ML20154H187
| ML20154H187 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 03/30/1988 |
| From: | Erickson D SANDIA NATIONAL LABORATORIES |
| To: | |
| Shared Package | |
| ML20154G997 | List: |
| References | |
| NUDOCS 8805250257 | |
| Download: ML20154H187 (19) | |
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- ,- Nkkoe.Ywn.d. [E$) j FINAL DRAFT FINAL DRAFT l l
I SUPPLEMENTAL ANALYSES l and COMMEr4TS/ RESPONSES TO EPRI/WOG ANALYSIS of DECAY HEAT REMOVAL RISK AT POINT BEACH
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i David M. Ericson, Jr. i ERC International <
Albuquerque,New Mexico l
For Sandia National Laboratories !
Albuquerque, New Mexico :
March 30, 1988 i
l l
t FINAL DRAFT !
FINAL DRAFT SUEk7ECT TO REVISION '
Do Not Distribute Without Prior Approval of Author :
8805230257 8 426 i PDR ADOCK O 266 '
o PDR i
CONTENTS
- 1. Dominant Accident Sequences 1 1.1 Internal Events 1 1.1.1 Small Break LOCAs 1 1.1.2 Loss of Offsite Power 6 1.1.3 Loss of Feedwater Transient 7 1.1.4 Other Transient Sequences 9 1.1.5 Long Term Station Blackout 11 1.1.6 Revised Estimates of Core Melt Frequency Internal Events 13 1.2 External Events 13 1.2.1 Seismic 13 1.2.2 Fire 17 1.2.3 Internal Flood (Spray) 21 1.2.4 Revised Estimates of Core Melt Frequency External Events 22 1.3 Other Significant Issues 22
- 2. Specific Topics For Review 24 2.1 Extended Internal Flood Analysic 24 2.1.1 NSAC-113 Approach 24 2.1.2 Case Study Approach 26 2.1.3 Summary 27 2.2 Cost (Impact) Analysis 28 2.2.1 General Comments 28 2.2.2 Specific Comments 32 2.2.3 Summary 34 i
References 35 l
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SUPPLEMENTAL ANALYSES AND COMMENTS / RESPONSES TO EPRI/WOG ANALYSIS OF DECAY HEA1 REMOVAL RISK AT POINT BEACH The EPRI/WOG analysis of decay heat removal (DHR) risk at Point Beach (NSAC-113)1 is essentially a rework, or "annotated review," of the NRC-sponsored Sandia case study (NUREG/
CR-4458)2 Because the range of issues raised by the EPRI/WOG re-analysis is rather broad, this response report is in two parts. In Part 1, the dominant accident sequences are used as a basis for reviewing the issues, highlighting areas of agreement /
disagreerient , and assembling comments. In Part 2, more detailed analyses and discussion of several specific topics are included.
Whenever possible, summary lists of questions or discussion topics are included. Thus, this document provides a vehicle for subsequent technical exchanges with EPRI/WOG.
- 1. DOMINANT ACCIDENT SEQUENCES l
1.1 Internal Events The dominant internal event sequences are shown on Table 1 (Table 8.3, EPRI/WOG). The sequences are discussed in groups, rather than singly, beginning with the small break LOCAs.
1.1.1 Small Break LOCAs l
For the small break LOCA sequences, S 2MH1'H2 S 2 MD 1D2' and S MXD 2 1 the differences are: the small break LOCA f re-quency; CCW success critoria; and operator actions.
Initiatino Event Frecuency: A recalculation of the S 2 sequence frequencies using the EPRI/WOG initiating event frequency of 3E-3, with no other chances, leads to an estinate of core melt frequency for these three sequences of 8.45 6/rx-yr or a
I l TABLE 1 l t
comparison of Core Melt Frequency Estimates !
?
Secuence ERC Case Study EPRI/WOG Study ~ Kev Reasons l Core Melt Frecuency Per Reactor-Year !
S2MH12 H 4.7E-5 5.8E-7 SBLOCA Freq. I CCW Suc Crit.
Operator Action !
I T iMLE 6.7E-6 7.7E-7 New Batteries ,
T 3QH H12 2.5E-5 N/A Rel Valve LOCA ;
cannot occur i T 2MQH H12 3.5E-6 1.9E-7 Rel Valve Prob l Operator Action S 2 MD 12 D 8.7E-6 9.5E-8 SBLOCA Freq. l CCW Suc Crit l T 3QD D12 4.6E-6 N/A Rel Valve LOCA f cannot occur
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! T 2MLE 6.6E-7 1.0E-7 MFW Recovery ;
l Alt to 1 PCRV i T 2MQD D12 6.6E-7 4.1E-8 Rel Valve LOCA CCW Suc Crit S2MXD 1 5.7E-7 1.0E-8 SBLOCA Freq. I CCW Suc Crit T5MLE 9.1E-7 1.3E-8 DC Bus X-conn !
l MFW Recovery I I
T 4MLE 6.2E-7 N/A Loss of AC Bus does not trip !
l T 2MbN 1 2.0E-3 1.0E-7 Operator Action f
MFW Recovery :
}
T 1QD 012 <1.0E-8 1.2E-7 Rel Valve LOCA j more likely l
LTSB 3.6E-6 5.4E-7 i
1.34E-4 2.56E-6 i l
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_3_
reduction of 4.76E-5/rx- fr from the S.61E-5/rx-yr reported in the SNL study. The total reduction reported by EPRI/WOG is 5.45E-5/rx-yr. Therefore, the revised S 2 frequency alone l accounts for 86% of the difference between the NRC/SNL values and the EPRI/WOG values. SNL used a value of 2E-2/yr for the S2 frequency because all breaks between 0.38" and 1.66" were included. This is consistent with several other PRAs, e.g., the Sequoyah analysis for NUREG-11503 However, that study notes that their S 2 includes the very small LOCAs (S3 insome nomenclatures with diameter <0.5"). Thus, the Sequoyah analysis would support an S 2 frequency on the order of IE-3/yr for equivalent diameters >0.5" and <2". The Surry analysis for l NUREG-1150 4 used 1E-3/yr for the S 2 frequency. Based upon the rationale presented by "PRI/WOG and that in the Oconee 5
PRA , the proposed value of 3E-3/yr appears reasonable. This "acceptance" is also predicated, in part, upon the argument that recirculation is not required for very small LOCAs because of the extended time required to exhaust the RWST inventory at low flow rates. A plant specific analysis of flow rates and timing would be beneficial. It is also presumed that containment suppression is not required during the early injection phase of an S 2 LOCA, (an argument also made in the Sequoyah and Surry analyses) which i will further extend the length of time that the RWST inventory is 1 available for injection. The SNL study was intended to consider steam generator tube ruptures (SGTR) as an initiating event as noted in the Analysis Plan 6. However, it was not explicitly treated as an initiating event in the case studies. There was an l
implicit assumption that a single tube (or even two tube) rupture would be "covered" by the S 2 frequency. If EPRI/WOG were to consider SGTR events, then the combined frequency would be on the I order of 1E-2/yr based upon the 8.6E-3/yr for SGTR suggested in the Oconee PRA, although other PRAs have suggested SGTR frequencies on the order of 2E-2/yr. It is noted however, that
the sequences which could lead to core damage given an SGTR, !
i.e., SGTR followed by failure of HPI or AFW, and failure of a SG-SV to close after being demanded to open, are minor contributors to the estimate of core melt frequency.
