ML20137P700
| ML20137P700 | |
| Person / Time | |
|---|---|
| Issue date: | 07/09/1996 |
| From: | Milhoan J NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| To: | NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| Shared Package | |
| ML20137P228 | List: |
| References | |
| FOIA-96-485 NUDOCS 9704090302 | |
| Download: ML20137P700 (60) | |
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e,n nee eq\ UNITED STATES i' NUCLEAR REGULATORY COMMISSION i -E !- WASHINGTON, D.C. 2000M001 July 9, 1996
- MEMORANDUM To: All Field Inspect y FROM: James L. Milhoan M I. .
Deput/ Executive tractor
- tor Regulation.
i fo'-Nuclear Re Regional Operations and Research , ,
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SUBJECT:
ARTICLE IN CHRISTIAN SCIENCE MONITOR I would like to direct your attention to the attached article which appeared in the Christian Science Monitor on June 18, 1996. The concerns raised in this article relate to the effectit'eness of the NRC and they. point to areas
, which we may need to improve. To this end, I would sincerely appreciate your perspective on the issues raised in the article, as well as your connents and views regarding your personal experiences, not only in communicating with your sagement, but also in your ability to parform your job.
Although your response is not mandatory, the issues raised in this article are relevant to each inspector in the field; thus, your input would be useful in identifying areas in need of improvement. Please provide your response to ;
i- your respective Regional Administrator with a copy to me and to the Director ,
of Inspection and Suppo.rt Programs /NRR by August 30, 1996. It is my intent-to I l have the Regional Administrators review your responses and discuss them at the January 1997 Senior Management Meeting in Region IV.
Attachment:
As stated 1
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BINDER 96-485 PDR _ _ _ _ _ _____________;
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Tuesday June 18,1996 Edition ,
Walking the Beat With a Nuclear Patrolman i
Peter N. Spotts, Staff writer of The Christian Science Monitor l
SEABROOK, N.H. - John Macdonald strides into the control room of Seabrook Station, a nubear plan coast north of the M==~hae-New Hampshire border. ,
He pauses to look at the dials and displays in this cockpit for controlling one of the world's most %.w ,
technologies. l l
"If you want to know what's really going on at a nuclear plant, just ask a reactor operator. They'll talk your car i '
off," he says, grinning, as one approaches.
CONTROLROOM CONFERENCE: Senior resident inspector John Mardanald (r.) performs a rautane check on OPerauons at the l 1
Seabrook nuclear plant in ,
, (PHOTOS BY R.
NORMAN MAWENY/ STAFF)
Mr. Macdonald is keenly interested in what the operators have to say - as well as all the digits on the monitors here. He is the Nuclear Regulate.y Commission's senior resident inspector at the plant. As such, he is one of 181 on-site inspectors at 110 commercial plants across the country.
They are the agency's cops on the beat, the first line of defense against nuclear catastrophe. They prowl corridors and peer from catwalks, listening, watching, and asking probing questions.
How well they do theirjob - and the conflicts they face - go to the heart of the debate over the effectiveness of the NRC itself.
Certainly being a resident inspector is one of the more unusualjobs in government. Unlike many other federal watchdogs, resident nuclear inspectors go to work every day with the people they are supposed to oversee. j They have offices at the plant. They eat in the company cafeteria. Though federal rules forbid them from
" socializing" with plant workers, they have to develop a level of trust with utility managers and staff while maintaining a sense of d*=Amant.
l Tensions can surface even with their own NRC superiors. Some on-site inspectors say they're hampered with i by-the-book administrative work that cats into time better spent inspecting pumps and pipes. Other inspectors complain of supervisors ahering or ignoring their findings. They cite instances of being harassed for pursuing safety issues by a ~;.iior management too cozy with the nuclear industry. l
j The result, critics say, is an agency in which dissent is eften stifled and a nati:n in which react:rs may be operating with defective systems.
While resident inspectors lack the authority to slap an errant power plant with a fine or even a notice of violation, the NRCs equivalent of a ticket, they are responsible for providing an independent check o
-performance.
Tneir reports cover everything from the nuts-and-bolts of plant repairs to reviewing documents i 1
operators identify and solve equipment problems. Lears keep tabs on how plants respond to NR directives. They also serve as a reyrative to the public living near a nuclear facility - for instance, giving talksinlocal schools.
- For his part, Macdonald says his experience as an inspector has been a good one. To spend tim glimpse the magnitude of the job the NRC fa m in regulating a tu icology in which there is little enor.
"You've got something the size of Shea Stadium you've got to inspect," says one official at NRC hea "You can't be on top of everything. You hope you're dealing with a responsible licensee."
By 8:30 on this morning, Macdonald, dressed casually in khaki pants and knit shirt, has already control-room operating records and taken part in a conference call with the NRCs regional headqua Khig of Prussia, Pa.
ON PATROL: '
Seabrook inspector John Macdonald is responsible for seeing ,
that the utility safely operates a maze of Pumps and i
generators, as well as l
miles of pipes and I electrical cables that make up an atom-splitting rC3Ctor.
Moments later, he slips into a corner seat in a conference room as some 30 Seabrook officials and staff J. . for a daily briefing. One by one, they review the plant's performance in the past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and report the s of maintenance projects. Macdonald jots notes u one describes a problem he's found with a radiation m The malfunction doesn't seem to be serious, but the utility will need NRC approval to fix it.
Later, in his office, Macdonald says that the utility was in effect proposing the NRC adopt new restriction the way the plant operates. "That represents a good safety ethic," he adds.
The NRC, in fact, has to rely a lot on the integrity of utilities. That's because the agency "does not hav
3 manpower to come in and see that every 't' is crossed and every 'i' is dotted," says William Jocher, a farmer '
executive cf the Tennessee Valley Authority who raised safety issues about the utility's Sequoyah nuclear plant.
1 Indeed, the amount of work involved raises an enduring question: Does the NRC have enough nuclear beat cops? At present, the agency matches the number of reactors at a site with the same number ofresident
, inspectors, then adds one more. The so-called n+1 formula represents a compromise. In 1981, two years aAer
' the accident at Three Mile Island in Pennsylvania, the agency wanted to increase the number of resident
- inspectors from at least one per reactor to two. Congress balked at the cost.
] Inspectors must have science or engmeerms backgrounds, although not necessarily in the nuclear field. Many j come from the Navy or from nuclear utilities. Macdonald, one of two inspectors at Seabrook, came to the
- agency aAer getting a degree in marine engineering and a US Coast Guard license for operating steam, diesel,
! or gas turbines. ,
He joined the NRC in 1984 'and arrived at Seabrook in April 1995, aAer serving as senior resident inspector at 4
the Pilgrim nuclear plant in Plymouth, Mass., and as a resident >=r+-tv at plants in Vermont and Plorida. His junior co!!v. David Mannai, came to Seabrook from the Susquehanna nuclear plant in Pennsylvania. On this
- day, Mr. Mannai is away taking part in a six-week training program in Tennessee to get the basics on Seabrook's reactor, which is different from Susquehanna's.
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' Resident inspectors serve at one plant for up to five years. The rotation policy is designed to ensure that the 4 watchdogs don't get toc close to the people they're overseeing. Yet because nuclear facilities are complex
! assemblages of pumps, pipes, turbines, and emergency generators, it can take an inspector several yearsjust to
- learn everything about a plant. "On average it takes one to two years to really get a handle on a site with any l confidence," Macdonald says.
i i Ordinarily, Macdonald says, he and Mannai meet early in the morning in their office at the plant to set i inspection agendas. Inspectors have a core set of plant activities they must scrutinize regularly. These range from plant maintenance and engineraing to radiation exposure and ucurity. The core program also includes
" initiative" inspections - ones where "you have an itch, a hunch, or some aspect of the plant hasn't been
- reviewed in awhile," Macdonald says.
i l 'If you polled every senior resident inspector out there, they'll tell you the same
- thing
- [NRC] management won't let us do our job.'
l -A 20-yearNRCinspector i
i In following this routine, inspectors will do everything from waten workers make repairs to review plant
- records to see how quickly a utility spots and fixes a problem. NRC guidelines are detailed - down to recommending how much time inspectors can devote to each inspection category. The idea is to catch problems
. before they become too big.
YET such micromanaging can also serve as a straitjacket, some inspectors say. "If you polled every senior resident inspector out there, they'll tell you the same thing: [NRC) management won't let us do ourjob," says a 20-year NRC veteran who is a resident inspector in another region.
Managers at his regional headquarters, he explains, keep close tabs on the inspection numbers in part because
- inspection time is factored into the fees the NRC charges utilities for its work. These fees pay the NRC's overall l bill.
i "I've had to use every goofy little process for sorting beans" to make sure the numbers match management's expectation, he says. Such detailed bean-counting, he says, has cut his direct involvement in inspections by 30 l percent, leaving a larger proportion to less-experienced colleagues.
