accident temperatures do not exceed design limits.
Reasons for Goina to the End State: Containment temperature not within limits and not wreded within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
PRA Basis: Initial containment temperature at the start of an event is not explicitly modeled. In Mode 4, LOCAs, MSuis, and other accidents would be much less severe. So, an accident in Mode 4, even with a small amount of containment overtemperature would not challenge the design limits of containment. In addition, containment design limits ate conservative with respect to actual structural limits.
Situatens to Consider:
Pressure is not within limits during Mode 4 conditions Evaluation Anoroach:
Since temperature variations would not have a measurable impact on core damage frequency or large early release frequency, operaten in Mode 4 would not result in an increase in risk.
Conduaions: Modification of the end state of this Technical SMT % to Mode 4 would be acceptable.
1 k
LCO 3.6.6.2 - Containment Cooling - Mode 4 Licensing Basis: Containment cooling is required to remove heat from the containment following a design basis accident in this Mode. Two trains of containment cooling, considering the worst single failure, provide sumcient cooling to control containment pressure and temperature following an accident.
Note that Containment Spray is not required to be operable in Mode 4.
Raasons for Going to the End State: 1) One Containment Cooling train is inoperable in Mode 4 for more than 7 days; 2) Both Containment Cooling trains are inoperable in Mode 4 for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
PRA Bass: Containment Spray / Containment Cooling is considered in the Mode 4 PRA model based upon Mode 1 success criteria. Note that best estimate accident analyses show that only one-half of a single CC train (i.e., 25% cooling capacity) is sufficient to prevent containment failure /ECCS pump NPSH loss for a Mode 1 Large LOCA. Hence, the PRA success criterion of 25% cooling is conservative for Mode 4.
Situabons to Canader:
- 1) One CC train out in Mode 4 for an indefinite period; 2) Both trains of CC out in Mode 4 indefinitely.
Evaluation Anoroacht For the case of one CC train inoperable, a comparative evaluation of the risks of operabon in Mode 4 vs. Mode 5 was performed, assuming that containment spray was also not available.
For the case of both CC trains inoperable, it is probable that the containment could tolerate no containment cooling for some period of time. However, ultimately some form of heat removal would be required. Hence, either a transition to Mode 5 would be appropnate, or it will be necessary to rely on at least one train of CS to be operable.
Canciuminna: Modificabon of the end state of this Technical Spadfsten to Mode 4 would be acceptable for the case of one CC train operable. For the case of two trains inoperable, it must be required that at least one train of CS remain avaliable until at least one train of CC is restored.
i 4
4 LCO 3.7.4 - Atmospheric Dump Valves Licensino Basis: ADVs are used to prcMde a controlled cu.umri to SDC entry conditions following a design basis accident. One ADV is provided per Steam Generator. A combination of one operable ADV and one Steam Generator can cool the plant to SDC conditions with the avalleble CST supply. The Steam Bypass Control System can also be used to perform the ca.umri If the condenser is available (which also requires off-site power). ADVs can also be ' pened and closed manually locally if o
r w =esary.
Reasons for Going to the End State: 1) One ADV is inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; 2) Both ADVs are inoperable for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
PRA Basis: ADVs and the Steam Bypass Control System are considered in the PRA for only certain events. (The transition from Steam Generator cooling to Shutdown Cooling is not explidtly modeled.)
Remaining in Mode 4 ensures that a greater diversity of safety systems remains available to respond to all transients.
Situations to Consider:
- 1) One ADV inoperable in Mode 4 while on Steam Generator Cooling for an indefinite period.
- 2) Both ADVs inoperable in Mode 4 while on Steam Generator Cooling for an indefinite period.
Evaluation Acoroach:
For the case of one ADV inoperable, a comparative evaluation of the risks of operation in Mode 4 vs. Mode 5 was performed.
For the case of both ADVs inoperable, further evaluation is required.
==
Conclusions:==
Modification of the end state of this Technical Spedfication to Mode 4 would be acceptable for the case of one ADV operable. For the case of both ADVs inoperable, further evaluation is required.
LCO 3.7.4 - Auxiliary Feedwater Licensing Basis: AFW is required for steam generator heat removal when MFW is not available. In Modes 1,2, and 3, all three AFW pumps are required. In Mode 4, the turbine-driven AFW pump is unavailable due to low steam pressure, so both motor-driven pumps are required to ensure that at least one train is available, given a single failure. However, while Tech Spec 3.4.6 requires two AFW pumps in Mode 4, Tech Spec 3.7.4 states that only one pump is required.
Reasons for Golna to the End State: 1) One AFW pump inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; 2) One steam supply to the turbine-driven pump inoperable for more than 7 days; 3) Both motor-driven pumps inoperable in Modes 1, 2, or 3 for more than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />; 4) One motor-driven pump and the turbine-driven pump inoperable in Modes 1,2, and 3 for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
PRA Basis: AFW is modeled in the PRA for modes 1 through 4.
For cases in which both motor-driven pumps are available, remaining in Mode 4 should be a lower risk condition than continuing to Mode 5 because more diversity of heat removal and injechon sources remain available.
Situabons to Consider:
- 1) One motor-driven AFW pump inoperable in Mode 4 while on Steam Generator cooling for an indefinite period of time. 2) Both motor-driven AFW pumps available in Mode 4 while on Steam Generator cooling for an indefinite period of time.
Evaluation Aooroach:
For the case of both motor-driven AFW pumps operable, a comparative evaluation of the risks of operation in Mode 4 (on Steam Generator cooling) vs. Mode 5 was performed.
For the case of one motor-driven pump inoperable, the plant should proceed to Mode 5.
Condusions: Modification of the end state of this Technical Specfication to Mode 4 would be acceptable for the case in which both motor-driven pumps are operable. For the case when one motor driven pump is inoperable in Mode 4, Tech Spec 3.7.5 should be revised to require shutdown to Mode 5 so as to be consistent with Tech Spec 3.4.6.
Ucensina Basis: Provides water source for AFW to allow 24 nours of steaming time from plant 4
shutdown until entry to SDC. Backup water sources may be used as alternate supply (HFMUD tanks, Fire / service water, and Unit 1 Service Water reservoir).
i Rameans for Goina to the End Ctata: 1) CST is unavailable and unable to provide a backup water i
source within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />; et 2) the plant cannot get the CST restored within 7 days (while using backup water sources).
i PRAliasis: CST is required for AFW function. While use of T-120 is modeled, use of other backup sources is not modeled. PRA also credits continuatkNVrestart of MFW and emergency condensate feedwater from the hotwell if AFW is unavailable.
l Onen Items to Resolve: 1) Chn the backup water sources tie directly to AFW, or do they feed into the CST and then into the AFW system? 2) is the Unit 1 Service Water reservoir still available? 3) if MFW or emergency condensate feed is used in lieu of AFW/ CST, is there sufficient water in the hotwell to get to cold shutdown?
Cituatinns to Conciater; Case 1: No water source to replace CST function l
Given that all AFW would be unavailable due to loss of CST, it would be more awupi te to j
have a required action like LCO 3.7.5, Condition F (or Condition G, if in mode 4), which requires that you restore the CST or a backup source immediately (i.e., no mode change) l Cast 2: Backup water sources are available, but CST is not restored w".hin 7 days Since AFW function would still De operable, there would be no real change in CDF. Therefore, end state is probably irrelevant (i.e., there is no reason not to remain in the current mode).
However, to ensure that the condition is corrected, we would probably need to propose transitioning to some lower mode (e.g., Mode 37)
==
Conclusions:==
This item MAY BE a candidate for end state modification. Further evaluation is required.
4
LCD 3.7.7 -Component Cooling Water lJeansing Basis: At least one CCW train must be able to operate to remme decay heat loads following a design basis accident. CCW is also used to prwide heat remwel during normal operating and shutdown conditions-Two 100% trains of CCW are provided, wh;ch prwides adequate CCW flow assuming the worst single failure.
Ransons for Going to the End Stata: One CCW train inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> j
PRA Basis: CCW is modeled in the PRA for all modes.
When the plant is in Mode 5, CCW is required to support Shutdown Cooling. So, the one operable CCW train (in conditions in which the other train is inoperable) must continue to futxtion. Operation in Mode 4 with the Steam Generators available provides a decay heat removal path that is not dependent on CCW. While design basis accidents are less likely and less severe in Mode 5, more mitigating systems are available in Mode 4 to respond to an event.
Note that for the Technical Spedfication 3.0.3 and state, the cunent requirement to be in Mode 5 would be inappropriate, as no means of prcmding Shutdown Cooling would be available. Mode 4 (on SG Cooling) would be the safer end state for 3.0.3 for this system.
