ML20210K071
| ML20210K071 | |
| Person / Time | |
|---|---|
| Issue date: | 08/03/1999 |
| From: | Stephen Dembek NRC (Affiliation Not Assigned) |
| To: | Richards S NRC (Affiliation Not Assigned) |
| References | |
| PROJECT-692 NUDOCS 9908050214 | |
| Download: ML20210K071 (15) | |
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August 3, 1999 MEMORANDUM TO: Stuirt A. Richtrds, Dir::ctor Project Directorate IV & Decommissioning Division of Licensing Project Management Office of Nuclear Reactor Regulation FROM:
Stephen Dembek, Chief, Section 2 (Original signed by)
Project Directorate IV & Decommissioning Division of Licensing Project Management Office of Nuclear Reactor Regulation
SUBJECT:
MEETING WITH THE CE OWNERS GROUP ON TOPICAL REPORT CE NPSD-1041 The Nuclear Regulatory Commission (NRC) held a meeting with the CE Owners Group (CEOG) on July 13,1999, to discuss topical report CD NPSD-1041, " Joint Application for HPSI (High Pressure Safety injection] System Technical Specification Modifications." Specifically, CEOG was asked to discuss the NRC staff's comments and questions on the subject topical report.
The questions were previously faxed to the CEOG and are attached to this meeting summary (Attachment 1). A list of attendees is attached (Attachment 2).
The CEOG representatives began the meeting with a short discussion of the purpose of their topical report. Their report requeMs the extension of the HPSI allowed outage time to 7 days.
The intent is to perform low risk maintenance while the plant is operating. The plants will commit to using configuration risk management programs to ensure the risks associated with the online maintenance are acceptable. CEOG also discussed the HPSI configuration differences for the plants in the CEOG (Attachment 3). Additionally, CEOG stated that the portions of the topical report that discussed mode changes should not be reviewed at this time.
CEOG will be submitting a letter asking the NRC staff to no longer consider the mode change portion of the topical report. The CEOG's draft responses to the NRC staff's questions are attached (Attachment 4).
The effect on the review schedule of CEOG-requested changes was discussed and it was concluded that CEOG would request that the review schedule be extended.
Project No. 692 h3 Attachments: As stated e
cc w/att 1: See next page DISTRIBUTION:
Hard Cooy EMail Docket File SCollins/RZimmerman PUBLIC BSheron/WKane PDIV-2 R/F Nanette Gilles OGC WLyon
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ACRS MillardWohl
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9908050214 990003 WBeckner PDR TOPRP EMVC-E GTracey, EDO C
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OFFICE PDIV-2/SC PDIV-2 NAME SDembek:sdM EPM 6Y
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DATE 8/ 3 /99-8 / 3 /99 l
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1 August 3, 1999 MEMORANDUM TO: Stuart A. Richards, Director Project Directorate IV & Decommissioning Division of Licensing Project Management Office of Nuclear Reactor Regulation
/
FROM:
Stephen Dembek, Chief, Section 2
./
Project Directorate IV & Decommissl ni g l
Division of Licensing Project Management Office of Nuclear Reactor Regulation
SUBJECT:
MEETING WITH THE CE OWNERS GROUP ON TOPICAL REPORT CE NPSD-1041 The Nuclear Regulatory Commission (NRC) held a meeting with the CE Owners Group (CEOG) on July 13,1999, to discuss topical report CD NPSD-1041," Joint Application for HPSI (High Pressure Safety injection) System Technical Specification Modifications." A list of attendees is attached (Attachment 1). Specifically, CEOG was asked to discuss the NRC staff's comments and questions on the subject topical report. The questions were previously faxed to the CEOG and are attached to this meeting summary (Attachment 2).
The CEOG representatives began the meeting with a short discussion of the purpose of their topical report. Their report requests the extension of the HPSI allowed outage time to 7 days.
The intent is to perform low risk maintenance while the plant is operating. The plants will commit to using configuration risk management programs to ensure the risks associated with the online maintenance are acceptable. CEOG also discussed the HPSI configuration differences for the plants in the CEOG (Attachment 3). Additionally, CEOG stated that the portions of the topical report that discussed mode changes should not be reviewed at this time.