, In addition, he says, inspecting by the numbers can misdirect efforts. "I have to put ir; a specific amount of time inspecting [ plant) operations, even when I know the problems are in maintenance and engineering," he says.
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What management really needs to know, he says, is whether conditions are improving or getting worse at a l
, nuclear plant. "Instead, they are forcing senior resident inspectors to be gatekeepers of accounting stufE" NRC administrators defend the procedures. Robert Gallo in the NRC's ofEce ofNuclear Reactor Regulation, which runs the agency's licensmg and inspection programs, notes thai while the administrative workload is an issue among the senior resident ivors, it's an inescapable part of the job. Part of that job is to train subordinates so that they become adept at ferreting out problems. "You can't do it al! yourself," Mr,. Gallo observes. '
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TALK:The l NRC's on-site in pears are the agency's eyes and ears. Ia a-ar Macdonald watches over the arnval of equipment in the l turbine buildmg at Seabrook.
When asked how tightly he has to hold to time allocations on the various inspections, Macdonald replies:
"When I come across a safety issue, resolution is paramount, not accounting for time.,
Critics outside the NRC add that too often some inspectors look only at a utility's documents to verify a plant is being well-run instead of checking hardware.
"Everyone starts with paper," acknowled e one senior resident inspector at a plant in die South. "That's how you figure out the next step - where you need to crawl around and follow up." But he adds that some of his colleagues do stop at paperwork, adding, "It's a function of their energy level."
The problem with inspecting only paper, according to internal NRC reports, is that utilities often say they are correcting problems when they aren't.
WHEN a potential violation is found, it is turned over to regional NRC ofBees to pursue possible enforcement actions. But the response may vary, depending on the political climate in Washington, says Herb Livermore, who recently retired after more than a decade as a resident inspector. "If management got word from D.C. that we were getting too tough, you wouldn't get much support," he says. "If word came down that we were being too lax, you'd get more support."
l A senior resident inspector adds: "The real problem is getting my [ regional) management to dig in and hold the line" with headquarters.
At times, say some inspectors, they meet resistance ranging from stone-walling to harassment and intimidation.
Two years ago, regional reactor inspector Larry King and a colleague went to a nuclear plant near St. Lucie,
! Fla., to f:llow up cn items frcm previous inspections. What they found prompted his colleague to write u
> three violations, says Mr. King, who in 1994 won a harassment and intimidati:n acti:n against the NRC
' being denied more than a dozen promotions for persisting in pressing safety issues.
But the NRC section chief, who had been the senior resident inspector at the S; Lucie plant, " changed the violations to ' unresolved itema,'" King says. He and his p.rg.er tried to voice their concerns in a larger l
performance assessment the NRC was conducting, "but our results were not included Now t kind of problems at the plant."
Rebecca Long, an inspector in the NRCs Region 2 office in Atlanta, says that watering down reports i allowing inspectors to respond violates NRC policy. But, she says, King's experience isn't unique.
Ms. Long, who has won a sex and job discrimination case against the agency, had one stepsr/. ea withdrew a citation she had prepared for problems at a research reactor at the Georgia Institute of Techno i
- in Atlanta. The reactor was allowed to operate until nearly a year later, when the agency shut it down followi an accident that st d from the violations Iang identi6ed in her original citation.
Other supervisors made life even more difficult, Long says, aAer she found violations at the TVA's Brown Ferry and Watts Bar plants. Immediate supervisors were berating her work and downgrading her in jo evaluations, she says, even as their superiors at regional and national headquarters were praising the qu her inspection reports.
Today, Long carefully avoids describing anything that might constitute a violation of her settlement with agency. But she notes that her victory has been bittersweet. "Nobody was ever punished," she says of nine-year ordeal. " People did things the NRC manual says they should be terminated for."
The danger, critics say, is that such cases chill people who otherwise might raise safety concerns "Many have come to me and said that aRer seeing what I went through, they never would disagree with management,"
Long says. "They're afraid they'll get into trouble."
Tom Devine of the Government Accountability Project in Washington, which provides legal counsel for whistleblowers, agrees: "The NRC has the symptoms of an agency saturated with frustrated whistleblowers afraid to come out of the closet."
If Seabrook's Macdonald has been spared the frustrations some inspectors cite, he acknowledges the inherent pressures of the job. Inspectors oRen work 10- to 12-hour days. They must abide by regulations preventing them from socializing with utility workers.
The NRCs rotation policy can add to the sense ofisolation: "We've moved four times since I joined the NRC.
We've had to build protective walls to avoid being too deeply rooted in a community."
l HW:%'~ l;1 7 ph 2 9 .U., A DUST BUSTER: A worker at the Millstone plant in Waterford, Conn., vacuums up rwhoactive dust as a safety procedure. Major NRC notauons can result in fines or plant closure.
"The resident program is not a career program," he adds. " Generally, you enter as a young person, take one, '
two, or three [ plant] pesignments, and move into a regional or headquarters job."
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l All of which raises another issue: experience. Being an on-site inspector is becoming "more and more cfa young person's position," he says. The age and myedes of the NRC's resident inspectors bear watching since tnese people are the ones who raise the majority of safety and performance issues, he says.
! Ar.w,-4 to NRC Sgures,75 perecit of the agency's resident inspectors and 17 percent of the senior resident
! inspectors are in their Srst assignment. Thus, while they will have gone through a training and inantaring program, many have less than five years' experience in deshng' directly with plants, utilities, and their own regional of5ces. n MACDONALD, who received the agency's Meritorious Service Award in 1993, says M changes
-have helped offset the trend. "Over the past six or seven years, the technical support (for i==a-*ars] has improved dr===ti=11y," he says. "IfI fmd an instrumentation issue and raise it during my early morning call to
) the regional ofEce, ril have a call back by 9 a.m. asking for details "
i Some veteran i==a-*ars, however, remain concerned that young, inexperienced watchdogs are unlikely to buck
- the system. "The sc
- ior resident who wants to be executive director of operations someday knows that d C--g '
his neck out isni going to do his career any good," says one veteran inspector in another region. "The older ones will tell you up front that to get along, you have to go along. They're starting to replace us old goats with lambs and sheep. That's where we're headed."
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Reprinted by permis'sion from The Christian Science Monitor @l996 The Christian Science Publishing Society. All Rights Reserved.
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UNITED STATES NUCLEAR REGULATORY COMMISSION 6 c/I M 54
[Q WASHINGTON. D.C. Sok 54001 f
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i MEMORANDUM TO: Hubert J. Miller, Regional Administrator, Region I Stewart D. Ebneter, Regional Administrator, Region II ;
A. B. Beach, Regional Administrator, Region III -
i Leonard J. Callan, Regional Administrator, Region IV Steven A. Varga, Director, Division of Reactor Projects I/II Jack W. Roe, Director, Division of Reactor Projects III/IV FROM: M. Wayne Hodges, Director .
Division of Systems Techno ogy Office of Nuclear Regulatory Research
SUBJECT:
IPE SENIOR REVIEW BOARD SEPTEMBER MEETING AGENDA Attached is the agends for the September 11-12, 1996, IPE Senior Review Board l meeting. The purpose of the meeting is to discuss the contractor-developed technical evaluation reports for St. Lucie and Commanche Peak and the staff evaluation report for Susquehanna. The meeting will be held in Two White Flint, room T-10-A-1. {
f Attached please find the detailed meeting agenda. As always( resident I inspectors and project managers are invited to attend. If yolFhave an questions, please contact John C. Lane at 301-415-6442.
Attachment:
SRB September meeti.g agenda cc: E. Butcher R. Hernan ;
L. Wiens M. Miller, R-II A. Gody, Jr. R-IV T. Polich A. Camp, SNL J. Forrester, SNL j J. Lehner, BNL M. Banerjee, R-I J I
C. Poslusny
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The St Lucie containment is a large, dry, steel containment vessel surrounded by an annular space and enclosed by a reinforced concrete shield building. The containment has ;
l-a volume of approximately '2.5 million cu. ft. and a design pressure of 40 psig. The reactor '
i coolant system is a Combustion Engineering (CE) two-loop design. Some of the plant characteristics important to the back-end analysis are summarized in Table 1 of this report.
, Table 1: Plant and Containment Characteristics for St. Lucie Plant . ,
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St. Lucie Zion Surry i Characteristic 2700 3236 2441 [
< Thennal Power, MW(t)
NP* 12,700 9200 i RCS Water Volume, ft' 2,500,000 2,860,000 1,800,000 Containment Free volume, ft' -
207,000 216,000 175,000 Mass of Fuel, Ibm 36,200 i 58,700 44,500 I Mass of Zircalloy, Ibm !