Situations to Consider:
- 1) One CCW train inoperable in Mode 4 while on Steam Generator cooling for an indefinite period of time. 2) Both CCW trains in Mode 4 while on Steam Generator cooling for an indefinite penod of time.
Evaluation Acoroach:
For the case of one CCW train operable, a comparative evaluebon of the risks of operation in Mode 4 (on Steam Generator cooling) vs. Mede 5 was performed For the case of both trains inoperable, the plant should remain in Mode 4 on SG Cooling, as no decay heat removal source exists in Mode 5.
Cancimalana: Mochfication of the end state of this Technical Specification to Mode 4 would be acceptable. The 3.0.3 end state for the condition in which both CCW trains are inoperable should be modified to be Mode 4 on SG Cooling.
T
LCO 3.7.7.1 - Component Cooling Water Safety-Related Makeup System Licensino Basis: The CCW Safety-related Makeup System is required to provide a source of makeup water to the CCW system in the event that the normal Nuclear Service Water System is unavailable.
CCW makeup is needed to compensate for system leakage so that a water-solid condition is maintained in the CCW system. The Safety-related Makeup System has redundancy, is protected from tomadoes and other hazards, and is designed to Seismic Category I requirements.
Rameans for Goina to the End State: 1) One makeup train inoperable for more than 7 days; 2) Both makeup trains (induding loss of the Plant Primary Makeup Tank) are inoperable for more than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
PRA Basis: CCW is modeled in the PRA for all modes. The Makeup system is not explidtfy modeled due to the diversity of CCW refill sources and the relatively long operator action times available to conduct refill operations. The Safety-related Makeup System would most likely be needed only under extended Loss of Off-site Power conditions, seismic events, and Severe Weather events.
~
If the Makeup System is not available, going to Mode 5 may have a higher overall risk than placing the plant in Mode 4, since Mode 5 is dependent on CCW for decay heat removal whereas Mode 4 can utilize the Steam Generators for heat removal. While the likelihood of LOCAs, SGTRs, and MSLBs is higher in Mode 4, the ability to rely on diverse sources of ECCS injection and decay heat removal would more than compensate for the higher initiator frequency.
==
Conclusions:==
Modification of the end state of this Technical Specification to Mode 4 would be acceptable.
i
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LCO 3.7.8-Saltwater Water ucansina Basis: At least one SWC train must be able to operate to remove decay heat loads following.
a design basis acddent. SWC is also used to provide heat removal during normal operating and shutdown conditions. Two 100% trains of SWC are provided, which provides adequate SWC flow assuming the worst single failure.
Ransons for Goina to the End State: One SWC train inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
EBAStas; SWC is modeled in the PRA for all modes.
When the plant is in Mode 5, SWC is required to support Shutdown Cooling. So, the one operable SWC train (in conditions in which the other train is inoperable) must amtinue to funcbon. Operation in Mode 4 with the Steam Generators available provides a decay heat removal path that is not dependent on SWC. While design basis accidents are less likely and less severe in Mode 5, more
)
mitigabng systems are available in Mode 4 to respond to an event.
Note that for the Technical Spedfication 3.0.3 end state, the current requirement to be in Mode 5 would be inappropriate, as no means of providing Shutdown Cooling would be available. Mode 4 (on SG Cooling) would he the safer end state for 3.0.3 for this system.
Situabons to Consider:
- 1) One SWC train inoperable in Mode 4 while on Steam Generator cooling for an indefinite period of time. 2) Both SWC trains in Mode 4 while on Steam Generator cooling for an indefinite penod of time.
l Evaluation Anoroach:
j For the case of one SWC train operable, a comparative evaluation of the risks of operabon in j
Mode 4 (on Steam Generator cooling) vs. Mode 5 was performed.
For the case of both trains inoperable, the plant should remain in Mode 4 on SG Cooling, as no decay heat removal source exists in Mode 5.
==
Conclusions:==
Modificabon of the end state of this Technical Specirc.6006 to Mode 4 would be acceptable. The 3.0.3 end state for the condition in which both SWC trains are inoperable should be modifled to be Mode 4 on SG Coolir.g.
l
' LCO 3.7.10 - Emergency Chilled Water System Licensing Basis: ECW provides coohng to safety-related HVAC units to provide cooling to equipment required to operate during/following a design basis accident. For most plant equipment, ECW is a backup to normal HVAC. For a subset of equipment, only ECW is available, but cooling is provided by l
both ECW trains.
Ransons for Going to the End State: One ECW train inoperable for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> PRA Basis: ECW and normal HVAC are modeled in the PRA for all modes.
Because normal HVAC would be available in all non-LOSP situations, cooling to most plant equipment would remain available. Should an event occur during Mode 4, the heat loads would be significantly reduced (allowing more time for manual recovery actions, including altemate ventilation measures.
However, this reduced heat load / increased recovery time is not credited in the PRA model.
Situations to Consider:
- 1) One ECW train inoperable in Mode 4 for an indefinite period of time.
Evaluation Anoroach:
A comparative evaluation of the risks of operation in Mode 4 vs. Mode 5 with one ECW train out of service was performed.
conclusions: Modification of the end state of this Technical Sg.c.Gv6 to Mode 4 should be acceptable.
e s
4 h
LCO 3111-CREACUS Limnsing Basis: CREACUS is used to filter incorning air to the control room and to provide positive pressurization to the control room during radiological Desgn Basis Accidents, which assumes a Maximum Hypothetical Accident (MHA) with source term releases as defined by TID-14844 (GDC-197).
These conditions are generally equhralent to a 30% core melt event with an intact containment. The design basis is to limit operator done to less than 5 rems over a 30 day post-accident period. The system is also used to isolate the control room in the event of a toxic gas release to minimize infiltration of toxic substances into the contml room.
Any event that releases radiation to the environment would challenge the CR environment. Without CREACUS the operator would be subject to radiological doses following all events that lead to core damage and many controlled events that do not lead to CD. Presumably, the limiting radiological accident of concem is a Large LOCA, but SGTR might need to be looked at as well.
Self-contained breathing apparatus is maintained for use by the operators in certain toxic gas release incidents. These devices could be used in the event of a radiological release during a period in which CREACUS was unavailable. Tw use of these descas is not credited as a backup measure to the CREACUS. These devices have a limited air supply, however replacement air bottles could be used to extend their operating lifetime for a period of about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Raasons for Going to the End State: One CREACUS train inoperable for more than 7 days PRA Basis: Control Room HVAC is not explicitly modeled in the PRA. The PRA assumes that the control room operators are capable of performing their duties until the time of core damage (for the Level 1 model). Some operator actions are also considered in the Level 2 model, but all of these actions occur before the time of core damage. It can probably be assumed that during a large early core damage incident, CREACUS would be inadequate to protect the control room operators once the release begins.
Situations to Consider:
- 1) One CREACUS train inoperable in Mode 4 for an indefinite period of time.
Evaluation Acornach:
To be determined conclusions: To be determined.
J l
/
k
LCO 3.8.1-AC Sources - Operating ucansina Basis: The idi,.;4.d AC buses provide the motive power for essenbally all Safety-related equipment. Normally, four sources of power are available (2 off-site sources and 2 emergency diesel generators). A graded set of completion times is specified in the Technical Specifications for situations in which one or two AC sources are inoperable. Inoperability of three or more AC sources invokes Technical Specification 3.0.3.
Ransons for Goina to the End State: 1) One source (Diesel Generator or offsite) inoperable for more than the allowed complebon time; 2) Two sources (Diesel Generator or offsite) inoperable for greater than the allowed completion time.
PRA Basis: AC Power is modeled for all AC equipment credited in the PRA for all modes. The PRA model takes credit for obtaining power from the opposite unit if one or more of its sources are available.
Mode 5 is a state that is totally dependent on AC Power. Mode 3 provides AC-independent heat removal (Turbine-driven AFW pump) for non-kCS-inventory-loss conditions. Mode 4 using Steam Generator heat removal does not have the turbine-driven AFW pump initially available. However, if all other AC heat removal sources were lost, the plant would heat up to a point at which the turbine-driven pump could then operate. While loss of inventory initiators are of higher frequency in Modes 3 and 4 (vs. Mode 5), the diversity of mitigabon equipment helps to compensate for this.
Under conditions in which 3 or more AC sources are inoperable, Technical Specification 3.0.3 drives the plant towards Mode 5. However, given that AC power is very degraded at this point, moving to an AC-dependent mode may not be the lowest risk strategy.
sauanons to consider:
- 1) One Diesel Generator inoperable in Mode 4 for an indefinite period of time. (This should be the limiting case for one AC source unavallaale.)
