ML20141L897
| ML20141L897 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 05/28/1997 |
| From: | Wetzel B NRC (Affiliation Not Assigned) |
| To: | Richard Anderson NORTHERN STATES POWER CO. |
| References | |
| NUDOCS 9706030129 | |
| Download: ML20141L897 (17) | |
Text
4 Q,mg go-2 P2 p
UNITED STATES i
S NUCLEAR REGULATORY COMMISSION
'f WASHINGTON, D.C. 20666-0001 May 28, 1997 a
Mr. Roger O. Anderson, Director Licensing and Management Issues Northern States Power Company 414 Nicollet Mall Minneapolis, Minnesota 55401 i
SUBJECT:
REV!EW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF OPERATIONAL EVENT AT PRAIRIE ISLAND NUCLEAR i
GENERATING PLANT
Dear Mr. Anderson:
Enclosed for your review and comment is a copy of the preliminary Accident Sequence j
Precursor (ASP) analysis of an operational event that occurred at the Prairie Island Nuclear Generating Plant on June 29,1996 (Enclosure 1), and was reported in Licensee Event Report (LER) No. 282/96-012. This analysis was prepared by our contractor at the Oak Ridge National Laboratory (ORNL). The results of this preliminary analysis indicate that this i
condition may be a precursor for 1996. In assessing operational events, an effort was made to make the ASP models as realistic as possible regarding the specific features and response of a given plant to various accident sequence initiators. We realize that licensees may have additional systems and emergency procedures, or other features at their plants that might affect the analysis. Therefore, we are providing you an opportunity to review and comment on the technical adequacy of the preliminary ASP analysis, including the depiction of plant equipment and equipment capabilities. Upon receipt and evaluation of your comments, we l
will revise the conditional core damage probability calculations where necessary to consider the specific information you have provided. The objective of the review process is to provide 4
q as realistic an analysis of the significance of the event as possible.
In order for us to incorporate your comments, perform any required reanalysis, and prepare the final report of our analysis of this event in a timely manner, you are requested to complete your review and to provide any comments within 30 days of receipt of this letter.
We have streamlined the ASP Program with the objective of significantly improving the time after an event in which the final precursor analysis of the event is made publicly available.
As soon as our final analysis of the event has been completed, we will provide for your
[
information the final precursor analysis of the event and the resolution of your comments. In previous years, licensees have had to wait until publication of the Annual Precursor Report
/
(in some cases, up to 23 months after an event) for the final precursor analysis of an event
(()
and the resolution of their comments.
We have also enclosed several items to facilitate your review. Enclosure 2 contains specific guidance for performing the requested review, identifies the criteria that we will apply to determine whether any credit should be given in the analysis for the use of licensee-identified additional equipment or specific actions in recovering from the event, and describes the specific information that you should provide to support such a claim. Enclosure 3 is a copy of LER No. 282/96-012, which documented the event.
9R0 FR.E CENTER COPY
==
9706030129 970528 PDR ADOCK 05000282 S
l
< z R. O. Anderson
-2 May 28, 1997 Please contact me at 301/415-1355 if you have any questions regarding this request. This l
request is covered by the existing OMB clearance number (3150-0104) for NRC staff followup review of events documented in LERs. Your response to this request is voluntary and does l
not constitute a licensing requirement.
l Sincerely, Original signed by Beth A. Wetzel, Project Manager Project Directorate lll-1 i
Division of Reactor Projects - lil/IV Office of Nuclear Reactor Regulation Docket Nos. 50-28:2 and 50-306 j
Enclosures:
- 1. Preliminary ASP Analysis'
~
- 2. Review Guidance
- 3. LER No. 282/96-012 l
cc w/ encl:
See next page DISTRIBUTION w/enci:
Docket File PUBLIC PD3-1 Rdg J. Roe OGC ACRS J. Jacobson, DRP/RI l
S. Mays, AEOD l
P. O'Reilly, AEOD -
W. Beckner, w/o encl.
DOCUMENT NAME: G:\\WPDOCS\\ PRAIRIE \\PIAEOD.LTR To r.c.iv.. copy or ini. oocum.nt, indic.t. in in. box: c copy witnout ettacnmentrenciosure fe = copy with attaenmentrenciosur. w No copy J/
p
/
OFFICE PM:PD31
,_)
E LA:PD31 C
D:PD31 NAME BWetzel:dyf4!