40 47 45 l Contamment Design Pressure,
- . psig 95 135 126
- Median Containment Failure Pressure, psig
- . 3.9 3.8 RCS Water Volume / Power, .NP' ft'/ M W (t) 926 884 737 Contamment Volume / Power, ft'/ M W (t) 0.023 0.016 0.020 Zr Mass / Containment Volume, >
lbm/ ft' !
0.083 0.076 0.097 Fuel Mass / Containment Volume, lbm/ fl'
- Not providedin the IPE submittal.
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. i The plant characteristics important to the back-end analysis are :
- A Steel containment that may be vulnerable to direct attack of dispersed core debris. ,
However, according to the licensee's response to the RAI, the probability of the dispersed debris coming into contact with the containment steel shell is negligible because of the thermal shields around the vessel and the very narrow gap for the '
dispersion path.
. The large containment volume, high containment pressure capability, and the open nature of compartments which facilitates good atmospheric mixing.
- A cavity design which facilitates flooding of the reactor cavity. Ex-vessel coolin likely to occur due to reactor cavity flooding and the low placement of the reactor vessel. This reduces the probability of vessel failure and is credited in CET quantification 2 The cavity configuration is a deep cylinder, which would likely '
in the formation of a deep molten core debris if all of the core mass pours into the cavity.
. There is no lower head penetrations in the St. Lucie reactor vessel. This may delay the
- ime of vessel failure.
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_8 With the cavity flooded, a vessel failure probability of 0.1 (i.e.,0.9 probabilit of preven l
. by ex-vessel cooling) is used in the IPE.
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The Approach usedfor Back-End Analysis The methodology employed in the St. Lucie IPE for the back-end evaluation is clearly
' described in the submittal. Containment event trees (CETs) were developed to determine the containment response and ultimately the type of release mode given that a core. '
. damage accide_nt has occurred. The front-to-back end interface are provided in the IPE by '
the definition of 15 Plant Damage States (PDSs) for Unit I and 14 PDSs for Unit 2. The PDSs are identified by core damage state, determined by core melt timing and RCS +
pressure, and containment state, determined by containment pressure boundary statu containment safeguards system status.
The top events of the CET are quantified by the use of fault trees (called logic trees in the ,
IPE submittal), which address the phenomenological, systems, and operator human response issues important to accident progression. The CET and the logic trees used in St. Lucie IPE provide a structure for the evaluation of all of the containment failure modes discussed in NUREG-1335. The quantification of the CET in the St. Lucie IPE is based on NUREG-1150 data and plant-specific MAAP calculations The result of the Level 2 .
analysis are grouped to forty five release modes. Release fractions for these release mo '
are determined by the developm'e nt of a parametric code similar to that used in NUREG-1150 (i.e., X-SOR) and plant-specific MAAP calculations. l For the St. Lucie Plant IPE, despite some inconsistencies, the definition of the interface between Level 1 and Level 2 analyses is in general reasonable. The CET is well structured and easy to understand. Although CET quantification and source term grouping and quantification seem adequate, the basis for some data used in CET quantification is not i
sufficiently discussed in the IPE submittal, and despite uncertainties of these data, their effect on CET quantification is not evaluated in the IPE (by sensitivity analyses). ,
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i Back-EndAnalysis Results
. For St. Lucie, the leading PDS, which contributes about 18% to total CDF, is a PDS with l
early core melt, with the RCS at high pressure, and with all containment system availabl
' (PDS 3B). The accident sequences that contribute to this PDS are transient initiated sequences. 'Ihis PDS is followed by a low pressure PDS (13%, PDS 5B) and an intermediate pressure PDS (12%, PDS IB), both with early core melt and all containment
. system available, and another high pressure PDS with early melt but with no. containme system unavailable (12%, PDS 3H). The latter high pressure PDS (PDS 3H) includes th '
' SBO sequences and is the dominant contributor to both er.sy and late containment failures.
Table E-3 shows the probabilities of containment failure modes for St. Lucie Plant as percentages of the total CDF. Results from the NUREG-1150 analyses for Surry and.
are also presented for comparison.
Table E-3. Containment Failure as a Percentage of Total CDF St. Lucie Plant Surry Zion Containment St. Lucie Plant IPE, Unit 1++ IPE, Unit 2++ NUREG-1150 NUREG-1150 Failure Mode 1 0.7 1.4 Early Failure 1 13 5.9 24.0 Late Failure 15 15 12.2 0.7 Bypass 12 Isolation Failure 71 81.2 73.0 Intact 72 ,
2.6E-5 4.0E-5 3.4E-4 CDF (l/ry) 2.3 E-5 The data presented for St. Lucie are based on Figure 4.0-4 of the IPE submittal.
The difference between Unit I and Unit 2 is due to different Level 1 analysis results.
Included in Early Failure, approximately 0.1%.
Included in Early Failure, approximately 0.5%.
Included in Early Failure,0.1%.
As shown in the above table, the conditional probability of contamment bypass for St.
Lucie is 12% of total CDF for Unit I and 15% for Unit 2. Containment bypass comes from ISLOCA and SGTR with ISLOCA being the primary contributor (70% of all bypass ,
[ for Unit I and 77% for Unit 2).
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14 The conditional probability of early containment failure for both Unit I and Unit 2 is about 1% of total CDF. According to the "Sununary and Conclusions" section of the IPE l submittal (Section 4.8),"The major contributors to.early containment failure for St. Lucie include containment threats due to HPME loads from high RCS pressure core damage accidents, steam explosion events for low pressure sequences, and isolation failums." ;
i This is not really accurate. According to the results presented in the IPE submittal and the licensee's response to the RAI questions, early containment failure for St. Lucie is dominated by two CET end states (E3-R and E4-R) for PDS.3H. These two CET end states contribute over 70% of total early failure probability for St. Lucie, and both of tizm are associated with successful RCS depressurization (thus not from HPME), and with the major contributor to containment failure from overpressurization (with a conditional probability of 0.1), not steam explosion (with a conditional probability of 0.8%). HPME not a major contributor because of the high probability of successful RCS depressurization. The imccurate statement in the IPE submittal may indicate a lack of
' sufficient examination of the IPE results. Among the PDSs, early failure comes primarily from PDS 3H (high pressure PDSs, including SBO sequences, over 80% early failure probability). This is followed by PDS 2B (intermediate pressure PDS, primarily fmm small-small LOCA, about 10% early failure probability).
The conditional probability oflate containment failure for St. Lucie is 15% of total CDF '
for Unit 1 and 13% for Unit 2. According to the " Summary and Conclusions" of the IPE (Section 4.8 of the submittal),"The major contributor to late containment failures is steam overpressure in long term (hydrogen buming is likely to be precluded due to the steam '
inerted containment atmosphere)." This is not completely accurate. It fails to mention that
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the major contributors to late containment failure are CET end states associated with core concrete interaction (or coolable debris not formed ex-vessel). According to the data presented in the IPE, the probability of containment failure due to steam pressure alon (without CCl) is in general much less than that with CCI.
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According to the results presented in the IPE submittal and the RAI response, late containment failure for St. Lucie is dominated by two CET end states, C4-L of PDS 3H and C5-L of PDS 2B. They contribute over 60% of total late containment failure probability for both units of St. Lucie. End State C4-L is associated with successfu depressurization, failure ofin-vessel coolant recovery, and ex-vessel debris not coo (i.e., with CCI). End State C5-L is associated with failure of RCS depressurization, lf of in-vessel coolant recovery, and ex-vessel debris not cooled. For all late failure probability, over 90% is due to overpressure failure associated with CCI. The cont from steam pressurization alone is small.
PDS 3H is the major contributor to late containment failure (44% of all late failure for Unit 1,43% for Unit 2). This is followed by PDS 2B (26% for Unit 1,30% for Unit 2) an' PDS 2F (16% for Unit I and 10% for Unit 2). The high late failure probability for these ,
PDSs is partly due to the low in-vessel recovery probability of these PDSs'.
Source terms are provided in the IPE for 45 release modes (i.e., the CET end states). Th .
source terms for the release modes are calculated in the IPE using a combination of plan specific MAAP calculations and the parametric model developed in NUREG-115 the X-SOR program). 'Ihe approach seems appropriate and the use of plant-specific ;
MAAP calculation results in the parametric model also seems reasonable. It is noted that,l source terms calculated by the above method (with results presented in Table 4.0-7) are only for non-bypass release modes. Release fractions for bypass sequences can be obtained from the MAAP calculation results presented in the IPE submittal.
1 Sensitivity studies .were perfomied in the St. Lucie IPE for MAAP calculations only.
Although the CET quantification involves the use of assumptions and data that have l significant uncertainties (e.g., the parameters that determine the probability ofin-ve recovery and ex-vessel cooling), the IPE does not provide a sensitivity study for CET quantification to evaluate the effects of these assumptions on the IPE results (e.g.,
containment failure probabilities).