- 2) Two Diesel Generators inoperable in Mode 4 for an indefinite period of time. (Again, this i
should be the limiting case)
- ) Two Diesel Generators and one offste source inoperable in Mode 4 for an indefinite period 3
of time (the 3.0.3 condition)
Evaluation Anoroach:
A comparative evaluation of the risks of operation in Mode 3 vs. Mode 4 vs. Mode 5 for the conditions of one, two or three AC sources out of service was performed.
Conchasions: Modification of the end state of this Technical SpedT(4ksi to Mode 4 should be acceptable for conditions in which one or two AC sources are inoperable. For the 3.0.3 condition, Mode 4 should be the best end state for th's condition.
i I
i
LCO 3.8.4 - DC Sources - Operating Licensina Basis: DC power is used to provide control, instrumentabon, and motive power to various plant equipment in order to allow that equipment to properly respond to transients and Design Basis Events. All four DC buses provide instrumentation power. Buses D1 and D2 provide most control and motive power loads. Bus D3 provides motive power for one Shutdown Cooling System suction valve and power for portions of the turbine driven AFW pump train. Bus D4 provides motive power for the other SDC suction valve. (Design may be unique to SONGS; design-specific review in progress)
" - ' -s for Goina to the End ** 1) One DC battery / bus / charger inoperable for greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
PRA Basis: Buses D1, D2, and D3 are explicitly modeled. Instrumentation power is not rnodeled, because loss of a DC bus would cause the PPS channel powered by that bus to actuate to the trip (safe) position. Power to the SDC sucbon valves are not included in the full-power model because SDC was only considered in the full power PSA model only in the MSLB analysis as a point estimate.
Since instrumentation power and SDC suction valve power were not explicitly modeled, bus D4 is not modeled in the PRA.
Both Modes 4 and 5 are DC-dependent. However, more mitigation equipment is available in Mode 4.
However, initiating event frequencies for most accidents are also higher in Mode 4.
Situations to Consider:
- 1) DC Bus 01 or D2 inoperable in Mode 4 for an indefinite penod of time.
- 2) DC Bus D3 or D4 inoperable in Mode 4 for an indefinite period of time. (Bus D3 inoperability should be the limiting case).
Evalumbon Anoroach:
A comparative evaluation of the risks of operation in Mode 4 vs. Mode 5 with one DC bus out of service was performed.
Conduaians: Modification of the end state of this Tedinical Sps.ifn.d;06 to Mode 4 should be we=*=* for conditions in which bus D3 or D4 is inoperable. Evaluation of the case in which Bus 01 or D2 is inoperable is still under evaluation.
LCD 3.8.7 -Inverters - Operating Licensing Basis: All four inverters are required to provide battery-backed power to the vital instrument buses. These buses provide power for the Plant Protection System (PPS) and key plant instrumentation which would be used by the operators following an accident or transient. Given that design basis licensing requirements assume a coincidert LOSP with most accidents / transients, having an instrument bus not powered by its inverter would result in instrumentaten for that channel being lost, at least temporarily, following a design basis event.
Raasons for Goina to the End State: 1) One inverter inoperable for greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
PRA Basis: Loss of an instrument bus following a LOSP would fail the appropriate PPS channel, causing that channel to go to the safe (trip) position. So, instrumentation power loss to the PPS is not considered as a PPS failure mode in the PRA.' Instrumentation operation is implicitly considered in the Human Reliability Analyses of the PRA. Loss of one channel of instrumentation would have a small impact on human actions Both Modes 4 and 5 rely on instrumentation to provide the operators with information to control plant conditions.
Situations to Consider:
- 1) One inverter inoperable in Mode 4 for an indefinite pered of time.
Evaluation Anoroach:
For a loss of 1 inverter, the increase in core damage Frequency and Large Early Release Frequency would be negligibly small. Four channels of instrumentation are available under non-LOSP conditions. During a LOSP, one channel of this instrumentation would be lost for a short penod of time until the emergency diesel generator restored power to the safety-related AC bus. Even in the event of a station blackout, only one train ofinstrumentation would be affected.
Condusions: Modification of the end state of this Technical Sp dtn. Gen to Mode 4 would be acceptable for conditions in which one inverter is inoperable.
i 4
LCD 3.8 9 - Dietribution Systems - Opomting IJeansino Basis: The
_g,a AC, vital AC, and DC distribution systems are needed to provide motive, control, and instrumentation power to safety-related equipment throughout the plant.
Normally, there are 2 AC trains,4 DC trains, and 4 Vital AC trains. Loss of any one distribution system train disables multiple pieces of equipment in the plant.
ftmasons for Going to the End State: 1) One AC distribution system train inoperable for more than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />; 2) One Vital AC train inoperable for greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; 3) One DC distribution system train J
inoperable for more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
]
2B& Basis; AC Power is modeled for all AC equipment credited in the PRA for all modes. The PRA model takes credit for obtaining power from the opposite unit if one or more of its sources are
)
available. DC Buses D1, D2, and D3 are explicitly modeled Instrumentation power is not modeled, because loss of a DC bus would cause the PPS char *.nel powered by that bus to aduate to the trip (safe) position. Instrumentation operation is implicitly considered in the Human Reliability Analyses of the PRA. toss of one channel of instrumentabon would have a small impact on human actions.
Power to the SDC suction valves (which is provided by DC buses D3 and D4) are not included in the full-power model because SDC was only considered in the full power PSA model only in the MSLB analysis as a point estimate. Since instrumentation power and SDC suction valve power were not expiscitly modeled, bus D4 is not modeled in the PRA.
For the loss of an AC distribubon system, Mode 4 on Steam Generator cooling offers AC-independent
' decay heat removal options for non-loss of inventory events. However, initiator frequencies are higher in Mode 4 than in Mode 5.
Vital AC is required for all modes to provide instrumentation to the operators. But with four instrument channels, loss of one channel would have an insignifkant effect on Human Error Prahaham.c DC power is required for all modes. However, buses D3 and D4 do not power key loads in Mode 4 (other than instrumentation buses, described above). So, loss of either of these buses should have an insignifkant impact on the plant. l.oss of Buses D1 or D2 would result in control power loss to one train of safety-related mitigation systems.
Situations to Consider:
- 1) One AC distribubon system train inoperable in Mode 4 for an indefinite period of time.
(Bus 2A04 or 2A06 should be the limiting cases for one AC train unavailable.)
- 2) ' DC Bus D1 or D2 inoperable in Mode 4 for an indefinite period of time.
' 3) DC Bus 03 or D4 inoperable in Mode 4 for an indefinite period of time Evaluation Acornach:
A comparative evaluation of the risks of operabon in Mode 4 vs. Mode 5 for the conditions of one AC or DC distribution system out of service was performed. Loss of vital instrumentabon bus was not evaluated due to its insignificant impact on core damage frequency or large early release frequency.
Conduminns: [Later]
9
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CEOG lead plant will provide the risk insights to support change (LCO 3.0.3) to Don Hoffman by 6/7/99.
I Work Attached Tables reflecting which speci6 cations were evaluated from a PRA perspective and which specs are believed not to have LCO 3.0.3 issues. Writeups are provided for evaluated specs.
Tables 1 and 2 reflect the results of the review against the SONGS specs.
Future Actions i
Work with CE to incorporate their comments and information relative to other plants.
Fillin blanks ofrisk insights Confirm TS reviews do not identify additional specs for PRA evaluation Table Columns 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to evaluate condition ok?? This column reflects the results of" evaluation" by the PRA personnel ofwhether or not 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to evaluate the prudent course ofactions is ok from a risk i
perspective, considering the increase in risk from staying where you are at, the risk of shutting down and looking at what that difference is.- For each "yes" and "no" an explanation is provided l
-(by spec number).
Note, at least two of the explicit entry into LCO 3.0.3 specs will actually allow you to evaluate for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Single inop AOT This column reflects th'e current AOT for a single component inoperability.
I This was added to compare / consider when the continuation of the single AOT would drive you down anyways.
For those cases where you enter LCO 3.0.3 because of additional inoperabilities the single AOT can be looked at a couple of ways. If the additional inoperability occurs in a time frame close to the initial inoperability, the single AOT would act as a back stop. Thus, preventing continued i
operation for long periods of time with equip inop. For example: You have an LCO with a 7 day single inop AOT. One train goes inop. The second train goes inop on day 2. With the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to evaluate, the maximum that continued operation would be allowed would be an additional 5 days, because on the f day, the required action and completion time associated with the single AOT would drive you down.