CJamerson @
JHannonQ DATE 5/g97 5/27/97
(/
5/$/97 OFFICIAL F,ECORD COPY
_~
?,
Mr. Roger O. Anderson, Director Prairie Island Nuclear Generating Northem States Power Company Plant cc:
J. E. Silberg, Esquire Site Licensing Shaw, Pittman, Potts and Trowbridge Prairie Island Nuclear Generating 2300 N Street, N. W.
Plant Washington DC 20037 Northem States Power Company 1717 Wakonade Drive East Plant Manager Welch, Minnesota 55089 Prairie Island Nuclear Generating Plant Tribal Council Northem States Power Company Prairie Island Indian Community 1717 Wakonade Drive East ATTN: Environmental Department Welch, Minnesota 55089 5636 Sturgeon Lake Road Welch, Minnesota 55089 Adonis A. Nebiett i
Assistant Attomey General j
Office of the Attomey General j
455 Minnesota Street l
Suite 900 l
St. Paul, Minnesota 55101-2127 U.S. Nuclear Regulatory Commission Resident inspector's Office l
1719 Wakonade Drive East Welch, Minnesota 55089-9642 l
Regional Administrator, Region Ill I
l l
U.S. Nuclear Regulatory Commission 801 Warrenville Road Lisle, Illinois 60532-4351 1
Mr. Jeff Cole, Auditor / Treasurer Goodhue County Courthouse l
Box 408 l
Red Wing, Minnesota 55066-0408 Kris Sanda, Commissioner Department of Public Service 121 Seventh Place East Suite 200 St. Paul, Minnesota 55101-2145 4
l November 1996 s
ir s
r, LER No. 282/96-012 1
l 1
I LER No. 282/96-012 Event
Description:
' Loss-of-offsite power to safeguards buses on both units 1
Date of Event: June 29,1996
]
i j
i Plant: PrairieIsland I and 2 j
Event Summary I
Both units were operating at 100% power on June 29,1996. Strong isolated thunderstorms caused the failure i
of three 345 kV offsite transmission lines to the plant substation. Both unit reactors tripped in response to j
a loss of load. All four emergency diesel generators (EDGs) started as expected. Both Unit 2 safeguards a
buses and one Unit I safeguards bus were immediately powered by their respective EDGs. A single 345 kV i
transmission line continued to supply power to the plant substation, the Unit I normal buses, and one Unit I safeguards bus (bus 15). However, the voltage supplied by the single offsite power supply line was so unstable that approximately 7 min after the trip, bus 15 automatically transferred to its associated EDG. A stable offsite source was not reestablished for approxunately 5 h and both units were cooled by natural circulation until after that time. The estimated conditional core damage probability (CCDP) for this grid-d based loss-of-offsite power (LOOP) is 2.6 x 10. This CCDP estimate is applicable to both units.
Event Description l
On June 29, 1996, at approximately 1418, the Blue Lake 345 kV transmission line tripped off-line and j
remained off-line following a single phase-to-ground fault resulting from a passing thunderstorm. Both units remained at 100% power following the loss of this offsite connection to 345 kV bus 1 in the plant substation, shown in Figure 1. Approximately 11 min later, at 1429, severe weather with " straight-line" winds destroyed
'several support structures causing three phase faults in both Red Rock lines. Both Red Rock 345 kV lines tripped and stayed out. At this point, only the Byron 345 kV line remamed in service to 345 kV bus 2 in the Prairie Island switchyard. Both unit generators were aligned to 345 kV bus 1 and subsequently tripped from 100% power due to the loss ofload. All reactor coolant pumps (RCPs) on both units tripped as a result of low frequency resulting in decay heat being removed by natural circulation cooling only.