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' ' In-vessel recovery tweeludes CCI and thus the challenge of late overpressure failure associate l
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l1 E.5 Vulnerabilities and Plant Improvements Definition of vulnerability is provided in Section 2.3.3 of the IPE submittal. Vulnerability
- is not dermed for Level 2, and no vulnerabilities were identified from Level 2 analysis.
The back-end analysis did not identify the need for any plant improvements. !
E.6 Observations i
Although the licensee appears to have analyzed the design and operations of St. Lucie Plant to discover instances of particular vulnerability to core damage, there are some j
deficiencies in the IPE and the IPE submittal. The important points of the technical l
evaluation of the IPE back-end analysis are summarized below:
- The back-end portion of the IPE supplies a substantial amount ofinfomiation with regards to the subject areas identified in Generic Letter 88-20.
The St. Lucie Plant IPE provides an evaluation of all phenomena ofimportance to
[
i severe accident progression in accordance with Appendix I of the Generic Letter.
- The containment analyses indicate that the conditional p:obability of containment '
failure is 72% for Unit I and 71% for Unit 2. The conditional probability of ;
containment bypass is about 12% for Unit I and 15% for Unit 2, the conditional 1
probability of early containment failure is 1% for both Unit I and Unit 2, the i conditional probability ofisolation failure is about 0.1% for both units, and the conditional probability oflate containment failure is 15% for Unit 1 and 13% for Unit ,
- 2. ;
- There are inconsistencies in the IPE submittal. Some of the inconsistenc !
grouping of accident sequences to the plant damage states, and some are due to of the NS AC-60 study as the basis for the IPE submittal (i.e., modifications to the NSAC-60 study for the St. Lucie IPE are not reflected in the IPE submittal).
According to the licensee's responses to the RAI questions, the inconsistencies are !
mostly on the conservative side and will not change the conclusions of the IPE.
e The probability ofin-vessel recovery (i.e., core melt terminated) is high for most !
PDSs. This is due to the high probabilities of RCS depressurization, core coolant l injection recovery, and core debris in a coolable formation assumed in the IPE. In-l vessel recovery eliminates challenges to early contamment failure due to HPME and l
reduces challenges to late containment failure associated with core <:oncrete i interaction. The effects of the assumpdons related to in-vessel recovery on the overall g
' containment failure probabilities for St. Lucie are not evaluated and discussed in the IPE submittal. Sensitivity studies of these assumptions are not performed in the St. l Lucie IPE.
I e
k
- . t I
- The statement made in the " Summary and Conclusions" section of the IPE submittal '
L (Section 4.8) that "The major contributors to early containment failure for St. Lucie -
include containment threats due to HPME loads from high RCS pressure core damage accidents, steam explosion events for low pressure sequences, and isolation failures."
r i
is not really accurate. According to the results presented in the IPE submittal and the -
4
' licensee's response to the RAI questions early containment failure for St. Lucie is dominated by two CET end states for a high pressure PDS. These two CET end states l
are associated with successful RCS depressurization (thus not from HPME) and the u
major contributor to containment failureo is from _ verpressurization (with a conditiona
- probability of 0.1), not from steam explosion (with a conditional probability of 0.8%)
' HPME is not a major contributor because of high probability of successful RCS l
depressurization'. The less-than inaccurate statement in the IPE submittal may indica
^
- a lack of sufficient examination of the IPE results.
Similarly, the statement on late containment failure that "The major contributor to la containment failures is steam overpressure in long term (hydrogen burning is likely to be precluded due to the steam inerted containment atmosphere)" is not completely accurate. It fails to mention that the major contributors to late containment are CET end states associated with core-concrete interaction (or coolable debris not fo ,
vessel). According to the data presented in the IPE, the probability of containment failure due to steam pressure alone (without CCl) is in general much less than that -
with CCI.
- The licensee has addressed the recommendations of the CPI program.
9
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ST. LUCIE 1&2 BACK-END PRESENTATION j
\
I.1 Contractor Observations &
Conclusions:
j l Adequate but poor back-end analysis. CET quantification based on .
NUREG-1150 data, scoping values, and plant-specific MAAP calculations. !
However, sufficient discussions are not provided in the IPE submittal for the i
values used for some CET basic events that may have significant uncertainties and significant effect on CET results (e.g., parameters associated with in-vessel recovery). Level 2 results do not seem to be thoroughly examined. l
\
l I.2 Overall Reject or Accept Submittal: Accent with recommendations. ;
i II. RAI Evaiuation:
Adequacy of Responses: Brief, some part of questions not specifically l 4 11.1 1 addressed. Adequate but poor.
I
- II.2 Remaining Concerns: None, but see I.1 above.
III Plant Characterization:
III.1 What Drives Conditional containment Failure Probability: Early release is dominated by containment bypass (12% for Unit 1,15% for Unit 2, primarily ISLOCA); Early containment failure (1%) is dominated by overpressure failure at low pressure VB; Late failure is dominated by CCI events.
III.2 Unique Features / Issues Associated with the Plant: A reactor cavity design that facilitates flooding and a low placement of the reactor vessel.This increases the probability of ex-vessel cooling. A steel containment. No lower head vessel penetrations.
111.3 Comparisons with Similar Plants / Containment Types and 1150: Both the thermal power and containment volume are between those of Zion and Surry.
1 9/11/96
f s
ST. LUCIE 1&2 BACK-END PRESENTATION IV Licensee's IPE Review Process IV.1 Completeness Assessment: Complete.
IV.2 Methodology Assessment /Were AllImportant Phenomenology Considered? Yes. Using CET with fault trees for the quantification of CET top events.
IVJ Concems Regarding Multi-Unit Effects /As-Built Conditions Different from IPE: None.
IV.4 Adequacy of Licensee Participation and Peer Review: Adequate.
IV.5 Did the Licensee Perform Sensitivity studies? For MAAP analyses only.
I Not for CET quantification. Similar to many other IPEs, but the assumptions used in the St. Lucie IPE may have a significant effect on CET results.
V. Containment analysis Assessment:
V.1 Conditional Failure Probabilities for Early failure, bypass Failure, and Late Failure Including Main Contributors to Each:
Type Fallure Failure Probability (%) Contributors Early 1 Transient (includ. SBO)
Bypass 12% for Unit 1 ISLOCA (over 70%)
15% for Unit 2 & SGTR(about 30%)
l Independent fault tree l Isolation 0.1 analysis Late 15% for Unit 1 Transient (includ. SBO) 13% for Unit 2 & Small-small LOCA Intact 72*/. for Unit 1 71% for Unit 2 V.2 Mapping of Accident Sequences to Containment Failure Modes: By 15 PDSs for Unit 1 and 14 PDSs for Unit 2 and CETs with 8 top events.
l V3 Adequacy of Estimate for Containment Isolation Failure Probability:
Adequate.
V.4 VulnerabilitiesIdentified/PlantImprovementsIdentified: None. .
l 2 9/11/96
k
<d i
ST. LUCIE 1&2 BACK-END PRESENTATION VI. Accident Progression and Containment Behavior Assessment VI.I Important Modeling Assumptions: High probabilities of successful RCS depressurization by operator actions, recovery of coolant injection, and in-vessel recovery for most PDSs.
- VI.2 Impact of Changes Made on Containment Performance
- None.
VI3 Any Credit Taken for Operator Recovery Actions? RCS depressurization, power recovery, recovery of coolant injection.
VI.4 Codes Used for Analyzing Accident Progression and Source Terms: A parametric code similar to that used in NUREG-1150 and MAAP code for plant specific calculations.
VII. Fission Product Release Assessment VII.1 Adequacy in Relation to IPE Reporting Criteria: Adequate.
VII;2 Major Sequences Contributing to Releases: Bypass sequences.
VIII. CPI Program Assessment:
VIII.1 Were global burns analyzed? Yes.
VIII.2 Were walkdowns performed to address local hydrogen pocketing? Yes.
VIII3 Was equipment survivability addressed including recovery of failed equipment? Although there were basic events in the CET structure that seem to address this issue, the RAI response stated that the I survivability issue was not considered in the CET explicitly, but was j embodied in the MAAP analysis. l l
VIII.4 Were high temperature effects on seal considered? Yes, qualitatively (in '
I the RAI response). l 1
3 9/11/96 ,
. - . . . .. . - - -. . - - . . - .. - ._. . ~ . _ - .-. - . . - .
M I
1 3 !
I a
Front-End TER Precantation for St. Lucie Cbservations and Strengths: (1) Comprehensive treatment of plant l' 1
Conclusions specific initiating events; (2) usage of plant I i
specific data _where possible; common cause factors are generally OK; (3) results make sense and ipsights derived; (4) system descriptions; (5) utility involvement; (6) ABAO plant modeling. l gb#- ;
Weaknesses were mostly in data, paucity of PS6f'y-categories and CCF categories, RAI discussions, ATWS I modeling. (ad WW I WN*
Overall Assessment of IPE: About average Recommendation: Accept IPE RAI Evaluation Uneven Plant CDF Results comparable to other typical PWRs. Largest.