CEOG will be submitting a letter asking the NRC staff to no longer consider the mode change portion of the topical report. The CEOG's draft responses to the NRC staff's questions are attached (Attachment 4).
The effect on the review schedule of CEOG-requested changes was discussed and it was concluded that CEOG would request that the review schedule be extended.
Project No. 692 Attachments: As stated cc w/att 1: See next page
1 CE Owners Group cc w/att 1:
Mr. Charles B. Brinkman, Director Washington Operations ABB-Combustion Engineering, Inc.
12300 Twinbrook Parkway, Suite 330 Rockville, Maryland 20852 Mr. Gordon C. Bischoff, Project Director CE Owners Group ABB Combustion Engineering Nuclear Power M.S. 9615-1932 2000 Day Hill Road Post Office Box 500 Windsor, CT 06095 Mr. Ralph Phelps, Chairman CE Owners Group Omaha Public Power District P.O. Box 399 Ft. Calhoun, NE 68023-0399 1
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E NRC/CE OWNERS GROUP MEETING ON CE NPSD-1041 LIST OF ATTENDEES l
July 13,1999 l
l NAME
' ORGANIZATION l
Nanette Gilles Office of Nuclear Reactor Regulation (NRR)/ Technical Specifications Branch Stephen Dembek NRR/ Division of Licensing Project Management Warren Lyo NRR/ Division of Systems Safety and Analysis (DSSA)/ Reactor Systems Branch Millard Wohl NRR/DSSA/Probabilistic Safety Assessment Branch Ray Schneider ABB/CENP Alan Hackerott OPPD Jim Meyer Scientech, Inc.
j Homayoon Desfuli Scientech, Inc.
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' NRC Comments / Questions on CE NPSD-1041." Joint Anolication forliP_E System Technical Specification Modifications" to be discussed on 7/13/99 NRC/CEOG Meetina CE NPSD-1041-1.
Page 10 states "Many CE PWRs include three (3) HPSI pumps...." Two will meet licensing requirements. Why is an AOT relaxation necessary?
2.
Numerous qualifiers are provided in the writeup that weaken an argument that a generic approach is satisfactory. The above item 1 is an example. Page 14 provides another example when it states "... a work plan is typically developed for completing the '
associated maintenance within an acceptable period that is normally shorter than the duration of the AOT." (Emphasis added.) Please address the implications of such statements with respect to existing and to requested AOTs.
3.
Much of the justification on Page 16 appears to reflect weakness in spare parts availability and planning. Extending AOTs is not the correct solution, i
4.
Mean times to repair on Page 18 vary from plant-to-plant and information is provided for half of the plants. Page 32 et. al. shows a wide variation that underscores the plant specificity of this issue.
5.
The statement of need on Page 19 provides two examples. Are there more? If so, how many and of what types?
6.
The CRMP requires extemal event consideration, but Page 27 states "For consistency in comparison or (sic) results, Core Damage Frequencies (CDFs) presented represent
!ntemal events only." All contributors should be included or it should be shown that the omitted ones are not significant. Many of the CDFs presented on Page 32 et alillustrate this point since they are significant, but do not include potentially significant contributors.
7.
Page 27 states "In a PSA, the CDF is obtained using mean unavailabilities for all standby-svstem components." This is insufficient because the outliers could dominate.
At the le.st, such an assumption should be backed by sensitivity / uncertainty studies.
This problem is repeated on Page 30 in that mean downtime for corrective maintenance and preventative maintenance is used.
8.
Much of the AOT-allowed operation involves human involvement. There is no human error component to the described PRA work.
Some o the risk results are querstionable. For example, on Page 32 et al, the Palisades r
9.
4 mean downtime is shorter than most, but the increase in CDF is 10 / reactor year. This is not exactly acceptable, and CDF would likely increase if downtime were longer or more initiators were included.
10.