In summary, for Point Beach, the EPRI/WOG proposed value for S2 frequency appears reasonable. It would also seem reasonable to consider S 2 frequencies on this order for other PWR analyses, j nevertheless, it is recommended that any such use be supported by updated small LOCA data reviews which explicitly consider the question of seal LOCAs and SGTRs. Additional analytical support ,
for the assumption that recirculation will not be required would be helpful.
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Suecort System Dependencies: The EPRI/WOG study also asserts I that CCW is not required for the HPI pumps in the injection mode J because CCW provides seal rather than bearing cooling. The study also claims that removing the requirement for CCW to support HPI l reduced cora damage frequency by about 3.6E-5/rx-yr for related j sequences (p 3-21 NSAC-113). Since the injection failures only )
appear in five of the dominant sequences in the SNL study, two l S2 and three T, the sum of which is less than 1.5E-5/rx-yr, it is not obvious how the claimed reduction comes about. As noted above, the majority of the reduction for the S2 sequences comes j from reduction in S 2 frequency, while the CCW dependency only contributes about 3-10% of the reduction, depending upon the particular sequences examined.
In summary, there are several issues which need to be addressed: 1
- 1) What specific sequences were affected by the revision in ;
the analysis?
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- 2) What is the technical basis for removing the CCW dependency other than the statement, "A review by WEP found that I
CCW is not required for HPI operation in the injection mode since CCW provides seal rather than bearing cooling?" Other PRAs, !
e.g., Surry and Sequoyah have noted that CCW is required for seal cooling and luba oil cooling and have required successful seal j cooling as a prerequisite for HPI success. Such criteria should l be retained unless there is unequivocal evidence that cooling is i l
not required.
.t Operator Actions: The final area which EPRI/WOG credits for (
significant reduction in core melt frequency is operator action, particularly in the case of the S 2, the failure to switchover from injection to recirculation. SNL used the generic value of 1E-3/ demand
- while EPRI/WOG used 1E-4/ demand, based on the assertion (p 4-10 NSAC-113) that, "there would be many people i watching and verifying its implementation." Given that there have been "many people" in a number of plant control rooms during critical incidents and that mistakes were still made, the EPRI/WOG rationale, as stated, seems weak. It is also noted that the Oconee and Sequoyah PRAs use values in the 1E-3/ demand range, although they do show variation with the time available to make f
the switchover. The SNL/NRC review of the Indian Point PRA7 describes analyses which can produce failure rates from less than i 1E-4 to greater than 1E-3. It would appear that 1E-3/ demand is a reasonable value to use when a detailed HRA is not available, i.e., a generic study. However, lower values may be substantiated with some modest amount of analysis, so long as it
- Although Table B.2, p B-26, NUREG/CR"4458 shows HPRF-MANACT as 3E-3/ demand, it will be noted from the actual analysis, Table B.22, p B-81, that the only term used is SUMP-VCC-OE at 1E-3/ demand.
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is more substantive than that offered by NSAC-113. (It may be anticipated that HRA and associated human failure rates will ;
r j continue to be an area of some contention and disagreement l l because of the lack of "hard data" and the often subjective [
nature of the analysis. In the author's opinion, the general approach of the EPRI/WOG study is to adopt the most favorable (optimistic) HRA values whenever possible, often without !
adequate substantiation.)
1.1.2 Loss of Offsite Power ;
2 i
4 For the loss of of fsite power (LOSP) transients T1 MLE and j
TtQD D12 the key differences are: LOSP f requency, new j batteries, and relief valve LOCA probability.
4 Initiatina Event Frecuency: The use of a site specific ,
j frequency for LOSP rather than the national average is a reasonable approach 11 the objective of a study is to get the 7
best estimate for a particular site. Given that the goal in l I the case studies was to gain some insights on a more generic I basis the industry average was a better value to use. In this [
] instance the difference is nominal, 0.062 versus 0.084 per l year, which accounts for only about 27% of the redue. ion in i 4 the Ti sequences or 8% of the overall reduction in core melt !
j frequency due to internal events.
l i Suecort System Decendencies: In some respects, the new
) station battery, added to back-up the the normal station j batteries, makes the plant analyzed by EPRI/ Wor a different ,
] plant than that analyzed by SNL. (If these batteries were
- installed in 1985, it is difficult to understand why SNL l wasn't made aware of them during the various plant visits and
! interactions, particularly since this new set is intended to 1
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5 provide back-up DC power for diesel starting and vital plant instrumentation.) It is not easy to quantify the contribution l y
these new batteries would make without reanalysis of the EPS i with these batteries included. Thc information provided in l Appendix B of the EPRI/WOG study indicates, for instance, that for one sequence involving battery common-mode failures and manual operation of the turbine driven auxiliary feedwater i
system, the core melt frequency decreases by more than an order of magnitude when the new batteries are considered. t
! Unfortunately, the listing provides no information as to the I values selected Or the other terms and thus we are unable to reproduce the results. Based upon comments in Section 5 (page 5-4, NSAC-113) it does appear that EPRI/WOG treated the new battery as a "recovery" action although that is not explicitly
] spelled out. Given that the third battery now exists, it f
. would be appropriate to include its use in any analysis. l The EPRI/WOG report indicates that the sequence T QD 1 1D2 will "appear" because there is an increased liklihood of a j relief valve LOCA. In this sequenco AFW succeeds, however in l Appendix B of NSAC-113 all the sequences listed for T i (
involve T iM-Q and some sort of AFW failure. Therefore, we !
are unable to comment on the validity of their observation. ;
1.1.3 Loss of Feedwater Transients
\l j l l j For the loss of feedwater (LOFW) transients T MOH 1 'H2',
2 T 2 MLE, T2 MQD D1 2 and 2 T MLHy the key differences are: relief l valve LOCA probability, operator actions, main feedwater recovery, alternatives to 1 PORV, and CCW success criteria.
i Felief Valve LOCA Probabililty: The EPRI/WOG study does j assume that PORVs will open for LOSP, LOFW and loss of AC or ,
DC bus, but they argue that if thermal-hydraulic calculations '
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(no reference) show that reactor and turbine trips will not .
result in PORV openings. 8 A H survey of PORV and SRV events indicated that there were no failures of PORVs in some 163 operational openings and no SRV operational openings, '
therefore no failures. If there are PORV openings, then it is not expected that the SRVs receive any challenge. But this represents a different base case than that analyzed by SNL in which the PORV block valves were presumed to be closed *,
therefore, a potential for challenge to the SRVs exists.
Although, in these sequences in which AFW succeeds the likli-hood of such a challenge is presumed to be small. Some westinghouse analyses, apparently unpublished , suggest that 9
SRV set points would not be' reached. However, information was ,
available to SNL which suggested that PORVs and SRVs might open inadvertently even when they were not demanded, the 0.07 value. Based upon NUREG/CR-272810 it was then assumed that ,
the probability that once opened the valve didn't close is 0.01, so since both valves have to reclose to prevent a small LOCA, the value is 0.02, and the T MQ 2 product becomes 1.4E-3. If one accepts the argument that the 0.07 value is conservative for SRVs, other studies 11 still suggest that SRVs may be demanded about 1% of the time even with AFW available. On this latter basis, the T MQ product becomes 2 l 2E-4 and the t
result for T MQH1'H2'and 2 T QMD 2 Dy 2 would be a factor of l seven lower or 5E-7 and 9.4E-8 per reactor-year, respectively.