Characterisation class of accidents contributing to CDF is LOCAs.
Important contributors are various failures of HPI, tj including support system (CCW). ,Y
,J d ^, w SBO contributes about 10%. Many crossties between >
i units possible (not sure which ones credited), 8 hou battery life (only 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> credited), TD pump control post battery depleticn not credited, self-cooled EDGs, '
i power recovery factors optimistic (factor of 2-3), IE frequency seems more realistic than at other plants (0.15/yr).
Other unique features: (1) MFW pumps will continue 1
running after most transients, (2) high level of redundancy of instrument air system,'(3) cross connect l
of CST, IA, EPS, (4) HVAC relatively unimportant, (5)
Byrin-Jackson RCP seals cooled by CCW only (injection
' disconnected), requiring 10 min operator action upon CCW loss, (6) U2 operates with one block valve closed;_
(7) recirc switchover automatic (8) open plant; (9) condensate system (3 pumps) can be used < 600 psi for SG cooling.
Licensee's IPE Small event tree /large fault tree; used CAFTA.
Process Uncertainty, importance (incl. systems) and j sensitivity analyses provided. ./'
D,(, E 5 ' fof y u .,,,
C. b F Q. (Lree a... . . ,)
1
. Front-End TER Presentation for St. Lucie Accident 25 initiating events: 4 LOCAs,'12 transients, 9 support systems; additionally ISLOCA, ATWS, several Coquence Delineation and flooding initiators (5) ; frequencies generally systems Analysis comparable to other IPE/PRAs. .
Success criteria based on CE non-proprietary reports, fff FSAR, and plant-specific MAAP analyses performed for d* p IPE.
,g Containment cooling considered in front-end analysis Of needed to support core cooling for most initiators, depending on sequence. EQ effects were also considered for affected sequences.
Dependencies appear to have been suitably accounted for.
Quantitative Analysis used functional event trees.
Process Event tree sequence cutsets were quantified using a truncation value of 1.E-6 to 1.E-8, without IE (i.e.,
set to 1) and prior to recovery actions.
' Mean values were used for point estimate frequencies and probabilities.
1 i
Recovery actions were considered.
Uncertainty, importance and sensitivity analyses were provided and discussed in the Submittal and RAI Responses.
Plant experience 1/85 to 10/91 (U1) and 6/86 to 4/92 (U2) used to quantify component failure rates. Plant specific failure data comparable to values used in other IPEs/PRAs. Types of pumps, valves not "
distinguished according to service (e.g., salt water vs. fresh water) .
Generic data are comparable to generic data used in most IPEs/PRAs (TDAFW pump?). Many components use
,/)) ' generic data.
hN The beta factor method used for common cause analysis; s
data source was SAIC generic CC database. Components considered for CCF comparable to those used in other IPEs/PRAs, with some omissions (all 3 AFW pumps, ckt '
breakers, relays, inverters, switches, transmitters, solenoid valves). CCF factors generally OK.
2
l e 1 l
Front-End TER Presentation for St. Lucie ,
Issues Level 1 binning of core damage sequences into classes l
Interface of accidents was provided.
Important recovery actions considered incl,ude recovery of offsite power (optimistic). l Containment cooling / core damage interface evaluated. ;
Evaluation of Submittal discussion of DHR focuses on secondary >
DER.and Other cooling (MFW, condensate and AFW) and once through .
cooling (feed and bleed). CCW used to cool HPI, CS Cafety Issues AFW located outdoors, does not need and SDC systems.
RAI responses briefly discussed insights into broader aspects of-DHR.
No vulnerabilities associated with DHR were ;
identified.
1 Other USIs/GSIs addressed in the IPE are: none (reserve the right to add in the future).
The most important l Internal Analysis of internal flooding OK.
Flooding contributors identified. Five of the' flooding l scenarios contribute a dominant sequence.
~
Core Damage CDF results - see attached tables.
Sequence Results Systems and operator actions with greatest contribution to CDF are identified.
Licensee defined a vulnerability as a sequence causing ,
I a disproportionately high CDF contribution, or early release contribution.
4 Based on these criteria, no vulnerabilities were
' explicitly identified.
One minor procedural improvement has been implemented.
1 l
HP: p9 L le.- t ~ l.1
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l Om St. Lucie Units 1 & 2 IPE Submittal Revision 0 r
- Figure 3.7-2 St. Lucie Unit 1 Core Damage Frequency by initiator
- .,,..n.:::iiii.iiiii::::n...
30% ZZS1U1
..u n u n :::::::::n ::: n::::n:...
u n = m u' u n::n n::::n n:n:n .-
l ZZLOG 18% .
. ,. n,m, , _u, n, ,,:=,,::::::::::::
n, , , n. . . . .... . . . .: .. . . n. : n. n. . . n. n. . . ...
< umun: nun:,::n ou n:::n::nnnn:n.
.n u n n m u n m n :: o : n : n : n :; n n: n n ; n :
,,u, n,,n,,m, ..u. .n., , , u,
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.mmn====nn : m ::::::::n:::::n::n::.
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- "'unnminnmun=m
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- -"""n n n n:. :. :. .:. .: . :. .:, :. ,:, :. ,,, .:, :. ,:, :, .n. . ,: . : .: : : :. :. .: :. : :..
mu
- ,;.. c
- m;g'm u n, m,,, m u,sn,unn =, ,n,, = n:
,,,f x.
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,::: -. n ,u n, ,=, , ,n
- %j{"ly 0{,f,,
ZZAU1 15% <
,ss&,s,H,,H,5, .
. +VEn + . -
~
ass m ==-- 2% 22RU1B
.l ,,4,,,:;:G,,:f,i,t,;s;:,:,:
- v-G, =
=
2% 22RU1A
,###,,I,,#,,, " 'l 3% M 6U1
=
w ,:::
.~
//.: = - 4%
4 ISLOCA 8% ZZDC1A
- 5%
7% ZZDC1B ZZS2U1 Core Damage Frequency % of 4
Initiator Desedpdon Contdbution Total
, 22S1U1 Small Small LOCA 7.09E-06 30 %
i ZZLOG l.oss of Grid 4.llE46 18 %
ZZAUI Large LOCA 3.48E46 15 %
, ISLOCA Interfacing System LOCA l.74E-06 8%
, ZZS2UI Small LOCA 1.60E 06 7%
ZZDCIB Loss of DC Bus IB I.08E46 5%
ZZDCIA Loss of DC Bus IA 9.75E47 4%
ZZT6UI Steamline Break Downsueam of MSIVs 6.60E 07 3%
ZZRUIA SGTR S/GIA 4.29E-07 2%
ZZRUIB SGTR . S/B 1B 3.86E 07 2%
Other 1.59E 06 6%
Total Freq: 2.3E45 l
3.7 27 of 67
- _ _ _ . _ _ _ _ ~ _ _ _ __
i 3
St. Lucie Units 1 & 2 IPE Submittal Revision 0 i
Table 3.7-2 St. Lucie Unit 1 Core Damage Frequency by initiator Core Damage Frequency % of Initiator Descript;on Contribution. Total ZZSIUI Small Small LOCA 7.10E 06 31% i ZZIDO Loss of Grid 4.08E-06 18 %
ZZAUl LnBe LOCA 3.49E 06 15 %
ISLOCA Interfacins System thCA . 1.74E-06 8%
ZZS2UI Small LOCA 1.60E 06 7%
ZZDCIB Loss of DC Bus IB 1.10E-06 5%
ZZDCIA loss of DC Bus I A 9.90E-07 4%
ZZT6UI Steamline Break Downsavam of MSIVs 6.60E 07 3%
ZZRUIA SGTR - S/O I A 435E47 2%
ZZRUIB SOTR - S/O IB 3.90E47 2%
ZZCCWUI Loss of CCW 2.83E-07 1%
ZZT3CUI LOFW - Not Recoversbie 2 38E-07 1%
ZZT751UI Spurious SIAS 1.91E-07 1%
ZZTIUI Reactor Trip I.80E 07 1% .