All four EDGs started as designed on loss-of offsite power. Safeguards buses 16 (Unit 1) and 25 and 26 (Unit 2 ) were immediately sequenced onto their respective EDGs. Safeguards bus 15 (Unit 1) continued to be supplied from offsite power via the Byron line. Voltage on the Byron line was low and unstable, and Safeguards bus 15 automatically loaded onto EDG D1 approximately 7 min after the reactor trip. Unit I normal 4 kV buses (non-safety related) transferred to the IR transformer supplied from the 345 kV bus 2 via the Byron line and continued to be powered from this unstable source throughout the event. Unit 2 normal 4 kV buses transferred to the 2R transformer supplied from the 345 kV bus 1, which was deenergized. The licensee declared an Unusual Event.
At approximately 1800, the Unit 2 normal 4 kV buses were powered from 345 kV bus 2, which was 611 in a degraded voltage condition (below 330 kV). At 1925, voltage on the Byron line was restored to vjthin the l
1
~
j
m
_.____.m.
p, l
LER No. 282/96-012 normal range after the utility purchased additional power and reset transformer taps in the switchyard. Since all EDGs were operating satisfactorily, emphasis was placed on restoring forced circulation cooling in both units rather than transferring the safeguards bus power supply to the appropriate offsite source. This priority was established because, in the event of an EDG failure with an offsite power source available, the load sequencers would have automatically transferred safeguards bus loads to the offsite power source. At 1953, forced circulation cooling we.s established in Unit 1. At 2028, forced circulation cooling was established in Unit 2.
On June 30,1996, at 0135, the Blue Lake 345 kV line was restored. The process of transferring the safeguards buses from the EDGs to an offsite power source began at this point and was completed at 1035.
The licensee exited the Unusual Event at this point.
Additional Event-Related Information The diesel-driven cooling water pumps that provide plant service water started as designed during the event l
to continuously supply a cooling water source throughout the event. Additionally, the Unit I mott.-driven j
cooling water pump operated throughout the event while powered from the degraded offsite power source.
Therefore, a heat sink was available throughout the event for the component cooling water system, the EDGs, and the auxiliary feedwater (AFW) pumps. All AFW pumps operated as designed.
Modeling Assumptions Five hours passed before a stable offsite power supply at normal voltage was reestablished. This did not occur until the utility purchased additional power and reset switchyard transformer taps. If the EDGs had not started as expected, the utility may have been able to expedite the retum of the offsite Byron 345 kV line.
Therefore, the Byron line was not considered a viable offsite power source for the safeguards buses, and the event was modeled as a grid-centered LOOP on each unit. The probability of not recovering off-site power j
in the short-term is included in the initiating event probability (IE-LOOP). This term was set to the probability for a grid-based LOOP assuming operators fail to recover offsite power in the short term
(
(4.8 x 10).
The grid-based LOOP probability of short term and long term offsite power recovery for a grid-centered LOOP and the probability of a RCP seal loss-of-coolant accident (LOCA) following a postulated station blackout (SBO) wre developed based on data distributions contained in NUREG-1032, Evaluation ofStation Blackout Accidents at Nuclear Power Plants. The RCP seal LOCA models were developed as part of the NUREG-1150 PRA efforts. Both are described in Revised LOOP Recovery and PWR Seal LOCA Models (Ref. 4). The probabilities for the following basic events are based upon these models: IE-LOOP, OEP-XHE-NOREC-6H, OPE-XHE-NOREC BD, OPE-XHE-NOREC SL, and RCS MDP-LK-SEALS.
The Individual Plant Examination (IPE, page 2-7) indicates that the first station batter / wal fail after 2 h.