Page 43 references NUREG/CR-6144 plant operating states and results. These results were so distorted by initial assumptions that they were not usable and were ignored when the contractors went on to the Phase 2 part of the study.
ATTACHMENT 2
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11.
Page 43 states "The methodology for evaluating transition risk makes use of the existing full power PSA models with minimum changes beyond changing component failure rates and initiating event frequencies. This methodology calculates a transition risk that is realistic with respect to the known elements of transition risk and to the calculation of the risk of remaining at power." Aside from the previously identified limitations of the modeling, this modeling approach may not yield good transition results unless careful consideration is given to the unique aspects of transition problems. The discussion starting on Page 46 clearly establishes that this.vas not done. On the "plus" side, most of the error is a significant underprediction of transition CDF which leads to underprediction of the potential benefit of remaining at power.
,Qgacems related to the May 3 1999 CEOG letter:
1.
Page 6 states "It is conceivable that stcaming may be provided in Mode 5." The reactor coolant system temperature in Mode 5 is < 200 'F. How is steaming achieved when below 200 'F7 2.
Page 9 states " Entry into low temperature Mode 5 operation will invoke LTOP procedures... (which) increases the risk of a leak or LOCA... " (This " message"is repeated many times later, including attempted justifications for Mode 4 operation where LTOP is described as not needed.) LTOP procedures are entered prior to this.
3.
Page 9 states " Technical Specifications restrict removal of safety equipment in Mode 4.
These restraints are largely lifted upon entry into Mode 5. Thus Mode 4 provides a mechanism for greater operational control." This " message'is repeated. A licensee operating under a philosophy that the TS provide sufficient coverage for safe shutdown operation is not operating safely - and no one operates this way.
4.
Page 9 states " SIT (safety injection tank) operability is also required (in Mode 4)." SITS must be isolated from the reactor coolant system (RCS) before RCS pressure reaches SIT pressure. Some CE SITS are roughly at 600 psi; others around 200 psi. Obviously, SlT operability is not required when RCS pressure approaches or goes below SIT pressure. It cannot be " required"in Mode 4 since one often operates with RCS pressure below that of the SITS. (Note there may be a few exceptions when SlT pressure is reduced as RCS pressure is reduced.)
5.
Page 9 states " Entry into Mode 5 will result in potential unavailability of all ECCS injection capability...." CE licensees committed to providing ECCS injection capability in response to GL 68-17.
6.
Page 11 states "An important insight that has resulted from these (licensee) PSAs is that the incremental risk of core damage associated viith the inability to irnolement HLI (hot leg injection) is primarily due to an operator error or unavailability of nvcessary realignment valves, not unavailability of the HPS' pumps." These PSAs do not consider such failure modes as throttle valve erosion. Have such modes been addressed in CE plants and, if so, what were the findings?
7.
Page 11 states "Because HLI is proceduralized and sufficient time is available to perform this action..., unavailability of HLI for an otherwise successfully mitigated event is of low probability." How is HLI via HPSI pumps achieveo if the pumps are not available?
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Page 14 states "The operation of one HPSI and a SIT can maintain the Appendix K criteria during a design basis large LOCA scenario." Please explain how this result was obtained.
9.
Page 19 states "Thus, even with the increased AOT flexibility, the frequency of occurrence of longer duration HPSI system maintenance that would fully disable a HPSI train beyond that already allowed currently by the Technical Specifications, is smal!."
What is the rationale loading to this conclusion?
10.
Page 19 states "The Conditional CDP of the full 7 day AOT is sufficiently low (between 4 x 10 to 6 x 104...) so as to not present a significant risk to the public." 6 x 10 is not 4
suf6ciently iow especially when one considers the initiators that were omitted from the calculations.
11.
Page 20 states "As with the current technical specifications, Safety Margins are not affected by removing the HPSI from service." Please explain.
12.
Page 21 states "Since CE plants have relatively low pressure HPSI pumps, unavailability of HPSI rarely contributes to a high pressure core damage scenario (since for high pressure sequences HPSI flow could not be injected into the RCS)." CE plant j
HPSI pumps have shutoff heads ranging from 1200 to 2300 psig. The upper end is not a "relatively low pressure." How many high pressure sequences are avoided if HPSI is used before pressure exceeds the pump shutoff head?