In contrast, the EPRI/WOG study assumes that the PORVs are generally unblocked, but accounts for the possibility that j l
l This conservative approach was taken based upon our impres- l sions from conversations with the plant staff suggesting that block valves were "of ten closed" due to leaking PORVs.
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they may be blocked some fraction of the time. Again, this is !
a different situation than that analyzed by SNL. However, tho l
approach suggested by EPRI/WOG seems reasonable, providing !
that adequate data on block valve status is available, the l main area for discussion then being the value selected for i operator action; where they use lE-3/ demand, SNL would use l 3E-3/ demand. Using the latter value would yield a T 2 QM ;
multiplier of 2.7E-4, comparable to the revised approach i discussed above. Therefore, it is agreed that in a plant specific study the probability of relief valve LOCA could be ;
lower than initially suggested by SNL. !
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It is not clear from the EPRI/WOG discussion how their main feedwater recovery differs from that employed by SNL, i.e., a l
non-recovery in 60 minutes of 0.1. In fact, they seem to be {
consistent given the comment made on sequences T MLE 2 and j T 2 MLH i , although for T 2MLH 1 it appears that they used l a larger value for non-recovery (about 0.6) and then took l l
credit for added operator actions. I 4
Finally, we have been unable to ascertain from the information presented precisely how the alternative to 1 PORV is implemented / quantified. It is understood that additional venting to containment is assumed (DC operated vent valves).
As noted above, the bases for the CCW success criteria need to be more fully explained, although it is also noted that this does not have a major effect upon the results, the principal impact comes from the reduction in the event Q value.
1.1.4 Other Transient Sequences l
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For the remaining transients, T 3QH 1 'H 2, T QD3 D1 2, T 4MLE, l and T2 MLF the EPRI/WOG report argues either that they do not, l
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l or cannot, occur or that they are significantly reduced by the !
availability of DC cross-connects and main feedwater recovery.
Miscellaneous T ySecuences: For the sequences T QH1'H2' 3
and T 3QD 12 D the argument is made (as noted above) that in some 163 openings of PORVs at H plants no failures of PORVs have <
been reported and that no operational openings of SRVs have occured. It is stated that H thermal-hydraulic calculations show that reactor and turbine trips will not result in PORV opening..
It is assumed that this is a reference to unpublished calculations 9, since no reference is cited. Unfortunately, this seems to be a situation in which the position is taken, if l it hasn't happened, and analysis says it won't happen, then it won't happen. While PRAs are built upon experience to the maximum extent possible, it does not appear reasonable to reject a possible sequence simply because it has not yet occured. As noted above, the SNL analysis of inadvertent openings may be more conservative than necessary and the actual contribution may be considerably less, but the EPRI/WOG study does not provide sufficient evidence to conclude that these two sequences "cannot ,
occur."
Loss of DC Bus: For sequence TS MLE, recovery of main feedwater and DC bus cross-connects are cited as reasons for change. The SNL study had already accounted for main feedwater recovery (NUREG/CR-4458, Appendix B, Section 6.3, page B-ll5). The !
existence of cross-connects is recognized, in fact they are shown j on Figure A.8, page A-23 of the case Study. It seems that the discussion of the cross-connection recovery (page A-9, NSAC-ll3) is approximately an order of magnitude "off" from the way we would read the references cited. The case study would yield a p(NR) outside the control room of 0.3 in 10-20 minutes, while the NUREG/CR-1278 12 data cited (Table A-3, page A-8) would support 0.01 at 20 ninutes. Thus, while the concept of DC recovery by I
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l cross-connection appears reasonable, the details of the ,
i application will have to be better understood before a firm 1
recommendation can be made. For sequence T 4 MLE, the EPRI/WOG study simply states that an evaluation by WEP indicates that the ;
loss of an AC bus will not cause a plant trip. Without addi- l tional detail it is impossible to comment on the acceptability of this statement. It would appear that a more reasonable argument
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would be improved recovery such as was argued for the DO bus, i although the probabilities need to be examined.
, i 1.1.5 Long Term Station Blackout
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Initiatina Event Frecuencv: Although the factors causing the i differences between the EPRI/WOG study and the SNL results are '
not as explicitly spelled out for the long term station blackout as for the other sequences, tney are relatively easy to !
1 identify. They are: reduction in T 1 frequency, reduction in DG l j failure rate, and recovery via long term cooling. As noted l earlier in the discussion of LOSP induced transients, the use of I
"bonafide" site data in a site specific study is acceptable; here the site specific T 1 frequency is about 78% of the national l
. average. I 1
)
j Succort System Decendencies: The EPRI/WOG value for DG failure i
rate is based upon more recent complyations of data. If independent assessment of NSAC-108 13 indicates that the data is valid then there would be no problem using the newer data. It
] should be noted that the SNL value, 3.8E-2, included two components; a 1.9E-2 failure to start and a 1.9E-2 failure to run i eight hours. Although it is not so stated in the EPRI/WOG
! analysis, based upon prior conversations with the NSAC staff, it is presumed that the 2.2E-2 is a combined failure to start and 1
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-. . _ .. . -. . - . _ ~ . . .. . _ .
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j l i run for Eng hour. On this basis the NSAC-113 value is consistent l, with the data used by SNL, the difference being the required run time. It is understood that industry would argue for the shorter .
run time based upon the probability of the recovery of offuite !
power. SNL chose the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time to be consistent with the !
i approach then being taken for the resloution of USI A-44, Station l Blackout. Applying the revised T1 frequency and DG failure rate to the SNL estimates produceu the values shown in Table 8-4 of l NSAC-113 under the column labeled Total Frequency of Blackout Not Causing Early Core Damage. The exception seems to be that for the entry DG-CM, USAC-113 ;,nly reflects the reduced T1 frequency. If one were to use the DG-CM valuer cited in Table 5-2, page 5-11, this value would be 2.26E-6/rx-yr. However, it is believed that the value cited for DG-CM is quite optimistic for two train systems. The study by Hirschberg and Pulkinnen 14 would support l l
values in the 10'3 range. Using the SNL approach (NUREG/CR-4458, i Appendix B, page B-34) with the NSAC-113 value for DG-LF yields a DG-CM of 8.8E-4 per demand. Incorporating this value into the study would reduce the EPRI/WOG estimate of LTSB to 9.94E-6/rx-yr.
The EPRI/WOG study, as we understand it, argues that the new batteries allow the operators to continue to run the AFW system during station blackout. Although we will accept the premise, it is not clear how it will be accomplished. The analysis of NSAC-113 appears very optimistic about how easy it will be to accomplish certain tasks during actual blackout conditions. (See also comments to the Advisory Committee on Reactor Safeguards by ACRS Consultant P. Davis.15] A similar situation exists here using diesel driven fire pumps to refill the CST. Although there is reasonable time to accomplish the refilling, it is not clear that this has been demonstrated with the plant actually blacked out. It is stated that p(NR) for 20 minutes would seem appropriate and tnat the unavailability of pumps and hoses would dominate the failure
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, probability so that an overall probability of 0.03 was "deemed reasonable." It is impossible to adequately comment without more j j detail on the rationale behind these statements. Therefore, it i is recommended that the estimate of core melt which only accounts 4 l for the site specific LOSP frequency and the revised DG-LF probabilities and not long-term cooling be retained pending a j better explanation by EPRI/WOG of their long term cooling 1 analysis. This yields a value of 9.9E-6/rx-yr for the LTSB ,
contribution. !
i 1.1.6 Revised Estimate of Core Melt Frequency - Internal Events !