Because a stable offsite power source was not restored until about 5 h into the LOOP, basic event OEP-XHE-NOREC-2H was set to TRUE (i.e., the probability of this event is 1.0 given that power was not restored in the short-term).
j 2
p q LER No. 282/96-012 Analysis Results d
The CCDP for this event is estimated to be 2.6 x 10. The dominant core damage sequence for this event (sequence 28 on Fig. 2) involves:
aLOOP a successful reactor trip a failure of the emergency power supplies (station blackout) success of the AFW system
+
no challenge to the power-operated relief valves (PORVs)
+
failure of the RCP seals during the LOOP, and
+
a failure to recover offsite power after the RCP seals fail This sequence accounts for about 37% of the total contribution to the CCDP. Sequence 37 is similar to LOOP sequence 28, except LOOP sequence 37 invoiv:s a POPV lin and sraessful reclosure. Combined, these two sequences account for 58% of the total contribution to the CCDP.
Sequences involving battery depletion (sequences 21 and 30) account for 16% of the total contribution to the CCDP. A station blackout is involved in 95% of the dominant core damage sequences. Failure of the AFW system only occurs in 10% of the dominant core damage sequences.
1 In a sensitivity study, the probability of failing to recover offsite power in the short term (IE LOOP) was set to TRUE [ LOOP with no short-term (30 min) recovery possible]. Station blackout values were adjusted to account for the revised time frame based on the code associateil with the Revised LOOP Recovery andPHR d
Seal LOCA Afodels (Ref. 4). The calculated CCDP in this case was 3.1 x 10 The dominant sequence remained the same for this sensitivity study.
Finally, the IPE indicated that an additional 2 h was available to recover offsite power prior to core damage following battery depletion. An estimate of the CCDP assuming 2 h prior to battery depletion and an d
additional 2 h prior to uncovering the core was calculated to be 2.0 x 10 Again, adjusted station blackout values were based on the code associated with the Revised LOOP Recovery and PHR Seal LOC 4 Afodels (Ref 4). The dominant sequences remained the same as for the initial analysis.
Acronyms AFW auxiliary feedwater system CCDP conditional core damage probability EDG emergency diesel generator IE initiating event IPE individual plant examination kV kilovolts LER licensee event report LOCA loss-of-coolant accident l
LOOP loss-of-offsite power i
I 3
l
- __ _ _ _. _.._=
l.> ',
,e i
I l
i LER No. 282/96-012 PORV power-operated relief valve RCP reactor coolant pump SBO station blackout References 1.
LER 282/96-012, Rev. O," Loss of Offsite Power to Unit 2 and Degraded Offsite Power to Unit i Followed by Reactor Trips of Both Units," July 29,1996.
2.
UpdatedSafety Analysis Report, Northern States Power Company, Prairie Island Nuclear Generating Plant.
3.
Prairic Island Nuclear Generating Plant,1ndividual Plant Examination.
4, RevisedLOOP Recovery andPHR SealLOCA Models, ORN11NRCILTR-89111, August 1989.
G 4
.\\
p t
t LER No. 282/96-012 I
i
+
.1
{
l s
I f
W Rad Rod I bLaka RedM 2 10TR
$45 KYBus 2
[
}
)
s s
l ll
/l
/
I)
I I
h) h)
l
[
l l
e I
To Bus 26 I
I l
l i
ll li
}I
/
til Trumfunner
/g' Tolks 15 l
I l
/l)
/l)
/l)
I l
l$45 KVBus i s
s s
2R T=sfamer ht2 Urut) w To N 25 h
Genersta To b 16 I
l l.
i i
Fig.1. Switchyard at Prairie Island.
i I
5
l' s
l LER No. 282/96-012,
$l 5555858888855885588885585888885585888888 i
....~..e==ere== ennananannnnsaaannunn.
ill LJ LJ lJ LJ LJ LJU UU I
g gl l i!ii l l
l l llf f 1ll s 11ll :
lill l lill l
~~
3 1
nIi g
]e il l is-I I
i!