13.
The large early release discussion starting on Page 54 contains a number of difficulties or potential difficulties, including:
a.
Containment bypass via ruptured steam generator tubes resulting from severe accident conditions do not appear adequately identified.
i b.
Page 55 states "HPSI piping failure due to exposure to the full RCS pressure is j
very low. Therefore, no change in the ISLOCA frequency is expected." In light of the Wolf Creek event, pipe breaks are not the concem. Mistakes and valve failures are. Discuss further.
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Page 55 states "...the ISLOCA will progress into early core damage regardless of HPSI availability." This fails to recognize the contribution HPSI can make to preventing core damage while actions are taken to mitigate the ISLOCA.
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d.
Page 55 states "Thus, the im. <.. of the unavailability of HPSI in responding to e i
SGTR event on core damage frequency is expected to be small." Provide J
further justification, e.
Page 55 states "Between 50 and 90% of the core damage sequences from CE PWRs are dominated by RCS transients that occur at high pressure." This has not been substantiated. (Extemal events? Shutdown operation?)
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Page 55 states "Thus, increased unavailability of the HPSI system... is expected to have a negligible to small impact on the large early release frequency (LERF) for CE PWRs with PORVs." HPSI is an important contributor to prevention of j
core damage, as is specifically stated on Pages 57 and 58. However, there is no discussion to address those plants without PORVs.
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Page 56 states "The fraction of the CDF due to HPSI pump unavailability leading l
to a high pressure core damage state is typically less than 20% for CE PWRs" l
This does not appear to be consistent with the Page 39 and 40 information and the related discussion.
h.
The Pages 57 and 58 discussion of compensatory measures is good, but there is no commitment that licensees will follow it. The maintenance rule will provide some of this, but the staff doesn't understand what ensure the remainder.
I 14.
The LOCA discussion of Page 60 completely misses the actual problems. It falls back on the historic picture of pipe rupture as opposed to the realistic valve and operator -
associated problems. This carries into the Pages 61 and 62 discussion, where a,
philosophy of not using LTOP is expanded. Such statements as "... the use of this end state... avoid the potential that other systems... will be deliberately or inadvertently placed in a degraded condition while repairs are being performed on the inoperable HPSI subtrains." Further, the quoted material appears to say that the risk-informed approach, the maintenance rule activities, and outage plans and implementation will be ineffective.
SUMMARY
1.
The calculated results, which omit potentially significant contributors, sometimes result in CDFs that exceed the guidelines.
2.
The material seems to contain numerous questionable and inaccurate statements, assumptions, and calculated results.
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Summary of HPSI Submittal /RAIS i
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ITEM FCS/WSES UNITS WITH 3 UNITS WITH 2 UNITS WITH 3 HPSIs gpgy3 gpggg
(" ASYMMETRIC
,' Spare swing,,
ALIGNEMNTS")
JUSTIFICATION OF e
Establish " backstop" so that MR can control Maint. Total unavailability NEED and CRMP controls configuration risk Perform low risk "on line" maint/surveillances and corrective e
maintenance with reduced potential for unnecessary shutdown Overall will enhance both plant economics and safety by not forcing e
plant shutdowns in the process of completing " low" risk maintenance.
Deterministic Issues e
DID no different for 3 day AOT or longer AOT Plant commitment to CRMP /MR enhances safety of lant maintenance e
Risk Issues
~
Risk Metric: Fully disabled 3 x 10-'
2.1 to 3.6x 104 1.5 to 2.73 x 10*
HPSI train SAOT Risk 6.2 x 10* (Pal)*
Full AOT Risk Based on Partially
<< 10-'
<10* (based on SCE)
< 104 (SL) disabled train: SI Valve
<4 x10 ' (PVNGS)
INOP: EXPECTED (approx)
MAINT. CONDITION Risk of Transition 2.510 ' to 1.4104
> 2 x 104 ICLERP
< 5 x 10* (est)
<10 " (SCE)
< 5 x 10-'(est)
Palisades [Later]
Conclusion Re: Risk e
Absolute "at-e Expected entry into Greater level of entry e
power" risk Low most adverse for HPSI maint than e
"At Power" Risk alternative low for plants with spare offset by projected duration HPSI. Duration of transition very low.