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Based upon the preceeding arguments and discussions a "revised" summary of the core melt frequency estimate is shown on Table 2. I l 1.2 QLteIpal Events J
)
The special emergency (external events) with which EPRI/WOG ,
i j disagreed are shown in Table 3. NSAC-113 states that the risk i related to external events, flood, high wind and lightning are
- each below 1E-8/rx-yr because of conservatisms in the SNL l analysis and because "WEP has strengthened the diesel generator
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exhaust supports, i.e., the vulnerability identified in the NRC l Case Study." obviously, if a vulnerability that was previously j
identified is reduced or eliminated, there is a reduction in core '
q melt frequency, although SNL estimates for wind would still be on j the order of lE-7/rx-yr. Specific comments on the seismic, fire
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- and internal flood analyses follow below.
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1 1.2.1 Seismic (Comments prepared from material by H. Bohn/SNL) j {
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] NSAC-ll3 reports a total seismic contribution of 7.4E-6/rx-yr as
] compared to the SNL result of 6.5E-5/rx-yr. The reduction was attributed to four factors: a lower hazard curve, newly-installed I
u I TABLE 2 Comparison of Modified Core Melt Frequency Estimates
- Secuence NRC Case Study Revised Value Key Chance core Melt Fre_auency Per Reactor-Year ;
S2MH12 H 4.7E-5 7.02E-6 SBLOCA Freq.
T iMLE 6.7E-6 4.94E-6 T 1 Freq T 3QH H12 2.5E-5 3.57E-6 Rel Valve LOCA frequency T 2MQH12 H 3.5E-6 5.0E-7 Rel Valve Prob S 2 MD 12 0 8.7E-6 1.3E-6 SBLOCA Freq.
T 3QD Di2 4.6E-6 6.6E-7 Rel Valve LOCA T 2MLE 6.6E-7 6.6E-7 None '
T 2MQD D12 6.6E-7 9.4E-8 Rel Valve LOCA S 2MXD 1 5.7E-7 8.8E-8 SBLOCA Freq.
T 5MLE 9.1E-7 9.lE-7 None T4MLE 6.2E-7 6.2E-7 None T 2MEN 1 2.0E-8 2.0E-8 None T 1QDi2 D <1.0E-8 <l.0E-8 !!one LTSB 3.6E-6 9.9E-6 T Freq
-LP Value 1.34E-4 3.03E-5 (Based upon "accepted" changes to data, see text)
TABLE 3 Comparison of External Event Core Melt Frequency Estimates Revised Accident Tvoe NRC Case Study EPRI/WOG Study NRC Case Study ggye Melt Frecuency Per Reactor-Year Seismic 6.1E-5 7.4E-6 4.1E-5 Fire 3.2E-5 6.3E-8 2.2E-5 Internal Flood 7.7E-5 <1.0E-8 8.7E-7 Wind 4.0E-6 <1.0E-8 1.7E-7 External Flood 1.9E-8 <1.0E-8 1.9E-8 !
l Lightning 5.8E-8 <l.0E-8 5.8E-8 )
1.7E-4 7.5E-6 6.4E-5 1
1 I
NOTE: These "revised" estimates in some instances use an approach or values which are still open for discussion, but they are provided to illustrate the sort of reduction *. hat may be reasonable.
(upgraded) emergency batteries, alternate water sources for the RWST, and recovery actions following the carthquake. Each of these is discussed briefly below.
The Hazard Curve: SNL does not agree with this modification, as it has no analytical basis. The EPRI/WOG analysis reduced the case study Pazard curve by a factor of 2 at the SSE and a factor of 5 at the 3 SSE acceleration, but no site-specific reanalysis was performed, The only rationale provided was that the EPRI Hazards Program tended to get hazard curves lower than the Lawrence Livermore Hazard Program curves by the f actors given.
However, SNL used the LLNL results for shape only, and scaled the Point Beach SSE to a frequency of 2.5E-4/yr, typical of most Eastern U. S. sites. Then the curve was modified for local soil column effects. We would not agree to the EPRI/WOG curve unless a site-specific analysis were performed. We believe the hazard as presented is realistic.
New Batteries: New batteries have been installed which meet seismic Category I standards. As failure of battery racks was a significant contributor to the seismic results, we are pleased that such a modification has taken place. However, taking full credit for these new batteries would only reduce the seismic core damage frequency tn 4.lE-5/rx-yr in the SNL analysis, less reduction than implied by the EPRI/WOG report. Several questions remain to be answered. Are the new batteries full-station !
emergency batteries or are they dedicated to the diesel generators and perhaps a few specific pieces of instrumentation? ,
This latter situation seems to apply. Even though the new installation is seismically qualified to the SSE, is there I sufficient margin in the design above the SSE where the seismic risk is greatest? (See also, comments to the Advisory Committee on Reactor Safeguards by ACRS Consultant P. Davis.15)
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Alternate Water Sources for the RWST: The EPRI/WOG reanalysjs takes credit for manually aligning other (presumably undamaged) water sources to replace the RWST, based on: a) an EPRI study (no reference) chowing that most free-standing vertical water storage tanks have behaved well in earthquakes, and b) the assumption that any failure of the RWST would not be instantaneous, but would allow time for such manual realignment. It should be noted that no reanalysis of the RWST fragility was performed. We do not agrea with these assumptions for the following reasons:
a) The Point Beach RWST is an anomalous design v;nich is outside the SQUG data base. Its dimensions (76' high by 25' outside diameter) are very nontypical. In our judgement, based on fragility calculations, significant buckling and extensive craching are possible, with quite rapid failure.
b) We would not give credit for manually aligning other sources of water in a short time frame due to aftershocks, confusion, loss of normal lighting, additional failures, etc. ,
c) Any alternate water sources would have to be analyzed and their seismic adequacy verified. It does not appear that this was done by the EPRI/WOG group.
Recovery: In the SNL seismic PRAs, credit is not taken for short term recovery actions (less than about 1/2 hour) due to the effects of aftershocks, confusion, etc. We believe this is a i realistic approach.
Summa ry: Including the new batteries, the SNL predicted seismic risk would be 4.1E-5/rx-yr, a value substantially greater than the 7.4E-6/rx-yr reported in NSAC-113. We do not concur with the other changes suggested.