ZZT3AUl LOFW Recoverable 9.95E-08 <l%
22T2UI Reactor Trip (PORV Challen84 9.49E-08 <t%
ZZT5UIA Upstream Steamline Break S/G I A 8.90E.08 <!%
Z2T5UlB Upstream Steamline Break S/O IB 8.55E 08 <l%
~
ZZlCWUI Loss of ICW 8.06E 08 <l%
ZZT3EUI Excessive Feedwater 6.82E 08 <l%
ZZIAUI Loss ofInstrument Air 6.08E-08 <l%
ZZT3AUI PORV Stickin8 Open S/O l A 3.75E-08 <l%
ZZTBBUI PORV Stickin8 Open S/O IB 3.74E 08 <l%
ZZT7MSUI Spunous Main Steam isolation 231E-08 <t% '
ZZMAUI Loss of Instrument Bus IMA 439E 09 <l%
ZZMBUI loss of Instrument Bus IMB 4.39E 09 <t%
ZZMCU1 Loss of Instrument Bus IMC 434E 09 <!%
ZZMDUI loss of Instrument Bus IMD 434E-09 <t%
ZZ4KVIB2 Loss of 4kV Bus 182 835E-10 <t%
ZZ4KVIA2 Loss of 4kV Bus I A2 4.0$E-10 <t%
ZZT3DUlA Feedline Break S/O IA 2.81E 10 <!%
ZZT3DUlB Feedline Break S/O IB 2.72E-10 .:l%
ZrrCWUI Loss of TCW 2 50E 10 <l%
ZZT3DUI Feedline Break (Common) 2.34E 10 <!%
ZZ6KVI AI Loss of 6.9kV Bus I AI 9 54E ll <l% l ZZ6KVlBI Loss of 6.9kV Bus IBl 9.54E ll <l%
ZZT4B Loss of Offsite Power "B" Train 638E 12 <!%
ZZT4A loss of Offsite Power "A" Train 438E 12 <1%
Total Freq: 2.32E 05 3.7 28 of 67
, I m St. Lucie Units 1 & 2 IPE Submittal Revision 0 -
1 I
l Figure 3.7-1 St. Lucie Unit 1 Core Damage Frequency by Sequence l U1TBF 16%
t U1S1U 12% 19% U1S1X 1
U1TBFB 11 % 6% OTHER
- i 2% U1RDX
- 3% U1S2U U1AU 10% 4% U1S2X 4%
5% U1TQX ISLOCA 8%
U1AXc Core Damage Frequency % of Sequence Description Contribution Total UtslX Small Small LOCA w/ tons Term Core Coolmg Failure 434E46 19%
j UlTBF Transent w/ Shy Heat Removal and OTC Failure (Non-Blackoup 3.72E46 16%
l UlslU Small-$ mall LOCA w/inpcuan Failure 2.74E46 12 %
UlTBFB Transwat w/ Secondary Heat Renmal and OTC Failure (Blackoup 2.64E46 11 %
l l
UIAU Large LOCA w/inpcuan Failm 2.37E-06 10 %
ISLOCA laterfacing Systern LOCA 1.74E46 8%
l UIAXC Large LOCA w/ Cold Leg Recirc Failure 1.12E46 5%
! UlTQX Transent w/ Loss of RCS Integnry and Long Term Core Cooling Failure 931E47 4%
UlS2X Small LOCA w/Long Term Core Cooling Failure 9.29E47 4%
UIS2U Small LOCA w/inpcuon Failure 6.72E47 3%
UIRDX $GTR w/ Failure to Termmar leakage and Long Term Core Coolms Failure 4.70E47 2%
i Other 1.48E46 6%
Total Freq: 23E0$
3.7-25 of 67
S t
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0
Human Reliability Analysis (HRA) Review IPE for St. Lucie Nuclear Power Plant (Units 1 & 2)
Presented by John Forester September 11,1996 f SandiaNadonallabmalmies HR A-1 .
St. Lucie Nuclear Power Plant IPE HRA Overview
- Overall Impression Of This HRA Submittal
- Average 1
e HRA Plant Vulnerabilities
- None Identified o Plant improvements Identified Based On IPE Results
- Implemented new AO to have operators fill CST from treated water storage tank when long-term operation (beyond 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />) of AFW is demanded.
I SaifeNdomitaboratories
~
HR A-2
. .i
St. Lucie Nuclear Power Plant IPE HRA Overview-(Continued?
e Licensee Participation ]
The HRA portion was performed entirely by utility personnel. The methodology was acquired from SAIC and used by FPL for Turkey Point and St. Lucie.
Electric (Level 1) contributed to a broad review of the entire PRA. Frank Hubbard from FRH and Niall Hunt from NUS were cited as reviewers knowledgeable in HRA. -
HMA 3 l SahNadoidlabordaies
Pre-Initiator Human Events
- Types of Pre-initiators Considered
- Pre-initiator Slips
- Restoration after test, maintenance, or operational alignment l
- Miscalibration ,
- Identification Process .
- The systems analysis procedure directed analysts to include miscalibrations if, '
based on their understanding of the system design and operation, there were l
failures which could be significant contributors to the CDF
- Maintenance, operating, and test procedures were reviewed. If the analyst determined that the maintained system, train, or component is not completely tested for its design function following maintenance, a failure to restore event was added to the fault trees. They were not modeled only if the components are realigned to correct configuration following a system actuation signal.
HM A-4
Pre-Initiator Human Events (Continued) ,
e identification Process (continued)
- HRA focused on actions that might lead to failures of multiple trains of equipment, thus acting like common-cause failures." ,
- Treated miscalibrations of all like instruments as common-cause.
e Restorations modeled at train level - e.g., AFW pump 1 A manual valve.
Assumed maintenance etc. on separate trains was independent HR A-5 i
Pre-Initiator Human Events (Concluded) 1
- Screening Process for Pre-Initiator Human Failure Events (HFEs)
Pre-initiator HFEs (modeled in fault trees) were screened at a nominal value of -
0.003 (per SAIC method used value from THERP). A beta factor of 0.1 is applied for multiple train events (miscalibrations only).
- Licensee noted that the screening values were consistent with those used in another IPE found to be acceptable by the NRC e Quantification Process (SAIC Method)
- No additional quantification beyond the screening analysis.
- Since only the screening analysis was performed, PSFs , self-recovery, and personnel redundancies / dependencies were not credited. Human common cause potential was evaluated.
- Relative to some IPEs, pre-initiator HEPs would be somewhat pessimistic Si H ill b (il1011ll1 8 1S HR A-6
___-__ _ Q
Post-Initiator Human Events
- Types of Events Considered
- Time-independent post-initiator slips
- Untimely responses (time-dependent): both in-control room and ex-control room
- No explicit distinction between response and recovery was initially made in IPE. In response to RAI, response and recovery events were retrospectively categorized (quest. 7). i i
t k
HRA-7
r .
Post-Initiator Human Events ;
(Continued) !
- Identification Process :
- Response to RAI documents a reasonable process. Interviews with plant
' operations and training staff and reviews of EOPs, operating experience, other !
PRAs, and NRC PRA reviews were conducted. This info used in accident l
sequence and systems analysis task. Accident sequence event trees and top l
logic fault trees were developed. Human actions related to system operation were included in the top logic fault trees.
- RAI indicated that events that fit into the recovery type were primarily ,
i identified during cutset review.
l t 1
i
, 1 l
1
[
HR A-8 I t
e .
i Post-Initiator Human Events ~
(Continued) e Screening Process - None, human action events were set to 1.0 for initial quantification. j i
- Quantification - Two Techniques
- - Time-independent (similar to general application of SAIC time-independent model, but generally more thorough than most (see attachments 3,4, 5, and 6 of response to RAI for examples) :
- A basic human failure probability from NUREGICR-1278 of 0.003
= A ' dependency factor for other personnel, or a default of 1 (in the-j examples i examined, only took credit for one " recovery" and usually assumed high dependency (0.5). If moderate dependency was assumed used 0.14, if Iow, 0.05. .
. PSFs were multipliers based on NUREG/CR-1278 and the analyst's ~
judgment. PSFs were only used to increase HEP (see Tables 3.4-2 and '
3.4-3 of the submittal) i, b
HRA-9
m Post-Initiator Human Events LContinued)
- Quantification -- Time-Independent Post-Initiator Slips (continued) J Problem:
- Assumes time is not a factor end (at least in principle) that diagnosis failure is negligible (see question 13).
- Approximately 50% of post-initiator events were treated as slips.
- Analysis appeared thorough and conscientious (reasonable application of PSFs such as stress etc.) and values did not appear to be unreasonable. "
= Yet, approach parallels the IPEP method somewhat in that diagnosis is not explicitly quantified in these cases, if it is clearly indicated by orocedure. Most other applications of the SAIC method that I have reviewed modeled (at most) only a couple post-initiator slips. ;
[
= For example, once-through-cooling failure is treated as a slip.
j'
- Major difference between this and IPEP is reasonableness of HEPs, apparent level of analysis, and clear documentation.
[
L
~
u i
Post-Initiator Human Events .