On the flip side, if the additional inoperability occurred on day 6.5, the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> would not help yo_u because at the expiration of the f day, the required action and completion time associated with the single AOT would drive you down. (Potential LCO 3.0.2 conflict that is being evaluated and addressed)
Current End State This column simply reflects the current end state in the SONGS Specs. It L
t.MrnommnTEcE.mnenagg sosos.My1Jm?;4^ ~^
DRAFr PageN ENCLOSURE 3
was added to work in concert with the next column Proposed Eid Stat) to see if there was going to be a need to further revise LCO 3.0.3 relative ts its end st:12. (Keeping in mind that LCO 3.0.3 drives you out of the applicability of the spec.)
Plant specific? This column reflects our best guess as to whether the PRA arguments provided could apply to other plants or whether plant specific evaluations would be necessary, would be necessary.
t 1
i SONGS-JulL 1922My9d999 DRAFT 9
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Issue 6 (3.0.3 Actions and Timing)
Table 2 Review of LCOs for Potential 3.0.3 issues LCO 3.5.1 - SITS Condition to be Considered: Two or more SITS inoperable Licensine Basis for Tech Spec: SITS are used for post-LOCA core refill following a Large LOCA. The wcter from 3 SITS must reach the reactor vessel in order to limit peak clad temperature to below 2200_,
F. The LOCA analysis assumes concurrent LOSP and the worst single failure (failure of1 AC bus due to diesel failure). It is also assumed that the water from one SIT is lost through the break, since the worst break location is one of the cold legs.
PRA Considerations: SITS are credited only in the Large LOCA analysis. The success criteria used is two SITS delivered to the reactor vessel. The PRA is somewhat conservative in that it assumes that any Lcrge LOCA would occur in a cold leg (hence spilling one SIT's contents).
AOT extension activiti:s indicate that best estimate generic evaluations of the need for SITS during large LOCAs indicate ths4 injection of 2 SITS will be sufficient to control fuel temperatures. Analyses performed for W3 indicate that App K fuel temp. limits can be satisfied with the equivalent inventory of cb:ut 2 SITS. For that plant SIT level has been allowed to be much lower during normal operation than f:r the rest of CE PWRs.
Evaluation of 3.0.3 Extension Risk: The risk impact of extending the 3.0.3 time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> can be represented by the increased risk due to the possibility of a Large LOCA during the 24-hour period requested. A conservative case was considered in which all four SITS are unavailable. From the SONGS IPE, the Large LOCA frequency is 6.5e-5 per year, which translates into a conditional probability of a LOCA of 1.8e-07 during the 24-hour period. Since no SITS are assumed available, the additional core d: mage probability would equal the initiator probability (i.e.,1.8e-07 per year), which is an insignificant i: crease in the annual plant risk. Simitady for LERF, the conditionallikelihood of a large endy release due to the Large LOCA event is, from the SONGS IPE,2.99e-03. Hence the overall increase in LERP w:uld be 2.99e-03
- 1.8e-07 = 5.4e-10. This is an insignificant increase in the plant's annual large early release risk. Hence, the proposed extension of the 3.0.3 interval is acceptable.
==
Conclusions:==
Increasing the time available to take action under 3.0.3 would be acceptable for the cases in which two or more SITS are unavailable.
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Table 2 Review of LCOs for Potential 3.0.3 issues LCO 3.6.6.1 - C atainment Sprays / Coolers Conditions to be Considered: 1) Loss ofboth Containment Spray trah 2) Loss of one Spray train and loss of both Cooler trains Licensine Basis for Tech Soec: Both Spray and Coolers are used for containment pressure / temperature control following a Large LOCA or MSLB, assuming LOSP and worst single failure. (MSLB is actually the limiting accident for containment P/T control). Each train of sprays or coolers removes 50% of the postulated hee: load, so some combination of two CC/CS trains must function (i.e., loss of both CC and one CS train would guarantee inadequate heat removal given a Large LOCA or MSLB). CS also has the additional function of removing fission products from the post-LOCA atmosphere. So, loss of both trains would result in a guaranteed loss of all fission product scrubbing capability.
For plants with only two CS trains (no safety grade Fan Coolers) loss of both trains will also impact the ECCS recirculation function.
PRA Considerations: CS and CC are used in a number of event trees for long-term containment heat removal (Large LOCA, Medium LOCA, Small LOCA, Loss of DC, Loss of PCS, and Turbine Trip) if ECCS is actuated.
This heat removal is needed to ensure that ECCS recirculation mode can continue to effectively remove decay heat. MAAP analyses performed for the IPE, indicate that successful containment heat removal occurs when at least one CS train QI one CC fan cooler operate (i.e., only 25% heat removal capacity is needed). CS and CC are also considered in the Level 2 model. CS is also used as a backup injection / recirculation source for ECCS.
Evaluation of 3.0.3 Extension Risk:
Generic Evaluation for plants with diverse and redundant containment heat removal For loss of 2 CS trains, the complete PSA model was re-solved assuming that all containment spray was unavailable. The results show an annual CDF of 7.09e-05 (vs. 6.68e-05 for the normal case). Over a 24-hour period, this results in an increase in core damage probability of 1.le-09, which is acceptably low. With the CS system out, LERF shows an annual frequency of 5.58e-07 (vs. the normal result of 4.96e-07). Over a 24-hour period the increased large early release probability of 1.7e-10. Again, this is an acceptably small increase.
Fcr loss of 3 CS/CC trains, the complete PSA model was re-solved, assuming both CS trains and one CC train was unavailable. The annual CDF for this case was 1.77e-04, which results in a 24-hour increase in c:re damage probability of 3.0e-07. For LERF, the calculated frequency was 6.85e-07. This results in an i crease in the LERP over the 24-hour period of 5.2e-10. Both of these risk increases are acceptably small.
Additionally, the PSA model was solved assuming that ALL CS and CC trains were unavailable. In this case, the annual CDF increases to 3.73e-03 and the LERF increases to 1.13e-05. This equates to a 24-hour CDP increase of 1.0e-05 and a LERP increase of 3.0e-08. These increases are greater than the acceptance criteria. Hence the 3.0.3 restrictions for loss of all CS and CC should not be changed.
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Issue 6 (3.0.3 Actions and Timing)
Table 2 Review ofLCOs for Potential 3.0.3 issues Evaluation for plants with non-diverse CHR c
- [To be provided later]-
==
Conclusions:==
For plant configurations with diverse and redundant CHR systems, increasing the time available to take action under 3.0.3 would be acceptable for the cases in which both CS trains are unavailable or for cases in which both'CC trains and 1 CS train is unavailable. The current I hour limitation for all CC and CS trains unavailable should remain as is.
Question should the I hour be changed to 4 hrs to provide additional preparation time.? Should we change end state to Mode 47 -
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Table 2 -
Review ofLCOs for Potential 3.0.3 issues LCO 3.7.11 - Control Room HVAC Condition to be Consided Two CREACUS inoperable Licentina B==ie for Tech Soec: CREACUS is used to filter incoming air to the control room and to provide positive pressurization to the control room during radiological Design Basis Accidents which
- assumes a Maximum Hypothetical Accident (MHA) with source term releases as. defined by TID-14844 (GDC-197).
These conditions are generally equivalent to a 30% core melt event with an intact containment. The design basis is to limit operator dose to less than 5 rems over a 30 day post-accident period. The system is also used to isolate the control room in the event of a toxic gas release to minimize infiltration of toxic substances into the control room.
Any event that releases radiation to the environment would challenge the CR environment. Without
- CREACUS the operator would be subject to radiological doses following all events that lead to core damage and many controlled events that do not lead to CD. Presumably, the limiting radiological accident of concern is a Large LOCA, but SGTR might need to be looked at as well.
PRA Considerations: Control Room HVAC is not explicitly modeled in the PRA. To demonstrate the acceptability of continued operation without filtered protection to the control room we should show that the probability of a toxic ' gas or significant radiological release event is acceptable. In general, the frequency of a radiation release from the RCS is on the order of 0.01 per year (SGTR+LOCAs) potential for offsite toxic gas r: leases could increase the filtration risk. Of those events approximately [10%, guess] will pose a radiation or toxic gas hazard when the CR is unprotected. The probability of a CREACUS challenge over a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period is 0.01 x0.1x 1/365=3x10-6. This approach provides a harsher standard than core damage, and recovery actions are not considered (source isolation, protective gear oc ). However, I think we need to deal with the actual threat to the operating staff Onen items to Resolve: 1) is Large LOCA the limiting DBA for CREACUS? 2) are compensatory measures readily available to the operators (e.g., SCBA) if CREACUS dos not function?