'.2.2 Fire (Comments prepared from material by T. Wheelis/SNL)
The first area of concern deals primarily with the EPRI/WOG statement on page 6-4, NSAC-ll3, "The NRC Case Study scenarios
focused on transient combustible fires." This erroneous statement has been made repeatedly by industry reviewers. In response, SNL has stated, also repeatedly, that this is not the case. The assumption in the fire analysis was that the two fire sources used were reoresentative of the cables (AD situ) or transient combustibles found in a particular location. The idea being that one can not analyze every possible case, so use a bounding approach. There currently is no way to say exactly how much or where a fire source will be in a room. By the same token, there is no way to know where an electrical cable might ignite. However, based upon historical data, fires at nuclear power plants have been caused by both transient combustibles and self-initiated cable fires. Our selection of fire sizes was used to bound these fire sources. In addition, the historical fire frequency data for given fire areas certainly indicates that fires do occur and thus would seem to imply that there is "some" fire source present in the area or room. It will be noted that ;
in the fire analysis (NUREG/CR-4458, Appendix D, page D-19) the fire frequency for the particular room, AFW pump room in this case, was derived by censidering the in situ fuel loading, i.e.,
cabling, in relation to the total fuel loading in the building.
[SNL does not understand how reviewers can continually assert that the emphasis was upon transients when the analysis clearly and unequivocally states the generic freauency data was used.)
The second area of disagreement between the studies is in fire frequency. As noted, SNL used generic data for auxiliary building fires, and using fuel loading information provided in the Point Beach Appendix R submittal, developed a frequency for the particular room. EPRI/WOG used specific event data to develop their frequencies. We also note that NSAC-113 draws heavily upon some portions of the Limerick PRA16 That should be done with caution since in several instances the Limerick PRA reports reduced liklihood of fires based on the argument I
19 (engineering judgement) that their cables are "better" than those in use when the industry-wide data was collected. Even so, when one compares the total frequency for the AFW pump room, the SNL value is only 2.7 times the NSAC-113 value and for the switchgear <
room only about 1.4 times greater. Given the state of the art of fire PRA at the time of the original study, these differences are not that important.
A third area of significant disagreement deals with the number of suppression systems available and their effectiveness. Based upon the information available to us at the time the study was conducted, SNL gave credit for one Halon system in the AFW pump room. If there are indeed two systems, they should be credited.
In that case, our estimate of core melt frequency for the AFW pump room would become 2.5E-6/rx-yr and the total fire contribution would be 2.23E-5/rx-yr or about 1/3 less than that reported in the Casa Study *. EPRI/WOG has proposed that the Halon system effectiveness is much better than the industry data used by SNL on the basis of a personal communication with a 00E staff member. It is difficult to comment on the validity of the data since it is not publically available. However, given the nature of the DOE research and production complex, we suspect that the data reflects incidents at the processing plants (Rocky Flats, Pantex, etc.). While we certainly agree that additional data is desirable, it is not clear that suppression system failure probabilites for processing plants and nuclear power reactors are comparable. That is, the processing plants probably have more stringent fire protection systems requirements (eg.,
more periodic testing and maintenance) than nuclear power plants.
- The comment on Table D-ll of NSAC-113 ("The principal basis results from information gained from recent installation of a Halon system in the referenced room.") can be interpreted to mean that the second Halon system was installed after the NRC/SNL visits.
Similarly, the processing rooms are probably much smaller than the fire zones at the power plants, so that one might have suppresion system success for small rooms, but not necessarily large rooms. The remaining point is that new data should be factored into the existing data base, not used in isolation (simply because it provides a "better" result). The data from the Millstone PRA was based upon inspector testing data at nuclear power plants by the "American Nuclear Insurers Group"
(>60 data points). Therefore, if the DOE data is really comparable, it should be combined with the existing data and new reliabilites derived. If such an analysis leads to an improved estimate of reliability then it should be used. However, until the applicability of the unpublished DOE data is demonstrated and the combined analyis is accomplished, it is recommended that the a SNL values for Halon syctem reliability be used. (During some recent conversations with A. Buslik of the NRC staff, he indicated that there was some information available that suggests that the potential for common-mode failures of Halon suppression systems exists.
Maybe he actually had some data, that point is not clear. This should be followed up since if there are such common-mode failures the SNL estimates may even be optimistic.)
The final area of difference is in the treatment of human reliability in aligning the turbine driven AFW pump. SNL used a value of 0.1 While EPRI/WOG suggEEts 0.03. l.s has been noted elsewhere, SNL used generic values, so in some respects reduction by a factor of 3 does not appear to be a big driver. SNL did, in fact, talk with Point Beach personnel to verify that they could manually align the pump. They felt that they could and thic is pointed out on page D-32 oC Appendix D of the Case Study.
However, it is not clear that one could use 0.03 for every room, especialtly for a fire in the AEW pump room. In this case you could have a fila in the room where you were trying to manually 2
. align a pump. It would appear that the key to using a lower value would be the time available before core melt occurs. If there is some time, say 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, the 0.03 value may be appropriate, if the time is short, say 15 to 20 minutes, then the human failure probability should increase because of the stress factor. Unlesss very specific and_ detailed HRA results are available, SNL recommends retaining the generic values used in the Case Study.
1.2.3 Internal Flood EPRI/WOG takes issues with the Case Study internal flood analysis primarily with respect to the initiating event frequency. SNL used generic data for auxiliary building pipe ruptures and applied it to the piping in the service water pump house. This approach is consistent with generic goals of the study. In contrast, EPRI/WOG cites a pipe break correlation by Thomas 17 which is used to develop the initiating event frequency. They cite:
P c = (P C/P )*(Q L +A*S*Q P W)*BF*P where: PC = probability of break PL/P Qp =cr =isk quantifier = D*L/t% of (10*36/0.5 breaks out2 )of lgaks 144o(0.06)
A,S = factors related to weld quality (50,1)
Qg BF == dynamic same asloa Qp,but dingfor welds factor (2)(?)
P = global failure rate per Q (lE-8/yr/Q)
However, when one exam!nes the cited reference, it is found that Thomas defines the terms somewhat differently. For example, A and S are designated as developed area and fatigue stress, not "factors related to weld quality," although the empirical development vields a value of 50 for the product A*S. The term BF does not appear in the Thomas paper, the product B*F does, however. B is defined as a design learning factor, and F as a plant age factor, s
A further concern is the EPRI/WOG assertion that "The service water pump house flood scenario requires a break to occur in one specific T-joint in the fire main." This is then used to specify only a three-foot segment in the calculation of Q.
It would appear that a more rational challenge to the Case Study approach would be to question the "assignment" of the auxiliary building moderate break frequency to the service water pump house. If the frequency had been adjusted somehow to account for the amount of piping present (an approach analogous to that used for the fire analysis in which fuel loading was the parameter) we might be on firmer ground. A very cursory examination of just the amount of service water piping suggests reductions of at least an order of magnitude from the 2E-2 originally used taking this sort of scaling approach.
A more extensive discussion of this particular event is provided in Section 2.1.
1.2.4 Revised Estimate of Core Melt Frequency - External Events Based upon the proceeding discussion a revised summary of core melt frequency estimates is also shown on Table 3. This assumes without proof that the EPRI/WOG approach to pipe rupture is acceptable, but modifies it to account for greater pipe length.
1.3 Other Sianificant Issues There are a number of instances in which the SNL Case Study and the EPRI/WOG disagree on specific values for component reliability or event frequencies. This is perhaps most prevalent in the treatment of operator actions and recovery. In general, it is observed that whenever there are uncertainties or ranges of l
1 m
values for a particular event, the EPRI/WOG study will consistently take the most optimistic view. Unfortunately, this ,
is usually done without much documented analysis, relying heavily upon engineering judgement or opinion.