CContinued) -
e Quantification (continued)
- Time-Dependent - Standard SAIC TRC approach
-
- In-control room technique makes use of the following parameters:
i Net available time as the difference between total available time and other times as human factors considerations require
- A type factor: 0.25 for verification actions; O.5 for rule based :
actions; 1 for others
- A success likelihood factor to reflect various performance i shaping ~ factors, or a default value of 0.5 which was done for this HRA
- A burden factor: 1 with no burden; 2 otherwise
- A model uncertainty factor, fixed at 1.68 f SandiaNationallaboratories HR A-11 i
Post-Initiator Human Events (Continued? .
e Quantification - Time-Dependent (continued)
- Ex-control room technique makes use of the following parameters:
Net available time as the difference between total available time and
- l. other times as human factors considerations require l
1 - An estimate from operations personnel's judgment or walkdowns of the expected time to locate, access and manipulate the equipment i - Additional time to reflect the potential delaying effects of specific types of ex-control room hazards
- A model uncertainty factor, fixed at 1.68 i
N'
_. m
Post-Initiator Human Events t (Continued?
i .* Quantification " Notables"
- Apparently used some actual estimates of median response times for in- ,
control room actions (attachment 9).
- Developed time lines for events and considered occurrence of cues (quest 15)
! - Where HEPs for same events might vary as a function of sequence, assumed I
worst case.
t
- - Some walkdowns occurred, but most response times estimated by operators
- Considered sequence-specific dependencies (quest 17 and 18)
- Modeled 2 non-proceduralized acts. for unit 1 (no data for unit 2). (quest 17)
- For time-dependent modeled events, assume default SLI, thus assumed plant ;
average in terms of PSFs. Similar to most IPEs which used this method.
i MNM HRA 13 t
l l t l
I Internal Flooding l e Some Operator Actions Apparently Considered, e.g., Terminate Flood.
t i
No numerical credit was taken for special human actions discussed in l l submittal (level 1 question 14)
- Seemingly, credit was taken for events already in model (e.g., trip caused by '
flooding) and values were not adjusted (no additional stress for flooding etc.)
I i
M HR A-14 i
% 9
Level 2 Analysis l
l
- Recovery actions considered in level 1 were directly incorporated into PDS cutsets
~
e Apparently adjusted some LOSP recovery values
- Modeled operator actions to depressurize RCS - estimated HEP at 0.01 from in-control room TRC - proceduralized action
- Credited several other recovery actions - assigned " scoping" values of 0.5 to 0.05. (Quest. 9)
Nbbib HR A-15
~~
St.Lu e 1 2 Important Human Actions, Per F-V
- 3. Operator falls to restore power to Unit 1 from unit 2 -2.5% of CDF
- 4. Operators fall to do once through cooling for transient (Feed and Bleed) --
2.3% of CDF
- 5. Operators fall to restore pump 1 A after maintenance - 1.6% of CDF
- 6. Operators fail to restore pump 1 A after maintenance -- 1.5% of CDF
- 7. Operators fall to restore electrical equipment room fans following LOOP -
1.5% CDF
- 8. Operators fell to do once through cooling for SGTR (Feed and Bleed) -- 0.7% .
of CDF 1
l-, St. Lucie Units 1 & 2 IPE Submittal Revision 0 i
TABLE 3.41 j
' ' ~
PRE-INITIATOR HFE EVENTS t
HPE BASIC *
- TM Fall.URE EIUtOR '
l UNIT- EVENT DESCIUPTION MODE PROBASIUTY FACTOR 1 AHPL109108 APW PUMP 1 A MANUAL VALVE V09100 MISP. ~'
SWP 3.00E43 ~
10 f osmONED :-
i I AHPL109124 APW PUMP IB MANUAL VALVE YO9124 MISP. SUP 3.00E43 10
! OSTI'lONED I 1 AHPL199140 APW PUMP IC MANUAL VALVE V0pl40 MISP- '
SUP, ' 3.00E43 10 5 l< 3 BHPLILYL COMMON CAUSE FAILURE OF SFT*S DUE TO SUP, 3.00E 04 10 MISCAuBRAnON OF SrT Unm. SENSORS I
I BHPLIPRS' COMMON CAUSE FAILURE OF StT'S DUE10 --
'SUP 3.00E 04 10 MISCAUBRAMON OF SIT PRESSURE SENSORS
} l DHPLlHYSIA OPERATOR PAILS.TO RESTORE HVS 1A. . POL - .
SUP- - - 3.00E43 10 ,
I I DHPLlHYSIB OPERATOR FAILS TO RESTORE HYS IB POL. -- SUP -* 3.00E43 10 .
-' . IDWMO MAINHNANCE'- 5*
l 1 1 I DNFLlHYSIC OPERATOR FAl1J 1D RESTORE HVS IC -- - -- SUP 3.00E43
- 10 l
e egyg.2 ' '* ' ' ' A '# I - l t
I DHPLlHYSID OPERATOR FAILS TO RESTORE HYS ID POLE - SUP - 3.00E43 10
. IDWDIO MAINNNANCE% di 4 ' #- )
. I
- I I EHPLIEDOIA OPERATOR FAILS.10 PROPERLY ALMM POL - . SUP - - - 3 00E43 10 1 G
gyWING MAINMPIANCEC ? ': ? 10 h* * ** ' -
I I EMPLIEDOlB OPERATOR FAILS TO PROPERL AUON POL ~ -- ' SUP- - 3.00E43 10 O);
IDWING MADfTEPIANG *~* " 'Ji " - 1
/ I OHPLIPUMPA OPERA 1DR FABJ.70 RESTDRE PUMP 1 A 700 - SUP 3.00E 03 ' 10 ~,
j i - - - - -
, . uyWm0 MADmDIANCE .i &~d UI '~d ' f ' " '
I OHPLIPUMPB <- - SUP- -- 3.00E43 10 l
{ -- -- OPERATOR
_FAILSJO RESTORE PUMP. I,B POL- e
- upwmo uslynu m n g.ar o ,w -
! I HHPLIS13YA
- - - ~
OPERATOR FAILS TO PITT CTWT AIR COMPRES. -- SUP" -
- 3.00E 03 - - 10
, SOR lA W STANDBY ' 7 '-i & 4 C' ' ' "
1
- SUP-I HHPLISTBYB OPERATOR FAILS.TO.PIJT CTMT AIR COMPRIS. 3.00E43' 10
~ ~ ' " '
,, . SOR 13 W STANDBY,'s C '* *H M "W ~ IJ'
'~*
I HHPLISTBYC
' ' ' ~ " ~ ~ OPERAW6ItJ.1Dftfr. AIR COMPRESSOR - - SUP ---- . 3.00E43 to"
- , e. . . N i ICIN STANDBY & .CUA Y U 9'M i i E' -
, J
! I HHPLIST3YD OPERATOR FARJ.TO.PITT AIR COMPR8 tens- -- SUP- 3.00E43 ' 10 't
' I ~~ ~ ~~" ~I ra N T ID IN STANDBYJOS. MDUA y.11 M rJT D # '
- i
- 1 JHPLIPUMPA OPERATOR FAILSJ0. RESTORE PUMP 1 A FCE., ---SUP-- c 3.00E 03, - 10 * '
1 ----, ." ,, ~Q)WWO MADfMMANGo wp a :TESA GT U , A
~ ~ ~
$ 1 JHPLIPUMPB OPERATOR FAILS lD, RESTORE PUMP.13 POL, L SUP - - 3.00E 03 -
~ ' ' 10'" ~
, - ;l - ' d)WWO MAINTEPIANCE?! W.M S. **W UT 8 !-
~ ' ' ~
. I JHPLISDA- - -
OPERATOR FABJJU. RESTORE 3DC HX Idi '-- SUP- -- 3.00E 03 - 10 *
' ~h MAIPrTENAPICE N * ~'- ~ ' N C" ? ~
l JHPLISDB OPERATOR.J,AR310 RESTURE SDC HX IB -. '-- SUP --
- 3.00E43 '
- . ;.10 -
- i
, 7 P0uDWWO MADf!ENANGM.~' 8 'TM CT l ~ *
~
, I OPEIULTUR FAILS.,lDfROPERLY_RES1DRE CS' - -- SUP -~ - 3.00E 03 ' , , 10 .
LHPLIPUMPA-
- - ~
FUW A POUDWING MADffENANGM i 9 '"' T I '
~' ~ *~ ~
l utPuPUMPB OPERATOR FAILS TO PROPERLY RESTORE C5. SUP-- 3ADE 03 10
- c}..,
FUWB POUDWING MADffENANCE S T "W G 1 " -
1 MHPUV2154 VALVE V2154 LEPT MISP05mONED.. . . - SUP--- 3.00E 03 to Pm6WrNO M 9,, N NG i'
I
( 3.4 7 of 13 l
1
- _- .- -. -.- .-~ - .. -- - - . . - - - . . -- -- . .-.-.-
- St. Lucie Units 1 & 2 IPE Submittal Revision 0 +!
t O
l TABLE 3.4-1 PRE-INITIATOR HFE EVENTS
(
, HPE BASIC .
FAILURE ERROR
.w UNIT EVENT DESCIUPTION .