' Anoroach for Evaluatina 3.0.3 Extension Risk: The risk impact of extending the 3.0.3 time to 24, hours can be represented by the increased risk due to the possibility of a Large LOCA (and possibly, SGTR, small LOCA, or other similar accidents) during the additional 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> requested. If compensatory measures are available, then credit could be given for the operators taking protective actions to enable them to continue to function post-accident. ; If compensatory actions are not available, then additional study would need to be performed.
' Conservatively assuming that all operator actions fail results in an unrealistically high CDF. Therefore, the actions would need to be reviewed to identify those that would be expected to be performed as the accident is progressing and releases are occurring.
- ConclusionsnTo Be Determined.
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Table 2 Review of LCOs for Potential 3.0.3 issues LCO 3.8.1 - AC Sources
- Conditions to be Considered: Three or more required AC Sources inoperable
. PRA Considerations: The Risk Associated with loss of Three or More AC Sources is unacceptably high.
==
Conclusions:==
Due to the magnitude of the increase with three or more AC sources unavailable, increasing the time available to take action under 3.0.3 would not be acceptable.
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Table 2 Review of LCOs for Potential 3.0.3 issues I
j LCO 3.1.9 - Boration Systems i
l Condition to be Considered: Both boration paths unavailable J
Licensina Basis for Tech Socc: The boration systems are required to ensure that adequate shutdown reactivity margin exists to bring the plant to Mode 5 with the worst CEA stuck out and the decay of all xenon poison. The systems are also intended to mitigate possible return to power scenarios following an MSLB. Per the Tech Specs, the two boration paths that are to remain available are 1) the RWST and its feed to the charging pumps, j
and 2) one or both BAMU tanks with their respective feed paths to the charging pumps.
j PRA Considerations: The CVCS injection functions are modeled only for small-small LOCA, SGTR, and ATWS. Both the BAMU and RWST sources are modeled. Because the PRA does not consider long-term shutdown to Mode 5 (only achieving a stable shutdown over a 24-hour period), modeling of the use of CVCS to bring the plant to Mode 5 is not considered.'Use of CVCS also is not considered for the MSLB event.
Open Items to Resolve: 1) if the RWST and BAMU sources are supposed to be independent and redundant borated water sources, why does the LCS requirements for BAMU volume and concentration vary based upon RWST concentration? 2) if both the RWST and B AMU borated water sources were unavailable, would the plant be able to shutdown and maintain adequate shutdown margin? 3) is a return to power following an MSLB likely under best estimate conditions? Or, if a temporary return to power occurs, would this result in core damage?
Evaluation of 3.0.3 Extension Risk: Ifit is assumed that the plant can shutdown with both sources unavailable, then the risk increase associated with extending the 3.0.3 allowed time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> would be based upon the risk increase resulting from small-small LOCAs, SGTRs, and ATWS during the additional 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> with CVCS unavailable, The PSA model was re-solved assuming that all CVCS boration paths were unavailable. The results show an annual CDF of 1.0e-04 (vs. 6.6Se-05 for the normal case). The risk increase is dominated by a turbine trip-induced ATWS. On a 24-hour basis, the increase in core damage probability is 1.02e-07, which is an acceptably small increase. For LERF, the annual frequency with CVCS boration unavailable is 1.25e-05 (vs. the J
base case of 4.96e-07). The increase in LERF is dominated by SGTR events with common cause failure of l
HPSI. On a 24-hour basis, the increase in large early release probability is 3.29e-08, which is again, acceptably i
small.-
Ifit is determined that the plant cannot safely shutdown with both boration paths unavailable, then the lowest risk j
strategy would probably be to remain in the current plant mode until at least one boration path can be made l
available.
==
Conclusions:==
Pending resolution of the open items, it appears that the proposed change to 3.0.3 is acceptable.
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Table 2 Review of LCOs for Potential 3.0.3 issues I
LCO 3.3.1 to 3.3.6 - RPS and ESFAS To Be Determined.
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i Issue 6 (3.0.3 Actions and Timing)
Table 2 Review of LCOs for Potential 3.0.3 issues LCO 3.4.9-Pressurizer Heaters Condition to be Considered: Two safety-related pressurizer heater groups inoperable
' Licensinn Basis for Tech Soect The Technical Specification requires both the existence of an adequately sized pressurizer steam bubble and two trains of safety-related pressurizer heaters (backed by connections to
. emergency AC Power) to mair tain pressure control. The heaters are used, in particular, to help maintain subcooling in the RCS loops during natural circulation cooldown conditions that would exist during a loss of offsite power event.
PRA Considerations:' The existence of a pressurizer steam bubble is implicitly assumed in the PRA. Pressurizer heaters are not modeled (both safety-related and non-safety-related heaters are normally available,'providing considerable redundancy).. The PRA assumes that natural circulation cooling can be maintained during LOSP and SBO conditions.
The Risk associated with loss of the two safety-related pressurizer heaters is minimal if analysis shows natural circulation can be maintained for an extended loss of offsite power without the heaters. However, the risk is
. probably unacceptably high if the heaters are needed for extended loss of offsite power.
Pzr Heater Operability is Mainly an Operational issue.
. Risk impact should be small. Risk contributions will arise from the following:
- 1. Potential increased PORV challenge
- 2. recovery from SGTR more complicated, increased potential for CD.
3 Entry into LTC complicated and extended (may need condensate tank refill)
Alternate strategies for depressurization and LTC entry need to be considered. Risk based on availability of equipment (PORVs) and strategies (condensate tank refill)
Ooen Items to Resolve: 1) if a LOSP occurred and the safety-related heaters were not available, how long would it be before RCS loop subcooling would be threatened?
Loop subcooling is not a risk issue. The plant will operate in a natural circulation mode and remove heat from the RCSi The RCS can lose up to 70% ofits inventory without resulting in core uncovery. Even ifinventory j
losses occur, the availability of SG inventory will promote reflux boiling and enable core coohng.
Anoroach for Ev.6 anna 3.0.3 Extension Risk: The risk impact of extending the 3.0.3 time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> can be represented by the increased risk due to the possibility of a Loss of Offsite Power during the additional 23 hour2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />
. period that would be of sufficient duration to cause a loss of natural circulation cooling. Note that this analysis would be conservative, as it would not consider the possibility of restoring at least one heater train prior to loss cf natural circulation, and it would assume that loss of natural circulation would leed to core damage (which might not be the. case).
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Table 2 Review of LCOs for Potential 3.0.3 issues
==
Conclusions:==
To Be Determined l
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Table 2 Review of LCOs for Potential 3.0.3 issues LCO 3.5.2 - LPSis Condition to be Considered: Both LPSI trains inoperable Licaneine Ba=is for Tech Soec: The LPSI pumps are used to provide reflooding of the core following a Large
' LOCA. They are not used for any other accident condition.
PRA Considerations: At least one train of LPSI is required to avert core damage in the Large LOCA event.
LPSI is also credited in the SGTR event as necessary for shutdown cooling following the late depressurization of the RCS to isolate the steam generators. The PRA assumes that core damage would occur if LPSI failed in that
. operation. Note that all SGTR sequences are assumed to result in a Large Early Release. However, this j
particular scenario would not result in core damage until at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> into the event.
Evaluation of 3 0.3 _ Extension Risk: The risk impact of extending the 3.0.3 time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> can 1,e represented by the increased risk due to the possibility of a Large LOCA or an SGTR during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. Since failure of LPSI is assumed to lead to core damage following a Large LOCA, the risk increase can be calculated from the initiating event frequency (6.5e-05 per year). For a 24-hour period the probability of a Large LOCA (and hence, core damage while LPSI was unavailable) would be 1.8e-07. For LERF, the conditional probability -
oflarge early release given a Large LOCA is 2.99e-03, therefore the increased probability of a large early release during this 24-hour period would be 1.8e-07
- 2.99e-03 = 5.4e-10.
For the SGTR event, the scenario involving failure of SDC is SGR*YDE*SDC (see attached event tree). If SDC is assumed to be failed, then the annual CDF resulting from this sequence would be 1.0e-02
- 1.0e-03 =
1.0e-05. This results in an increase in the core damage probability (and large early release probability, since it is conservatively assumed that all SGTR events lead to an early release) over the 24-hour period of 2.74e-08.
As the combined increase in core damage probability is 2.le-07 and the combined increase in large early release probability is 2.8e-08, this proposed change is acceptable.
If LPSis are not available, either is SDC (for the most part) thus operation in Mode I waiting for a LOCA is preferred to operating in an SDC mode (4 or 5). End state should be Mode 4 steaming.
HPSis and CS could backup LPSIs for SGTR events. Thus alternate strategies and recoveries could also be active.