4 For example, elthough feed and bleed is a controversial solution 4
to decay heat removal because it does lead to containment contamination, the EPRI/WOG analysis asserts it will take place without hesitation. This assertion is based upon a classroom interview with two operators who assured the interviewer that they would conduct a feed and bleed operation. However, the i
report also states that Catawba operators in simulator exercises and interviaws expressed reservations. The report authors chose the more opticistic view. Actual plant incidents, such as that at Davis-Bessel8, t.sve also illustrated the operators reluctance to "open the primary." Therefore, we believe the more conservative approach in the Case Study is to be preferred.
Another example is available in the estimate of the operator error related to depressurization. The Case Study uses a human
- error of 1.5E-2/ demand which is the basic 3E-3 error rate multiplied by a factor of 5 to account for stress. NSAC-ll3 uses the 3E-3 without qualification. Again, we believe this to be overly optimistic.
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- 2. SPECIAL TOPICS FOR REVIEW o 2.1 Extended Internal Plood Analyses EPRI/WOG in NSAC-113 takes issue with the SNL Point Beach case Study internal flood (spray) analysis primarily with respect to the initiating event frequency. SNL used generic data for auxiliary building pipe ruptures 19 and applied that to the service water pump house. Such an approach appears consistent with the generic nature of the case studies. In contrast, EPRI/WOG cites a 1981 pipe break correlation by Thomas 17 which is used to develop the initiating event frequency. Additional details and comments follow below.
2.1.1 NSAC-ll3 Approach NSAC-ll3 cites the relation:
P c = (PC/PLI*(O P +^*S*Q W )*BP*P where: Pc = probability of break PL/P Op =cr =isk quantifier = D*I./t% of(10*36/0.5 breaks out2 )of,lgaks 144o (0.06)
A,8 = factors related to weld quality (50,1)
Qg = same as Op, but for welds (?)
BF = dynamic loading factor (2)
P = global failure rate per Q (IE-8/yr/Q)
It is possible to reproduce the values for PC reported in NSAC"113 by assuming that the value of Qg is 70, i.e., the three foot section has two welds, one at each end. This would be consistent with the EPRI/WOG assertion that there is only one 3-foot "T" which could cause adverse effects.
However, when one examines the cited reference, it is noted that Thomas defines the terms somewhat differently. For example,
I 4 A and S are designated as developed area and fatigue stress, not "factors related to weld qualilty," although the empirical development yields a value of 50 for the product A*S, and clearly i the factors are related to the treatment of welds. The single term BF does not appear in the Thomas paper either. The product B*F appears where B is defined as a design learning factor, and F as a plant age factor. Thomas also notes (page 86, reference 17) that "...there are severe limitations to the potential accuracy of any prediction. The state of the art is numerically still in the order o* magnitude phase. Any attempt at probabililty model-ing must recognize this." l Therefore, it would be appropriate for EPRI/WOG to explain how !
their expresion was derived and how they established its appli- ]
cability to this issue, i
A further concern is the EPRI/WOG assertion that "The service water pump house flood scenario requires a break to occur in one specific T-joint in the fire main." This is then used to specify only a three-foot segment in the calculation of Q. We do not understand the rationale for only one "T". The case Study notes that, "All pumps are in line-of-sight to the mid-section of the header." Based upon our evaluation of the geometry, it appears that the pumps can "see" on average 15-20 feet of the header. If one uses the Thomas correlation, and its validity here remains 12 be demonstrated, and recomputes PC assuming a 15 foot section of pipe and 3 welds (ie., two pipe sections joined together) in a fashion similar to that of NSAC-ll3, the result is PC r 2.5E-4 per year. This is not inconsistent with the range for moderate pipe breaks of 2E-4 to 3.4E-2 reported by Kazarians and Fleming 19, although it is on the lower end of the range. Using !
this frequency, the estimate of core melt frequency would become 8.7E-7/rx-yr which is also significantly lers than the Case Study value. Nevertheless, EPRI/WOG should provide the reasoning l l
behind limiting the vulnerable section to one specific T-joint.
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2.1.2 Case Study Approach !
{
If one questions the direct applicability of the auxiliary building data to the service water pump houso, it would appear that an alternativo approach would be to adjust the break frequency to account for the actual amount of piping present (an approach analogous to that used in the fire analysis whero fuel loading is the scaling paramotor). A very cursory examination of just the amount of piping in the service water heador and fire mains (assuming they have comparable runs) suggests a ratio for pump house to auxiliary building on the order of 0.05. If this approach is applied, a frequency on the order of 1E-3 is obtained which then yields an cotimate of coro melt frequoi.ev of 3.5E-6/rx-yr. It would be possible to refine this number with a more preciso analysis of the amount of largo diamotor piping in the two huildings.
Wright, et.al.20, have recently published the results of their study to establish pipe break frequency estimates for nuclear
, power plants. In this study, they treat piping which eculd cauco LOCAs and other piping separately. They also provido a categorization of'non-LOCA inducing pipe breaks by plant type, pipe si:0, leak rato, plant system and operational mode. In each instanco they provide a point estimate with upper and lower bounds, UB and LB, respectively. Considering all LWRs together their results may be summarized as follows.
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. l 2 i N T Point Catecorv Failures Onr Yrs LB Estimate UB All LWR 19 789.09 1.56E-2 2.38E-2 3.50E-2 Pipe Size (>6"D) 8 789.09 4.99E-3 1.00E-2 1.81E-2 -
Leak Rgte (>15gpm) 13 789.09 9.65E-3 1.63E-2 2.59E-2 System 1 789.09 6.45E-5 1.25E-3 5.95E-3
- Opnl Mode (Norm) 13 500.60 1.54E-2 2.59E-2 4.13E-2
Based upon this analysis, a pipe break frequency in the range of 1.0E-2 per year is not unreasonable, although a frequency on the l order of 1.0E-3 in a system ruch as the fire protection system is ,
i also substantiated. If one assumes Do breaks of significance in the 789 reactor-years reported above, then the point estimate becomes 2.8E-4/yr with LB and UB of 0. and 3.75E-3 respectively. ,
, It is worth noting that this is comparable to the value for PC
, from the NSAC-113 correlation assuming 15 feet of piping. There- ,
fore, in a more precise, plant-specific study, a non-LOCA pipe l break frequency less than the 2.2E-2/yr used in the Case Study is '
probably justifiable, although a value greater than the 3.75E-5/yr reported by E'RI/WOG I would be expected.
2.1.3 Summary j
The questions which need to be addressed.in discussions with j industry are: 1 i
i 1. How did EPRI/WOG derive / develop their version of the 1
Thomas correlation?
j 2. How was the applicability of this correlation t o this I study established? l J 3. What is the basis for limiting consideration to one 3-foot section?
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_ _ - - , _ _ _ _ . _ _ . _ _ ._._,_. _ _ __J
A 2.2 Cost (Imoact) Analysis EPRI/WOG in NSAC-113 takes the general position that for most modifications proposed, the Case Study undereutimates the costs.
NSAC-ll3 reports cost from 50% to 400% of those reported in NUREG/CR-4458. Comments on our comparison of costing follow below.
2.2.1 General Comments It is difficult to ascor*ain exactly what was done by EPRI/WOG, in terms of modifying the Case Study results, for a variety of reasons. Although the individual modification design reports .