!!j o.
l il i 58 ll1 li[ s E
1ll 1
j Fig. 2 Dominant core damage sequence fcr LER No. 28'.i96-012.
6
s's e,
l l
LER No. 282/96-012 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 282/96-012 Modified Event Base Current for this name Description probability probability Type event IE-LOOP LOOP Initiating Event 5.9 E-006 4.8 E-001 GRID Yes LOOP IE SGTR Steam Generator Tube Rupture 1.0 E406 0.0 E+000 IGNORE Yes initiating Event IE-SLOCA Small-Break LOCA Irdtiating 1.0 E406 0.0 E+000 IGNORE Yes Event IE-TRANS Transient Initiating Event 53 E-004 0.0 E+000 IGNORE Yes AFW-TDP-TC-TDP AFW Turbine-Driven Pump 3.5 E-002 3.5 E-002 No i
Fails AFW-XHE-NOREC-EP Operator Fails to Recover AFW 3.4 E401 3.4 E-001 No System During SBO EPS-DGN-CF-ALL Common Cause Failure of EDGs 1.6 E-003 1.6 E-003 No EPS-DGN-FC-1 Diesel Generator 1 Fails 4.2 E 002 4.2 E-002 No EPS-DGN-FC-2 Diesel Generator 2 Fails 4.2 E-002 4.2 E 002 No EPS-XHE-NOREC Operator Fails to Recover 1.0 E+000 1.0 E+000 TRUE No Emergency Power OEP-XHE-NOREC-2H Operator Fails to Recover Offsite 2.1 E-001 1.0 E+000 TRUE Yes Power Within 2 H OEP-X1E-NOREC-611 Operator Fails to Recover Offsite 9.9 E-002 3.6 E-004 GRID Yes Power Within 6 H LOOP OEP-XHE-NOREC-BD Operator Fails to Recover Offsite 6.1 E-002 33 E-002 GRID Yes Power Before Battery Depletien LOOP OEP-XHE-NOREC-SL Operator Fails to Recover Offsite 5.9 E-001 4.5 E-001 GRID Yes Power After Seal LOCA LOOP PPR-SRV CO SBO PORVs Lifi During SBO 3.7 E 001 3.7 E-001 No PPR-SRV-OO 1 PORV 1 Fails to Reclose After 3.0 E 002 3.0 E-002 No Opening PPR-SRV-OO-2 PORV 2 Fails to Reclose Af$r 3.0 E-002 3.0 E-002 No Opening RCS-MDP-LK-SEALS RCP Seals Fail Without Cooling 23 E-001 2.1 E-001 GRID Yes j
and Injection LOOP i
l l
7
. ~
l l>'s
,o i
LER No. 282/96-012 l
l Table 2. Sequence Conditional Probabilities for LER No. 282/96-012 Conditional Event tree Sequence core damage Percent name number probability contribution (CCDP)
LOOP 28 9.5 E-005 36.6 l
LOOP 37 5.6 E-005 21.5 LOOP 38 3.6 E-005 13.6 l
LOOP 21 2.6 E-005 10.1 LOOP 39 1.9 E-005 7.3 LOOP 30 1.5 E-005 5.9 Total (all sequences) 2.6 E-004 1
i l
l e
l l
i 8
> \\
s LER No. 282/96-012
. Table 3. Sequence Logic for Dominant Sequences for LER No. 282/96-012 Event tree Sequence name number Logic l