==
Conclusions:==
Increasing the time available to take action under 3.0.3 would be acceptable for the cases in which both LPSI trains are unavailable.
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Table 2 Review ofLCOs for Potential 3.0.3 issues LCO 3.5.2 - HPSI and CVCS -
i-Conditions to be Considered: Both HPSI Trains or all CVCS Trains.
l TPRA Considerations: Loss of all HPSI or Loss of all CVCS pumps would result in an unacceptably high risk for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Risk for all HPSI would be approximately 4E-06/ day CDP and 2E-07/ day LERP. Failure of all CVCS would result in a plant transient / shutdown without CVCS makeup.
==
Conclusions:==
Increasing the time available to take action under 3.0.3 would be unacceptably high for either both HPSI trains or all of CVCS unavailable.-
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Table 2 -
Review of LCOs for Potential 3.0.3 issues LCO 3.7.2 - MSIVs l
Condition to be Considered: Both MSIVs inoperable r ic,onin, B..t for Tech Soec: The MSIVs are used to limit the mass and energy release into the containment for a MSLB inside containment. Mass and energy are limited by isolating the non-faulted steam generator from the fauh.- Worst case conditions, used for the licensing analysis, exist during hot zero power conditions (Mode 2).
l The MSIVs also help to mitigate potential return to power scenarios during MSLBs in which the highest worth CEA sticks out. They also assist in preventing uncontrolled cooldown and positive reactivity addition during steam line breaks in other locations. For SGTR, the MSIV can be used to isolate the faulted steam generator to minimize radioactive release.
PRA Considerations: Proper operation of the MSIVs appears to be implicitly assumed in the SGTR event (or success / failure of MSIV is irrelevant to core damage probability). For MSLB event, failure of the MSIV is assumed to proceed directly to core damage.
. Assumption is based on violation ofDB and not best estimate. A prior assessment concluded that best estimate MSLBs will not result in a core damage event. Issues include selection of DB assumptions (MTC, initial conditions, etc). This is an area for further comment.
Evaluation of 3 0.3 Extension Risk: The risk impact of extending the 3.0.3 time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> can be represented by the increased risk due to the possibility of a MSLB inside containment during the 24-hour period requested.
The frequency of the MSLB initiator in the PSA is 5.42e-04 per year. Over a 24-hour period, this would result in a core damage probability increase of 1.48e-06, which is above the acceptance criteria.
==
Conclusions:==
Due to the magnitude of the risk increase if both MSIVs are unavailable, increasing the time available to take action under 3.0.3 would NOT be acceptable.
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Issue 6 (3.0.3 Actions and Tuning) l Table 2 '
Review of LCOs for Potential 3.0.3 issues i
LCOs - 3.7.7 Component Cooling Water and 3.7.8, Salt Water Cooling l
Conditions to be Considered: Both Trains of CCW or SWC Inoperable PRA Considerations: Failure of all CCW or SWC would result in a plant transient / shutdown, that can lead to a core damage if the RCP seals are damaged. Additionally, loss ofHVAC cooling to all ECCS pump rooms, and other vital areas is lost.
==
Conclusions:==
Increasing the time available to take action under 3.0.3 would be unacceptably high for all of CCW or SWC unavailable.
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Troble 2 Review of LCOs for Potential 3.0.3 issues LCO 3.7.10 - Emergency Chilled Water L
Condition to be Considered: Both ECW trains inoperable. Issue may be plant / design specific. Work for non-i L
- SONGS design in progress Licensine Basis for Tech Spec: ECW is used to remove heat loads from various plant equipment post-DBA, particularly during the recirculation phase. For many loads, the non-safety normal Chilled Water system serves as a backup if offsite power is available. However, several loads (P018, CREACUS) are supported only by both tr:. ins of ECW. Since the licensing basis assumes LOSP at the time of the accident, the ECW system is needed to provide necessary cooling.
PRA Considerations: ECW is modeled, along with normal chilled water, as a support system for th'e various mitigation systems (including AC). The impact ofloss ofECW on CREACUS is not modeled.
Evaluation of 3 0.3 Extension Risk: The risk impact of extending the 3.0.3 time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> can be evaluated by determining the increased CDF resulting from operating the plant for the 24-hour period with both trains of ECW unavailable. The PSA model was re-solved under these conditions. The annual CDF increased to 1.07e-03 (vs. the base value of 6.68e-05) and the LERF increased to 7.18e-05 (vs. the base value of 4.96e-07). Over a 24-hour period, this would result in an increased core damage probability of 2.6e-06 and an increase large early release probability of 1.95e-07. As these values are above the acceptance criteria, this change is not acceptable.
==
Conclusions:==
Due to the magnitude of the risk increase if both ECW trains are unavailable, increasing the time available to take action under 3.0.3 would NOT be acceptable.
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Table 2 Review of LCOs for Potential 3.0.3 issues LCO 3.8.4 - DC Sources Operating
' Conditions to be Considered: 1) Two batteries or two chargers (or other associated cabling and equipment) inoperable, or 2) One battery in one train and one battery charger in another train inoperable Licensing Basis for Tech Soec: DC power is used to provide control, instrumentation, and motive power to various plant equipment in order to allow that equipment to properly respond to transients and Design Basis Events. All four DC buses provide instrumentation power. Buses D1 and D2 provide most control and motive power loads. Bus D3 provides motive power for one Shutdown Cooling System suction valve and power for ponions of the turbine-driven AFW pump train. Bus D4 provides motive power for the other SDC suction valve. (Design may be unique to SONGS; design specific review in progress)
PRA Considerations: Buses D1, D2, and D3 are explicitly modeled. Instrumentation power is not modeled, because loss of a DC bus would cause the PPS channel powered by that bus to actuate to the trip (safe) position.
Power to the SDC suction valves are not included in the full-power model because SDC was only considered in the full power PSA model only in the MSLB analysis as a point estimate. Since instrumentation power and SDC suction valve power were note explicitly modeled, bus D4 is not modeled in the PRA.
Evaluation of 3 0.3 Extension Risk: Because buses D1 and D2 provide critical control power to much of the plant systems, the unavailability of two of these buses would have a significant increase on risk. (A calculation of the loss of one bus shows a 24-hour core damage probability increase of 5.7e-06). So, it is not appropriate to extend the 3.0.3 action time for these buses. However, the limited set ofloads'on buses D3 and D4 make these buses candidates for the action time extension. To assess the risk impact of extending the 3.0.3 time to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for a simultaneous outage of buses D3 and D4, the PSA model was re-solved assuming that bus D3 was unavailable and that Shutdown Cooling could not be provided for the MSLB event. (This is a conservative assumption, as the SDC suction valves could be manually opened in the event of power loss). Using these assumptions, the annual CDF increased to 8.65e-05 (vs. the base value of 6.68e-05) and the LERF increased to 1.05e-05 (vs. the base value of 4.96e-07). Over a 24-hour period, this wou!d result in an increased core damage probability of 5.4e-08 and an increase large early release probability of 2.7e-08' Hence, the risk increase due to the unavailability of buses D3 and D4, under conservative assumptions, is acceptable.
==
Conclusions:==
Increasing the time available to take action under 3.0.3 would be acceptable for the cases in which both DC buses D3 and D4 are unavailable (The existence of this battery alignment may be paint specific) The existing 3.0.3 action time for buses D1 and D2 should remain at the current I hour value.
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SONGS -Iply 9J9?%Iy9d999 DRAFT Page 213
1 Issua 6 (3.0.3 Actions and Timing)
Table 2 l
Review ofLCOs for Potential 3.0.3 issues LCO 3.8.7 - Inverters - Operating Conditions to be Considered: Two or more inverters are inoperable Licensine Basis for Tech. Socc: later PRA considerations: Later
==
Conclusions:==
Later -
)
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l SONGS Julz.2J9?%Iy-974999 DRAFT Page }]3 P
LCO 3.8.9 - Distribxtica Systems - Operating l
l Conditions to be consideret Two AC distributions inoperable 1
PRA Considerations: The Risk associated with two AC Trains results in an unacceptably high risk over a 24 l
hour period.
==
Conclusions:==
Increasing the time available to take action under 3.0.3 would be unacceptably high for two trains of AC power unavailable.
SONGS - kly.9.119pJuly 9,-1999 DRAFT m
Page D 3
s.
Issue 3: Increased Flexibility in Mode Restraints: Risk Considerations - PWRs The Table below provides a general review of the Modes 2,3, and 4 (PWR) operations. Since most Technical fpecification LCOs are based upon steady state operation, the acceptable equivalent LCO fw a plant under transition may be different.