MODE PROSABILrry FACTOR I* MHPLIV215$ ' VALVE V2iS5 LEFT MISPOStrlONED SUP 10
- *3J10E43 i 70uhWMO MANTENANCE t
- I NHPLIPPCCF COMMON CAUSE MISCAUBRATION OF PRES. . SUP 3.00E44 10 +
t SUIUZER PRESSURE'!RANSMrTTERS l 1- NHPLIRWu"F COMMON CAUSE Wea8 fBBaTION OF THE SUP 3.00E44 10 ;
RWT LEVELTRANSMITTERS I NHPLISOPCF COMMON CAUSE uneat vanaTION OF THE SUP 3mE 04 10 .
STIAM OBERATOR PRESSURE a .. .
- .. TRANSMrTTERS . '
I NHPL1CPCCF COMMON CAUSE wean ene a110N W THE , SUP
- * * ~ '
3mE ~04 '
30 ., I CONTAINMENT PRESSURE TitANSMITTERS'" ,
I NHPLICRMCF COMMON CAUSE MISCAUBRATION OF115 SUP 3 00E. 04
. . . . 10
. CONTAINMENT RADIATION MONITORS * . .
2 AHPL209108 'APW PUMP 2A MANUAL VALVE V09108 SUP
~~' *- ~3.00E 03 ' ' 10..
- 1.- MISPOSI'!10NED -" ' *- ~~~ ' '
2 AHP1.209134 APW PUMP 2B MANUAL VALVE V0pl24 'O o
. . .. . . .- MISPOSmONED -- -
-" ~ S.UP 3 00..E 03.-
.. 10 -
.o, 2 AHPL30pl40 APW PUMP 2C MANUAL VALVE V0pl40 . .
'SUP-
"' ~ ~ ~ ~ ~
3.005' 03 * . 10 .
. .- . - -- MISPOSTIlONED * ~ ~ " ' '
~'. . ,
2* BHPL2LYL COMMON CAUSE FAILURE OF SIT *S DUE10i .**SUP 3mE 04 10_ .
E ME.
- MISCAUBRATION OF SIT LEVEL SENSORS"" *~*"~~-~7.".' .*
' "% 2 BHPL2 PRS COMMON CAUSE FAILURE OF Str*3 DUE 10 * . .+. SUP' 3J10544 ' ^ 30. .
~~~ ~ ~~~~ .
user.as ann aTION OF SIT PRESSURE SENSORS . ~~.~~
2; DHP12NV31A OPERATOR FARJ10 RESTORE HYS IA 700 : Ti'.O SUP ,,,3J10543, _._,.10. . ..
.....; ~~~ " ' *
.. -- IDWING MAINTENANCE "~. . , . u. '
2 j DHPL2HYSIS OPERATOR FARJ TO RESTORE HVS IB .L' ',% SUP* 3.00E43,. ... 10. _ ._.
I~ .- in.
._ . . /. - -PouDWING MAINTENANCE * . ~'"~'.~.' .
2 DHP12HYSIC OPERATOR FAILS TO RES"IURE HVS IC .
SUP~ ~3.00E43 _ , _ _. 10_.. - . . . . .
. . . . . . . . _... PouDWINO MAIN!ENANG * -* . -
. . r 2 DHPL2HYSID OPERATOR FAILS 10 RFSTORE HVS ID POL, SUP ,,, 3J10543_.,, _ .10 _ . ..
- 1DWING MAETENANCE . . ""~.~. *~ ,,,, , . - - . . s .. ..
2 EHPL2EDO2A OPERATOR FARJ TO PROPERLY AUON POL.' 3'*~SUP- 3.00543 10 .-
. . - 1DWING MADfrENANCE. .,. , .'" '".**.~7~~~~~ orvi. IM,. , '
7tn ~ ' . + !
2 Oret'ATUR FAE.S TO PROPWtLY AUON pot / 3.00E EHPt 'NSE. M' S_UP 10 ... ..
~
IDWING MAINTENANCE. . . . . . , . 3,,,-,. . .,.v .4. 3 8t 4, .
P 2 GHPL2PUMPA OPERATOR FAILS TO RESTORE PUMP 1A POtk f~
i SUP2 *,,,3J10E43 _JO_. .- ,
IDWING MAINTENANCE:." . . . e m .. , . r r -.< . . cr s + w :. i.
2 GHPL2PUMPB OPERATOR FARJ 10 RESTORE PUMP IB POLE
- A '. . SUP :' _ ' _3.J10E43_ ., . _ _. 10_ _.
- 1DWING MADffENANCE ... .,. ;~.' . . , . , , . . .. .. -. 4 2 HHPL2STBYC OPERATOR F, AILS TO FUT AIR COMPRESSOR /
SU.P ' 3. mE..q3._, 10.
T.lc IN STANDSY ,f,. ',l .,.,e..
o,.' .m e ..v3 . -
2 HHPL2FrBYD ..
OPERATOR F. AILS TO FUT AIR COMPeetene . S.U._P .*N 3.J10E-(13- 10 .-
y..
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- 3.00E43. _ . _.10. .. . .-
IDWINO MAINTENANG *.f.~. ~'~ ".*" ..e. . , . ~ , sa . *% ., *
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.? 2 JHPL2PUMPB OPERATOR FAILS 1D RESTORE PUMP 2B POL /
- 1DWING MAINTENANCE ' "' ~"
N' O SUP , ,
i 3.00E43. __. 10 ,
. ,. .. . - . 1- . - - - -
- 3.4 8 of 13-i' i
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' Revision 0 St. Lucie Units 1 & 2 IPE Submittal 4
i q i-TABLE 3.4-1
! O a-C# PRE INITIATOR HFE EVENTS .
t
- FAILURE ElutOR .
HPE BASIC l UNTT EVENT . - - DESCRIFnON
- MODE ~ PROEABILTTY FACTOR
SUP 3.00E43 10 l 2 JMPL2SDCE OPERA 1DR PAILS 10 RESIDRE SDC HK 2B - !
POLLDWING MAINTENANCE i
- 10 i SLIP 3.00E43
- 2 L3fPL2PUMPA OPERATOR PAILS TO PROPERLY REETORE CS
- l PUhr A POU.DWING MAINTENANCE .
f SUF 3.00E43 10 ,
2 LHPL2PUMPB OPERATOR FAES 70 PitOPERLY RESTORE CS
- I I
f i
PUMP B POUDWINO MAINTENANCE .
10 I
- SUP 3.00E43 2 LtHPL2V2154 VALVE V2154 LEFT MISPOSTDONED ' ' '
j POuDWING MAINTENANCE
.~~'
l E' 7$UP 3.00E43 10 .
2 MHF1.1Y2155 VALVE V215512PT MISPOSTI10NED
.I
- POLLOWING MADf!ENANCE SUP 3.00E44 10 2 NHP12PPCCF COMMON CAUSE uw ai see aT10N OF PgtES. '
' SURIZER FIWSSLEtETRANSMITTERS .
COMMON CAU$g userat van aTION OF THE SUP 3 AGE"' 44 10 ~
' 2 NHPL2RWLCF '~~~ ~ ' ~ ' * -
- RWT LEVEL 1RANSMITTERS'" "'
SUP . 3.00E 04 to 2 COMMON CAUSE MISCAUBRATION OF THE NHPL2SPCCF" * *
. STEAM OENEATOR FIWSSUltE .
i
. TRANSMI1TERS.1 ' i .
- 'i I2 2 NHPL2CPCCF . COMMON CAUSg useras som aTION OF11E . . i ' SUP
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TABLE 3A-3 (Cont'd) ST. LUCIE UNIT 2 POST-INITIATOR HFE UPET RKOVWY 1389CBFfMPs FeOSABEJTY maOR LOCATWM PARISE PW TTPR tF M REIWe NESPOMBE AVAEASLS TIndeuG EVALt9ATION U)
Evfuer FACTOR OF ACTIcee 98DDR gmeAVIOR TBIE ttdRet 1988(Gemel SOURCE TYPE I*
3 R1tFISIOfC OPMATOR FAR3 TO DetTRATE -TJW49 90 38 G Er I ps4 esA sea geA tea MS ONCE.T55tOUtMMWE E00 FOR 98 LDCA n pea M4 O
3 31tF351ACP OPERATOR FAILS 10 SKURE SCF"S 3 M 46 30 MG 3Lp 3 pea pgA NA 30U POL 10mMO LDSB OP SEALCootA80 d 3 R1trtTUTC OPERATOR FAR310 98tTIATE DMCE 1.BBB40 IS MG SLF S tea ftA 90 4 MA NA NU TIGOUEM COtXDeG FOR TRAfWWET Dd 3 R10Pf*SOR OPERA 1tIR FAES10 stRAft $3421980 ATWS GEE 49 N M CR SLP 4 MA 94 4 MA feA MA leu ,
w tamMO sounct Rev: av4LUATMNe TTPS REP.
t . OPERATOR EST94ATS ffU . IgUb4AM L*J t
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