maint. Not expected
- AOT beneficial e
Absolute "at to exceed 3 days for even most power risk of most based on CEOG adverse (SAOT) adverse (SAOT) plant data.
erdry maintemmce small e Absolute risk of most to moderate adverse (SAOT)
- At Power Risk of maintenance small valve maintenance tomoderate negligible At power Risk of e
At power Risk valve maintenance e
significantly or negligible entirely offset by At power Risk e
transition significantly or alternative entirely offset by
- CRMP controls transition alternative CRMP controls entry entry to ensure maintenance to ensure activity is maintenance activity acceptable is acceptable e
MR controls total MR controls train train unavailability unavailability
- Increased risk based on I to 7 day change and greater worth HPSI ATTACHMENT 3
r.
Discussion Points for 713 Meeting PAGEI Discussion Points for Meeting l
t.
Question Summary Statement Comment / Response 1
Why request Relaxation?
The intent of the request is to allow low risk PM /
surveillance tests :o be conducted on the HPSI system on-line and to allow for potential corrective maintenance of the HPSI system in order to avert a plant shutdown and the risk associated with mode transition.
Tasks where HPSI system AOT extensions would benefit the utilityinclude:
MOV testing of HPSI header valves (individually)
Resolution of issues associated with degruled HPSI e
pump performance Risks associated with header maintenance are low (ICCDP of < 5x10-7, see for example below table) and increesing the AOT would allow the maintenance cycle (tag ou..
maintenance, and testing) to be conducted with limited risk of a plant shutdown.
ICCDP associated with a single HPSI Si valve maintenance (7 day-PM) for typical CE PWRs are as follows:
FCS/WSES
.... < 5 x 10 '
St. Lucie Units 1&2
< 104 (see RAI Response 8)
- < 10* (< 10'" ICLERP)
PVNGS Units
.. < 4 x 10-7 Actual valve PM times will be much shorter than the allowed outage time. Furthermore, maintenance activities that would remove a full HPSI train from service for more than several j
hours are remote (even for plants with two pumps). Any maintenance that would disable a HPSI train would be minimized via controls within the Maintenance Rule and more recently via the Oversight Process.
Most plants restrict maintenance durations to ensure a wide margin from the completion time to the AOT. For example plants with a 3 day AOT cannot nonnally plan unintenance to exceed 1.5 days. His general philosophy will continue.
Rerefore, HPSI maintenances greater than 3 days would be rare and generally not planned. De fact that most maintenances can be completed within this 3 day band can i
be seen from experience. The 7 day AOT provides the ficxibility for the plant to perform this maintenance without incurring the economic cost and added risk of arbitrarily forcing the plant through a mode transition to shutdown.
(Note that a review of maintenance records for a typical CE PWR indicated that no HPSI Out of Service Times that renders the HPSI train non-functional exceeded 62 hours7.175926e-4 days <br />0.0172 hours <br />1.025132e-4 weeks <br />2.3591e-5 months <br />).
i ATTACHMENT 4
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Discussion Points for 7-;.:.stecting PAGE2 Question Summary Statement Comment / Response 2
Qualifiers QualiDers are included, as above since not all maintenance activities are rigidly defined and rules vary somewhat throughout the industry and in unique circumstances exceptions will be made when all maintenance factors are considered.
For example a utility may plan a MOVAT test on a single valve when it has confidence it may be completed in 2 days instead of 1.5 days, provided suf6cient contingency is believed available to ensure that the AOT will not be violated. However, a difficult repair with a that will take 2.5 days may not be conducted.
In the sentence you quoted, a technical editor would have removed both word from the sentence, since utilities will not schedule a maintenance for times greater than the allowed AOT.