The Table summarizes the major differences between mode I and the transition modes, and provides a summary of the systems that may become more imponant or less important because of the transition.
The results of this review are:
- 1) AFW, the Diesel Generators, and support systems are more important in transition modes, and consideration should be given to not allowing entering a mode.if one of these are inoperable.
- 2) HPSI is less important in lower modes due to a lower LOCA frequency, but may also be more important when coming out of an outage. Further work is needed to see what the overall importance of HPSI is following an outage. Initial estimates are a lower CDF importance, but a higher LERF importance for HPSI.
- 3) Some systems which are less important in Modes 2-4 could be considered for AOT relaxation during these modes. This is not part of the scope of the Issue 3, but could be considered for future RI-TS enhancements.
Based upon a general review of the San Onofre PRA, relaxation of the 3.0.4 nsode restraints should be allowed, with the possible exceptions listed in items 1 and 2 above.
r Major differences between Mode 1 and Modes 2-4: PWR I
Mode Change From Mode 1 Systems More Systems Less Important Important J
2 ATWS may be less likely and is less ATWS response severe, making ATWS support systems systems, such as less important in Mode 2.
boration.
A loss ofFeedwater is more likely, AFW and AFW especially when first entering Mode 2.
support systems A primary safety lift is less likely on a Safety Injection and trip due to smaller pressure spike, support systems making an induced LOCA less likely.
3 ATWS is not possible. Return to ATWS response power is possible, but Highly Unlikely.
systems, such as Turbine Trip / Reactor Trip can not boration.
occur.
AFW is typically the primary supplier AFW and support i
of SG cooling, and ifMFW is turbine systems.
j driven, a loss of all feedwater is much more likely.
Loss of Offsite Poweris more likely Emergency Diesels due to the plant being down. However, and Turbine Driven the time available to respond to a loss AFW Pump of offsite power is greater. Overall, systems required to respond to a loss of offsite power, such as the DGs and the TD AFW Pump, are slightly more important.
4 Same as Mode 3 above AFW and support ATWS response systems. Emergency systems, such as Diesels and Turbine boration.
Driven AFW Pump LOCAs are less likely due to reduced High Pressure Safety RCS temperature. When RCS Injection.
pressures are lower, both LOCAs and SG Tube Ruptures are less likely Modes Following an outage, an RCS or SG High Pressure Safety 3 &4 Leak may be more likely due to Injection i
after maintenance activities in the outage, outage
RISK INFORMED TECHNICAL SPECIFICATIONS (RI-TS) TASK FORCE STRAWMAN ISSUES PHASEI ACTION PLAN 1.
ISSUE #I TECHNICAL SPECIFICATIONS ACTIONS END STATES A.
Short Description of The Proposed Change Define the appropriate end state for the Technical Specifications Actions B.
Reasons / Justification for The Proposed Change 1.
Benefit ofThe Proposed Change Plant safety and efficiency will be enhanced by not requiring plants to extend shutdowns to an end state not commensurate with the safety significance of the plant condition or level of degradation 2.
Level of Risk Information Required for The Proposed Change a.
For each end state option considered, a quantitative or qualitative evaluation of the risk associated with the following will be performed:
(1)
MODE transition to the proposed new end state with the failed component unavailable (2)
Component repair in the proposed new end state j
(3)
MODE transition return to power from the proposed new i
l end state 1
Rev. 4,6/21/99 i
ENCLOSURE 4 J
\\
3.
Justification Versus Need of The Proposed Change a.
A risk comparison between end state options will be perfonned considering the risk and economic benefits of the proposed new 4
end state C.
Actions and Schedule -
l 1.
Bryan Ford will provide the methodology for the BWROG qualitative
{
review and determination of the appropriate LCO end states to all OGs by 3/31/99
{
2.
Each Owners Group (OG) will perform a qualitative review of and develop a matrix repon of their respective affected LCOs and distribute I
their OG specific evaluations to the RI-TS Task Force by 6/15/99 3.
Each OG will review the other OG evaluation and matrix report and 4
provide comments by 7/5/99 4.
The RI-TS Task Force will resolve all comments (via telecon and email) -
by 7/8/99 5.
The RI-TS Task Force will provide the individual OGs qualitative assessments and matrix repon to the NRC by 7/14/99 6.
NRC and RI-TS Task Force will discuss the scope and methodology of the qualitative assessments and matrix report at the 7/14/99 meeting
)
2-Rev. 4,6/21/99 1
i
7.
Industry will develop detailed technicaljustifications and risk informed justifications (if necessary) by 11/1/99 and will provide a TSTF to NRC by 11/30/99 8.
NRC will review and approve by12/30/99 D.
Other CorrespondingInformation II.
ISSUE #2 MISSED SURVEILLANCE REQUIREMENTS (SRS) i A.
Short Description of The Proposed Change 1.
Extend the delay for declaring equipment inoperable and entering the Required Actions i
2.
Extend the time to perform a missed SR from the current 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to the specific Frequency of the Surveillance i
B.
Reasons / Justification for The Proposed Change i
1.
Benefit ofThe Proposed Change Plant safety and efficiency will be enhanced by providing a more reasonable time to perform the missed SR. This will in many cases i
preclude a change in the MODE or condition of the plant to perform the SR 2.
Level of Risk Information Required for Proposed Change a.
Assess the incremental risk of continuing to operate the plant I
without testing the affected component for several representative i
equipments or components. (This may include comparing the l
incremental risk of continuing to operate without testing the l
l.
3 Rev. 4,6/21/99 l
I affected component versus the risk of shutting down, testing the affected component in the shutdown state and restarting the plant) 3.
Justification Versus Need of Proposed Change a.
_ Perform a risk comparison between current Technical Specification requirements and the economics and risk of testing within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and/or remaining at power. This comparison consist of providing a qualitative discussion of the prudent use of plant resources and the advantage of scheduling activities to support plant operations and avoiding LERs. This change is adequately supported by plant specific Correction Action Programs (CAP) and the j
implementation of the Maintenance Rule.
C.
Actions and Schedule 1.
Donald Hoffman develop a draft of the proposed change and the technical justification by 5/11/99 and distribute to RI-TS Task Force i
2.
RI-TS Task Force will review and provide comments by 6/15/99 i
~ 3.
The RI-TS Task Force will resolve all comments (via telecon and email) by 7/8/99 4.
The RI-TS Task Force will provide the draft to the NRC by 7/14/99 5.
NRC and RI-TS Task Force will discuss the Missed SR draft at the 7/14/99 meeting l
i 1
4 Rev. 4,6/21/99
f 6.
Industry will develop detailed technicaljustifications and risk informed justifications (if necessary) by 10/1/99 and will provide a TSTF to NRC by 10/30/99 7.
NRC will review and approve by 17130/99 D.
Other Corresponding Information III.
ISSUE #3 INCREASE FLEXIBILITY IN MODE RESTRAINTS A.
Short Description of The Proposed Change Increase flexibility in MODE restraints by allowing MODE changes to be made while relying on ACTION statements to satisfy the requirements of the LCO for all LCOs. This flexibility would apply generically to all the LCOs, with any exceptions appropriately identified, instead of being allowed individual LCO by LCO based on the length or requirement of the Required Actbn and Cc'mpletion Time. The basis for this flexibility is an appropriate licensee management review and approval being performed for each MODE change while relying on ACTIONS to satisfy the requirements of the LCO B.
Reasons / Justification for The Proposed Change 1.
Benefit of The Proposed Change Improve plant safety and efficiency by allowing the licensee the flexibility l
of detennining the acceptability of the MODE change based on consideration of all of the plant conditions 5
Rev. 4,6/21/99
2.
Level of Risk Information Required for Proposed Change a.
Provide qualitativejustifications that demonstrate the risk of MODE changes with equipment inoperable or unavailable is equivalent to the risk of at-power operation with these equipment inoperable or unavailable. Consideration needs to be given to additional startup events. There is always the option to nel startup or change MODES with inoperable equipment and relying on l
ACTION Statements to satisfy the requirements of the LCO if the determination is made starting up or changing MODES is not the most appropriate course of action.
3.
Justification Versus Need of Proposed Change a.
Economic benefits plus justification oflow risk impact C.
Actions and Schedule 1.
Donald Hoffman will develop a draft of the proposed change and the technicaljustification by 5/11/99 and distribute to RI-TS Task Force 2.
RI-TS Task Force will review and provide comments by 6/15/99 3.
The RI-TS Task Force will resolve all comments (via telecon and email) by 7/8/99 4.
The RI-TS Task Force will provide the draft to the NRC by 7/14/99 5.