(Attachment A through 0, to Appendix J, NUREG/CR-4458) spell out in reasonable detail the materials to be used and the work to be done, the individual cost elements are not er.umerated, only summary values for labor and materials are provided. Therefore, it is difficult to see how the approach defined on page 10-10, NSAC-113 was implemented. It says in part, "The EPRI/WOG analysis used the results of the NRC Case Study as a starting point for estimating these costs. An experienced cost estimator from WEP reviewed the estimates in the NRC Case Study (Appendix J) and adjusted those estimates where appropriate. The basis for adjustments in cost is presented in Appendix D."
This raises the question, did EPRI/WOG use the descriptions in the design reports to generate a new estimate, or was seme "rule of thumb" factor applied? In several instances in Table D-11, NSAC-113, reference is made to specific projects done at Point Beach and how much they cost, but there often is no clear indication as to how applicable the cited experience is to the modification under discussion.
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For example, on page 10-10 it is also stated:
"The basis for each increase is presented for each modification in Appendix D. Tangible evidence exists in support of each of 1 these increases. The NRC Case Study estimated that a dedicated ;
diesel generator battery system would cost $750,000. The actual cost of a new battery system installed at Point Beach and i designed for backup capability to' start the diesel generators, as l well as providing powert for half of the plant's critical safety l instrumentation, was $3,690,000, The actual cost of installation ,
of a dedicated battery modification based on one similar modi- l 4 fication available, supports the higher estimate of $1,800,000 l provided by WEP and used in the EPRI/WOG study."
Even so, there is no indication of how the $1,800,000 figure was generatedorhowabatterysystemforplant-wideapp1($ tion compares to a special purpose (diesel start) battery system.
Based upon the descriptions in NUREG/CR-4458 (Attachment B to Apendix J) it appears that the modification proposed is much less complex than the system actually installed by Point Beach. ;
i NSAC-ll3 also states: '
l "The general reasons fcr cost differences vary depending on the '
modification. For expensive modifications, most of the differences in cost included: (1) failure to consider some design requirements, e.g., seismic for specific aspects of the
- modification; (2) failure to account for existing structures
, and/or buried cabling at the site; (3) failure to consider costs 4
of iteration between initial design and final installation, especially when construction of supports or structuras and
, excavation were involved. For the inexpensive modifications, one important difference involved the fixed cost of paperwork of
$10,000 for any modification."
Unfortunately, when one compares these general observations with i the information available in Appendix D, NSAC-ll3, it is I impossible to establish a solid basis for them. I
! Consider first item (1) above, failure to consider some design
) requirements. Design requirements specifically are mentioned in
{ only two of the modifications discussed in Table D-ll. i 1
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Internal 8 - Sparo IUIR Pumn (MQD 816) : NSAC-113 notes that the l principal difference results from provision of a different power 1 arrangement in response to Enforcement Information Notice (IEN) 86-79. While it is reasonable to stato that costs will be higher, it is ap1 reasonable to fault the Case Study for not including a requirement which was not imposed until after the technical effort was completed.
Internal 9 -
Diesel-Driven Auxiliary Feedwater Pump (MOD 817):
NSAC-ll3 states that, "The principal difference is that piping i i could not go through the non-seismic turbino building. The WEP l l esy6mato assumes construction of a now seismic buildiing to house l
the pump." The implication appearu to be that the Case Study did proposo to run piping through the turbino building and that the new constuction is non-seismic. Careful reading of Attachment M I
l to Appendix J, NUREG/CR-4458, reveals for examplo, "1.2 Design Requirements and Criteria 1.2.3 Environmental Seismic - Installation nust be seismic 1.2.4 Installation The new equipment shall be housed in a new Category I ,
l' building, consisting of a single room housing a diesel generator, day tank, oil pump, battery and electrical I
I equipment, located adjacent to, but not c_gflacqttill the existino olant turbinq_hallt (Emphasis added) 5.1.3 Mechanical Install auxiliary feedwater piping from the pump to the diesel jacket water heat exchanger then to existing AFW header. (NOTE: These headers are in the auxiliary building, not the turbine hall.)"
Also, Figure 2 Diesel Auxiliary P&ID clearly shows new room and piping to auxiliary building not to the turbine building.
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Therefore, although there may be differences in costs assigned to various items, it does not appear that these differences should 1 be attributed to the causes cited above. j l
l Consider next item (2) failure to_ account for existing structures I
and/or buried cabling at the site. This situation is mentioned l l in three of the comments, l >
L Internal 11 - New Condensate Storace Tank (MOD 818): Tho NSAC-ll3 comments do not imply a failure to meet der,igr. l requirements, par sg, but they do imply that the Case Study did not adequately consider all the design effort required, i.e., l "The principal difference includes the consideratic.n that i installation can not be in the area suggested becaase maintenance ;
shop and offices currently occupy part of that space, and because of underground piping and cabling in the area.
Additional costs include extended piping runs and rework problems for the ,
underground caoling areas. The initial design will not succeed; i construction sill uncover underground cables and pipes, work will ,
necessparily cease, and the design would have to be redone.
These rework costs can be substatial."
i Several aspects of these comments are distrubing. First, during !
the modification design process thr. Case Study team visited the site and outlined what was being proposed. No one4 objected on the grounds that other structures were in place. One wonders why? The second part of the comment is dist00bing because it portrays a situation in which the plant operator does not know what piping and cabling is buried or where it is buried. That would seem to make any work at the site a "hit and miss" process.
Surely, that is not the case!
Seismic 1 -
Seismic RWST Alternative Connection to Scent Fuel Pool:
"The principal differences include. . . increased pipe routing for seismic design, additional penetrations and more cable routing. . . (Note that the RHR pumps can already take suction i from the spent fuel pool via a two-inch pipe connection."
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Again it is noted that there is an implication that the case i Study modification is not seismic, but Attachment D to Appendix J f of NUREG/CR-4458 clearly spells out that this hlll bit a seismic
. Category I installation (1.2.3 Environmentcl, p age J-9 and Table 1
1 1, page J-98). The question also arises here, if there is a 2" 4 line which permits the RHR pumps to take suction from the spent i
- fuel pool, why doesn't it appear on the P& ids amd why wasn't it )
I mentioned during the site visit when modifications were discussed !
, with the staff?
Sorav - Intake Structure Shield Wall Extension (MOD 109.
"Principal basis is the cost to disassemble the existing wall and l erect a new wall. This work is not included in the NRC Case Study which neglected to consider that the fire protection spray header over the pumps is seismically supported. Iteration is
! required generally for seismic construction, thereby increasing the cost."
j Attachment G to Appendix J of NUREG/CR-4458 again unequivocally )
states in Section 5.2 (page J-130) "Remove existing shield )
j wall." Thus, part of the above quote is simply incorrect.
Furthermore, Section 1.2.1 (page J-129) states that "The shield I wall shall be seismic category I with a three hour fire rating."
1 Based upon the design proposed in Attachment G, the issue as to i how the fire protection header is suptorted does not appear to be of special concern. It is not at all clear why "iteration" would be required on a task as straight forward as the shield wall.