3 Spare Parts No. Isst:e is that following a repair acceptance tests may not at first be positive. This could require a re-test, or a readjustment to the repair followed by a retest. In instances valve repairs (including tagout and return) have taken nearly 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (more or less). It is these situations that we wish to avoid.
4 Plant Plant Variation When one removes the MY spare pump that they left id!c and unrepaired for nearly a year, the data is remarkedly consistent. The repair data on page 19 shows all repairs have been performed in less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
5-Examples Other ex:.mples of MOV maintenance taking longer than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> exist within the industry. These are the two examples associated with the CE fleet.
6 CRMP CRMP includes qualitative or quanti?ative consideration of external events. These considerations include pragmatic actions to minimize fire risk, control flood and fire barriers, etc.
Removal of a HPSI train from service will adversely affect the risk of operation both at-power and during transition.
The relative impact of the external events should be small since these events will affect both trains equally. That is seismic events that fail one HPSI would fail both. The CRMP would invoke contingency actions to ensure that asymmetric events would be minimized by ensuring flood barriers and fire barriers and equipment are in place to protect the second component, or ensure that alternative equipment to meet the function of the component under repair is available.
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7 Uncertainties Table 6.3.2 5 shows a comparison of the CDFs for a ll l
Discussion Points for 7-13 Meeting PAGE 3 Question Summary Statement Commert/ Response representative plant with the existing and extended AOT.
Note that the point and mean CDF estimates are differ by <
10% and that the relative shift of these parameters for the j
point estimate and the mean are the same.
From a different persepetive the cross comparison of all the plants shows the CCDFs for all plants with one HPSI in l
service (except Palisades) is hetween 0.998 E-4 to 2.4 E-4.
This is a selatively narrow range given the variability of the plants and differences among large numbers of parameters.
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Palisades has a higher CCDF since the plant used a higher L
end SBLOCA IEF and has a unique PORV capacity which is strongly credited for OTCC. This increases the worth of the HPSI w.r.t other rfants. (see HPSI RAI Response 8 )
8 Human Error No specific human error contribution was defined for the on line mairtenance other than that associated with the equipment FTS and ITR which is based on industry / plant data. HPSI maintenance does not generally involve realignments of the system. Typically maintenance will be on the SI header valves. Maintenance on the pump will 4
require isolating the pump. HPSI piping is high pressure piping and is not subject to overpressurization failures.
l One area where human errors may be of greater concern is l
associated with realignment of components as modes are l
changed. Installation of LTOP and entry into SDC co.ild be sources of alignment concerns or inventory losses. Greater risks in this action further supports minimizing unnecessary j
mode changes.
9-Palisades Results nflect uniqueness of Palisades. Palisades high capacity s'ORV increases importance of OTCC as a core cooling trede. Also conservative assumption in the Palisades SBLOCA IEF resulted in a greater LOCA threat.
Net impact is a more valuable HPSI train. This was j
discussed in the report and the followup response.
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If the Palisades PORV were downsized, the HPSI OOS risk iI would be in hne with the other plants on a daily basis. Also l
j note the Palisades AOT used in the analysis was only one l
day compared to 3 for the other plants. 'Dris also contributes to the differences in the accumulated risk. Increase. On the same basis, the risk increase from a 3 day AOT would be 4 x 10-6.
1 Note that the risk estimates assumes HPSI train maintenance
[
disables the full train. Maintenance is mostly expected on I
header valves and therefore would result in risk levels more than an order of magnitude lower. See SCE CIV submittal and Response to RAI question 8.
Palisades has updated their PSA in the past 3,ye_ars. Updated l
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3 Discussion Points for 7-13 Meeting PAGE4 Question Summary Statement Comment / Response tesults will be presented at the time of subrnittal.
10 NUREG/CR-6144 Understood l
11 Transition Risk Too Low This is the only attempt at formally modeling transition risk _
I in the industry. Transition risk is limited to the transition from Mode 1 to Mode 4 on SG heat removal and above LTOP entry.. These transition risk assessments did consider operator actions and procedures. However, additional issues that have emerged over the past several years and are generally associated with SDC operation have not been integrated into the risk. Inadvertent diversion paths etc.