NRC and RI-TS Task Force will discuss the Flexibility in Mode Restraint draft at the 7/14/99 meeting 6
Rev. 4,6/21/99
o
)
6.
Industry will develop detailed technicaljustifications and risk informed justifications (if necessary) by 9/30/99 and will provide a TSTF to NRC by 10/30/99 -
7.
NRC will review and approve by 12/30/99 D.
Other Corresponding Information IV.
ISSUE #4 RISK INFORMED ALLOWED OUTAGE TIMES (AOTS)
A.
Short Description of The Proposed Change Develop extended AOTs based on engineering, technical and operational information and risk insights j
l B.
Reasons / Justification for The Proposed Change 1.
Benefit ofThe Proposed Change Enhance plant safety and efficiency by providing AOTs that are commensurate with the risk of the equipment inoperability 2.
Level ofRisk Information Required for Proposed Change i
a.
Risk information provided will meet the requirements of Regulatory Guides (RG) 1.174&1.177. Impact on CDF, LERF, ICCDP, and ICLERP will be provided. Plant specific vs generic will be determined on item-by-item basis b.
Develop CRMP requirements and determine AOT backstops consistent with RG 1.174 and 1.177 7
Rev. 4. 6/21/99
3.
Justification Versus Need of Proposed Change 1
l a.
The need will be developed from utility specific and generic infonnation regarding impact, frequency and consequence of problems created by the current AOT C.
Actions and Schedule 1.
The OGs will coordinate OG specific AOT extension submittals (specifically CEOG and WOG; there is currently no generic BWRdG or BWOG AOT extension effort) 2.
TSTF will continue to pursue individual generic AOT extensions in coordination with the OGs and the RI-TS Task Force with appropriate risk informed support as required 3.
The ultimate goalis to:
a.
In the short term develop a risk informed process for optimizing selected AOTs b.
In the longer term establishing backstop AOTs for all Technical Specification AOTs. This may be performed using the CRMP (1)
The schedule for this effort is late 2000 to mid 2001 D.-
Other Corresponding Information 8
Rev. 4,6/21/99
- n. -
V.
ISSUE #5 OPTIMIZE AND MOVE SRS A.
Short Description of The Proposed Change 1.
Relocate / delete SRs from the Technical Specifications that do not demonstrate safety function OPERABILITY i
2.
Relocate Surveillance Test Intervals (STIs) to a licensee controlled
_ program -
3.
Optimize the relocated STIs B.
Reasons / Justification for The Proposed Change 1.
Benefit ofThe Proposed Change Enhance plant safety and efficiency by: @ relocating or deleting SRs that do not demonstrate safety functions OPERABILITY @ relocating STIs to a licensee controlled program @ optimize relocated STIs based on risk insights of the STI commensurate with the risk importance safety function being tested 2.
Level of Risk Infonnation Required for Proposed Change a.
_ Risk infonnauon provided will be consistent with RI IST approach described in Reg Guide 1.175. Required risk information will be developed on a plant specific basis I
i 9
Rev. 4,6/21/99 2
3.
Justification Versus Need of Proposed Change Evaluate the potential impacts of requiring performance of SRs by a.
the Technical Specifications that do not demonstrate safety j
function OPERABILITY and evaluate the benefits of relocating and optimizing STIs j
C.
Actions and Schedule 1.
TSTF will pursue relocation of all SRs not related to the verification of safety function OPERABILITY in a TSTF to be submitted to NRC by 12/30/99 and NRC will review and approve this TSTF by 3/30/00 2.
TSTF will pursue relocation of all Surveillance Test Intervals (STIs) to a Licensee Controlled Program in a TSTF to be submitted to the NRC by
)
1/30/00 and NRC will review and approve this TSTF by 5/30/00 l
3.
The RI-TS Task Force will continue to pursue optimization of the j
i i
relocated STIs D.
Other Corresponding Information VI.
ISSUE #6 MODIFY LCO 3.0.3 ACTIONS AND TIMING A.
Short Description of The Proposed Change Extend the current time of I hour to initiate plant shutdown upon entry into LCO 3.0.3 commensurate with the level of degradation and associated plant conditions and reason for entering LCO 3.0.3 4
10 Rev. 4, 6/21/99
B.
Reasons / Justification for The Proposed Change l
1.
Benefit ofThe Proposed Change Enhance plant safety and efficiency by not requiring unnecessary plant shutdowns and by providing reasonable time to determine the appropriate l
course of action given the level of safety function degradation and associated plant conditions 2.
Level of Risk Information Required for Proposed Change a.
Develop the approach for assessing the risk associated with the situation leading to LCO 3.0.3. Develop the approach for assessing alternate actions, including continued plant operation.
Develop approach for evaluating incremental risk and assessing an acceptable time to restore OPERABILITY while at-power 3.
Justification Versus Need of Proposed Change a.
Economic benefits of eliminating plant shutdowns vs incremental risk of taking alternate action C.
Actions and Schedule i
1.
Donald Hoffman will enhance the technical presentation by 5/15/99 l
l 2.
CEOG Lead Plant will provide the risk insights to support this change to l
Donald Hoffman by 6/15/99 3.
Donald Hoffman will merge the technical and risk insights and provide the draft change to the RI-TS Task Force by 6/22/99
. 4.
The RI-TS Task Force will review and provide comments by 7/8/99 11 Rev. 4,6/21/99
l 5.
The RI-TS Task Force will provide a draft to the NRC by 7/14/99 6.
The NRC will discuss the initial acceptability at the 7/14/99 meeting 7.
The Industry will develop detailed technicaljustifications and risk informed justifications (if necessary) by 9/30/99 and will provide a TSTF to the NRC by 10/30/99 8.
The NRC will review and approve by 12/30/99 '
D.
Other Corresponding Information
)
VII.
NEW ISSUE #7 - DEFINE ACTIONS TO BE TAKEN WHEN EQUIPMENT IS NOT OPERABLE BUT IS STILL FUNCTIONAL A.
Short Description of The Proposed Change Provide appropriate actions for equipment that is not OPERABLE (inoperable) i but is still functional B.
Reasons / Justification for The Proposed Change 1.
Benefit of The Proposed Change Enhance plant safety and efficiency by ensuring appropriate compensatory actions are taken based on the actual level of degradation of the safety functions 12 Rev. 4. 6/21/99
2.
Level of Risk Information Required for Proposed Change l
No quantitative risk information required. Will need to determine a.
equipment functional requirements from risk /PRA modeling. For this application " Functional" is defined as capable of performing the intended function but possibly without all the pedigrees of EQ, seismic, etc. The scope of not OPERABLE but functional still needs to be developed 3.
Justification Versus Need of Proposed Change a.
Evaluate incremental risk by providing a qualitative discussion of having functional but not OPERABLE equipment for specified period of time to satisfy LCO requirements versus economic considerations of derating or shutting the plant down C.
Actions and Schedule l.
RI-TS Task Force will define appropriate actions for inoperable but functional equipment 2.
Intent is to not change the definition of OPERABILITY
'3.
Bryan Ford / Donald Hoffman will develop proposed change and provide to RI-TS Task Force by 6/16/99 4.
The RI-TS Task Force will review and provide comments by 7/8/99 5.
The RI-TS Task Force will provide a draft to NRC by 7/14/99 6.
NRC and RI-TS Task Force will discuss the draft change at the 7/14/99 meeting 13 Rev. 4,6/21/99
7.
The Industry will develop detailed technicaljustifications and risk infonned justifications (if necessary) by 11/30/99 and will provide a TSTF to the NRC by 12/30/99 8.
The NRC will review and approve by 4/30/00 D.
Other Corresponding Information VIII. GENERIC PROCESS ISSUES A.
The NRC and Industry will continue meeting routinely as necessary to maintain the progress desired by NRC and Industry B.
The RI-TS Task Force will attempt to generally follow a process of:
1.
Identify Issue 2.
Draft change 3.
Provide draft to NRC and get NRC acceptability review 4.
Develop TSTF and provide to NRC 5.
Support Timely NRC review and Approval C.
The dates for the Actions and Schedule for each of the issues is based on the assumption that there is a minimum level of quantitative assessment and input required. Each issue will have some level of risk insights applied. However, ifit
^
is discovered that a great deal of quantitative assessment is required, the dates may need to be changed accordingly.
l l
14 Rev. 4,6/21/99 l
[
t..
l D.
The RI-TS Task Force will identify for each issue their position of the level of risk information required for the proposed change. The NRC will be providing f
timely feedback on their position on the level of risk infonnation required for each l
issue and the RI-TS Task Force will integrate this feedback into their efforts.
l l
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l-l 15 Rev. 4,6/21/99 L-