, 2.2.2 Specific Comments i
l Internal 9 - Diesel-Driven Auxiliary Feedwater Pumo (MOD 817):
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1 WEP estimates costs at $8,000,000 versus the $2,606,000 in the NRC Case Study. As noted above, the comment in Table D-11 1
! implies that the differences arise bacause piping runs will be j longer that those used by the Ca,se Study and because WEP uses 1 1
costs for a Seismic I building and the Case Study did not. The i
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Case Study cost estimates were generated using the general method outlined in NUREG/CR-379121, the Handbook for Cost Estimating, !
information from the Energy Economic Data Base 22 and the Tech-j nical Assessment Guide 23 This information was augmented with ;
- local cost experience gathered during the site visits. In ,
l contrast, the EPRI/WOG approach was to use "an experienced WEP l cost estimator" to review and revise the estimates. It would appear, given the "bottom line" number reported, S8,000,000 versus $2,606,000, that the WEP estimates are much coarser than I
] those developed by United Engineers and Constructors (UEC) for the Case Study. Particularly, since the WEP estimator started with the published UEC information which only shows aggregate costs for labor and materials. Although UEC was not required j under their contract with Sandia to provide the details of the ,
f costing (unit costs, hourly rates, etc,) that information has !
] been requested in order to have a complete package to compare
- with any EPRI/WOG details that become available during the !
4 planned discussions. In the case Study the indirect costs vary :
l comewhat with alternatives. For example, for Alternative 1 the j indirects are '66% of the directs, while for Alternative 3 they are '70% of the directs, so that the ratios of total cost to !
I i j direct cost range from 1.66 to 1.70. Apparently a similar j variation exists in the WEP estimates since the ratios of total cost to direct cost vary from 2.21 to 2.53 for the estimates f provided in Table D-1, NSAC-113. It may be noted that the ;
indirects in NSAC-113 are approximately 1/3 greater than those in i j the Case Study, but there is no explanation for the increase. (
) Similarly, there is no explanation for the increase in direct cost, i.e., how much piping was added, how much additional concrete and steel, etc.
- Wind - Diesel Generator Exhaust SuDoorts (MOD 119)
- If one subtracts the $10,000 cost attributed to testing and submittals i
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. l i-by WEP, then the $15,750 cost rcported by UEC does not compare that unfavorably with the $20,00 estimated by WEP. However, there are no details upon which to base a comparison at this time, Added information is being sought from UEC.
2.2.3 Summary ,
I Based upon the proceeding discussions, the following issues need to be addressed with industry. [
j 1. Did the WEP estimator "back out " to 1985 costs or are these 1987 figures in NSAC-113?
I
- 2. Did the WEP estimator use the Bill of Material called out in Appendix J, or did he just apply some arbitrary "factor" to the Case Study numbers?
l 3. Were man-hour cotimates examined individually or was some arbitrary "factor" applied?
- 4. How was the applicability of prior work at Point Beach i established? Example: battery installation.
- 5. The basis for cost incrdhespresumablypresentedin ,
Appendix D, Table D-11 is inadequate for any meaningful ;
comparison. Can EPRI/WOG enumerate and quantify the differences ;
more precisely?
I 6. How did EPRI/WOG come to the conclusion that added piping l runs were required?
) 7. What is the basis for increasing costs for a Seismic I 5 structure above those reported in the case Study?
i 1 8. Are the installed systems really so inadequately documented
- that locations of buried piping and cabling are unknown? .
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. REFERENCES
- 1. EPRI/WOG Analysis of Decav Heat Removal Risk at Point Beach, NSAC-113, Science Applications International Corporation and Westinghouse Corporation for Electric Power Research Institute, October 1987.
- 2. Shutdown Decay Heat Removal Analysis of a WestinchouJe 2-Loop Pressurized Water Reactor, NUREG/CR-4458, SAND 8G-2496, Sandia National Laboratories, March 1987.
- 3. Analysis of Core Damace Frecuency From Internal Events:
Secuovah, Unit 1, NUREG/CR-4550/Vol 5, SAND 86-2084, Sandia National Laboratories, February 1987.
- 4. Analysis of Core Danace Freuency for Internal Events: Surry, Unit 1, NUREG/CR-4550/Vol 3, SAND 86-2084, Sandia National Laboratories , November 1986.
- 5. Oconee PRA, A Probabilistic Risk Assessment of Oconee Unit 3, NSAC-60, Nuclear Safety Analysis Center, EPRI, June 1984.
- 6. Shutdown Decay Heat Removal Analvis Flan, Letter Report, Sandia National Laboratories, August 1984.
- 7. Review and Evaluation of the Indian Point Probabilistic Safety Studv, NUREG/CR-2934, SAND 82-2929, Sandia National Laboratories, Decerber 1982.
- 8. Probabilistic Analysis and Operational Data in Response to NUREG-0737, Item II.K.3.2 for Westinchouse NSS Plants, WCAP-9804, Westinghouse Electric Corporation, February 1981.
- 9. Personal Communication, D. Paddleford, Westingh7use, and D. Ericson, ERCI, March 28, 1988. Best estimate analyses by Westinghouse have minimal circulation outside the company.
- 10. Interim Reliability Evaluation Procram Procedures Guide, NUREG/CR-21728, SAND 82-1100, Sandia National Laboratories, January 1983.
- 11. Reactor Safety Study Methodoloav Acolications Procram: Oconee s3 PRR Power Plant, NUREG/CR-1659(2 of 4), SAND 80-1897(2 of 4),
Sandia Naticnal Laboratories, May 1981.
- 12. Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plant Operations, NUREG/CR-1278, SAND 80-0200, Sandia National Laboratories, August 1983.
- 13. The Reliability of Emercency Diesel Generators at U. S.
Nuclear Powe Plants, NSAC-108, Electric Power Research Institute, September 1986.
e l
REFERENCES (Continued) I I
- 14. "Common-Cause Failure Data: Experience from Diesel Generator j Studies," Nuclear Safety, Vol 26, No 3, May-June 1985, pp 305-313. ,
- 15. Letter, Review of "EPRI/WOG Analysis of Decay Heat Removal Risk j at Point Beach, (NSAC-113), Final Report, Octobar 21, 1987," P. R. ;
Davis to P. Bohnert, ACRS, January 11, 1988. ;
- 16. Severe Accident Risk Assessment Limerick Generatina SttiPD, l Report #4164, Philadelphia Electric Company, April 1983. l
- 17. "Pipe and Vessel Failure Probability," Reliability Enaineerina, Vol2, 1981, pp 83-124.
- 18. Loss of Main and Auxiliary Feedwater Evvent at the Davis 6 esse l
Plant on June 9, 1985, NUREG-1154, USNRC, July 1985. *
- 19. "Internal and External Flood Failure Model," Chapter 10 of The .
Impact of External Events, Fire, Internal Flood on Nuclear Power !
Facilities, Notes from ACTA Consulting Engineers and Applied l l Scientists, 1984.
- 20. Pipe _ Break Freauency Estimation for Nuclear Power Plants, NUREG/CR-4407, EGG-2421, EG&G Idaho Inc., May 1987. !
- 21. A Handbook for Cost Estimatina, NUREG/CR-3971, ANL/ESS-TM-2CS, !
Argonne National Laboratory, October 1984.
l
- 22. Energy Economic Data Base (EEDB) Program, Phase VII Update, !
United Engineers and Constructors for Oak Ridge National Laboratory, 1984. .
i l
- 23. Technical Assessment Guide (TAG), EPRI P-2410-SR, Electric '
Power Reserch Institute, May 1982.
i I
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