These factors would increase risk of transition,. It was the intent to demonstrt te that the transition risk was significant and of the same order as maint. Risk. Increasing the risk estimates would tend to further support the position presented in the report. 'Ihe current estimate was to provide a balanced transition risk assessment.
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L, Discussion Points for 7-13 M:eting PAGE5 l
Response to RAI Questions on May 3 Ixtter Question #
Summary Statement Comment / Response Items 1-5 Mode Change ne gist of these arguments is to note that Mode 4 on SG heat removal has a lower level of risk due to redundancy and diversity of heat removal mechanisms.
Also there S little difference between Mode 4 and Mode 5 on SDC.
Dese issues are being considered globally as part of a RI TS initiative and should be subsumed into that much more comprehensive effort.
De end state request, for which these arguments were put forth, is no longer being sought as part of this topical.
6 and 7 HLI The issue being addressed is that HLI will r.ot change the worth of the HPSIs since the HPSI are required even if HLI is not implemented. Therefore cutsets with no HL1 & no HPSI would be subsummed into cutsets for No HPSI.
8 Success criteria statement See Paper: " Role of MAAP in NRC Requested Analyses",
Ellison, P.G., Ward, L.W., Allison, C.M.. (Table 2 handout)
ZION Analyses with RELAP 5 9
Unavailability HPSI repair times reported (with exception of MY spare) were less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Few entries beyond 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> have occurred for MOVs in ECCS trains. Maintenance rule will control unavailabilities to ensure risk significant systems will not increase.
10 Risks Risks are relative. Should the full AOT be required for repair (which is not anticipated), and should the maximum INOP be in effect (which is less likely) and should the entry to a high risk state occur often (which would be prevented by several programs including the Oversight Program and MR),
adding the seismic and fire CDFs would give a higher CDF.
However, all these risks would be the same or greater as the plant enters a transition.
He risk values presented are metrics in that the state is a possible but not necessarily an expected condition. He expected use of this AOT is discussed in the same question, the actual ri ks per maintenance associated with a header valve would only be 1 x 10-8. SCE has estimated this risk at even a lower value (See SCE CIV submittal, see also response to item 1). Thus a maximum possible risk of the full use of the AOT under the worst set of conditions, rarely entered would be acceptable even for the most adverse plant.
Also note that if Palisades did not purchase large capacity PORVs, its risk of removing the HPSI from service would be much lower. But it's overall risk of plant operation would go up noticably.
1I SAFETY MARGINS What is meant is that on a daily basis there is no more risk in taking a HPSI train OOS in the current TS or with the proposed TS. The same level of DID is retained. The longer AOT accumulates greater solely because of its longer time.
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Discussion Points for 713 Meeting PAGE 6 Question #
Summary Statement Comment / Response 12 HPSI Shutoff heads No currently operating CE plant has a HPSI shutoff head greater than 2000 psia. All but the PVNGS units have pressure in the range of 1500 psia or below. HP scenarios are generally generated by loss of AFW w/o early depressurization of the RCS or SBO which drive the RCS pressure to the PSV setpoint. HPSI availability provides no benefit for these scenarios.
13 15 F Note LERF is only considered for AT POWER conditions Delta LERC estimates are provided ir. Response to RAI i 1.
SGTRs LERF estimates performed by plants indicate increme,ntal LERFs to be between 10-8 and 5 x 10-7 See RAI response i1. High end estimates are dominated by SG1Rs.
Estimates based on a disabled non-functional HPSI train.
HPSI valve alignment HPSI valve alignments would not divert flow from RCS while plant is at power.
HPME HPME scenarios, which dominated IPE risk are now believed to be incredible events when analyzed further (see Ref 1 ) In essence this is no longer a significant contributor to LERF, Reference 1 NUREG/CR-6475. " Resolution of the Direct Containment Heating Issue for Combustion Engineering Plants and Bat; cock & Wilcox Plants", M.M.
Pilch, et. al., Sandia National L.aboratory, November,1998.
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