LOOP 28
/RT-L, EP, /AFW-L-EP, /PORV-SBO, i
SEALLOCA, OP-SL LOOP 37
/RT L, EP, /AFW-L-EP, PORV-SBO,
/PORV-EP, SEALLOCA, OP-SL LOOP 38
/RT-L, EP, /AFW-L-EP, PORV-SBO, PORV-EP i
~
LOOP 21
/RT-L, EP, /AFW-L-EP, /PORV-SBO, i
/SEALLOCA, OP-BD j
l LOOP 39
/RT-L, EP, AFW-L-EP
)
LOOP 30
/RT-L, EP, /AFW L-EP, PORV-SBO,
/PORV EP,/SEALLOCA, OP-BD l
l l
l Table 4. System Names for LER No. 282/96-012 i
System name Logic AFW-L EP No orInsufficient AFW Flow Durmg SBO I
EP Failure of Both Trains of Emergency Power OP-BD Operator Fails to Recover Offsite Power Before Battery Depletion j
OP-SL Operator Fails to Recover Offsite Power After Seal LOCA l
l PORV-EP PORVs Fail to Reclose (No Electric Power)
PORV-SBO PORVs Open During SBO l
RT-L Reactor Fails to Trip During LOOP SEALLOCA RCP Seals Fail During LOOP i
d l
9 l
l
.' b -
LER No. 282/96-012 Table 5, Conditional Cut Sets for Higher Probability Sequences for LER No. 282/96-012 Cut set Percent number contribution CCDP' Cut sets' LOOP Sequence 28 9.6 E-005 I
52.4 5.0 E-005 EPS-DGN-FC-1, EPS-DGN-FC-2, EPS-XHE-NOREC, RCS-MDP-LK-SEALS, /PPR-SRV-CO-SBO, OEP-XHLNOREC-SL 2
47.6 4.5 E-005 EPS-DGN-CF-ALL, EPS-XHLNOREC, RCS-MDP-LK-SEALS,
/PPR-SRV-CO-SBO, OEP-XHE-NOREC-SL LOOP Sequence 37 5.6 E-005 1
52.4 2.9 E-005 EPS-DGN-FC 1, EPS-DGN-FC 2, EPS-XHE-NOREC, PPR SRV-CO SBO, RCS-MDP-LK-SEALS, OEP XHE-NOREC-SL 2
47.6 2.7 E-005 EPS-DGN4F-ALL, EPS-XHE NOREC, RCS-MDP-LK-SEALS, PPR-SRV CO-SBO. OEP-XHE-NOREC-SL LOOP Sequence 38 3.6 E-005 1
26.2 9.3 E-006 EPS-DGN-FC-1, EPS-DGN-FC-2. EPS-XHE-NOREC, PPR-SRV-CO-SBO, PPR-SRV-OO-1 2
26.2 9.3 E-006 EPS-DGN-FC-1, EPS-DGN-FC-2, EPS-XHE-NOREC, PPR-
~
SRV-CO-SBO, PPR-SRV-OO 1 3
23.8 8.5 E-006 EPS-DGN-CF-ALL, EPS-X11E-NOREC, PPR-SRV-CO-SBO, PPR-SRV-OO-2 4
23.8 8.5 E-006 EPS-DGN-CF-ALL, EPS-XHE-NOREC, PPR-SRV-CO-SBO, PPR-SRV-OO-2 LOOP Sequence 21 2.6 E-005 1
52.4 1.4 E-005 EPS-DGN-FC-1, EPS-DGN-FC-2. EPS-XHE-NOREC,
/RCS-MDP-LK-SEALS, /PPR-SRV-CO-S BO, OEP-XHE-NOREC-BD 2
47.6 1.3 E-005 EPS-DGN-CF-ALL, EPS-XHE-NOREC, /RCS-MDP-LK-SEALS,
/PPR-SRV-CO-SBO, OEP-XHE-NOREC-BD LOOP Sequence 39 1.9 E-005 1
52.4 1.0 E-005 EPS-DGN-FC-1 EPS-DGN-FC-2, EPS-XHE-NOREC, AFW-TDP-FC-TDP. AFW XHE-NOREC-EP l
2 47.5 9.1 E 006 EPS-DGN4F-ALL, EPS-XHE-NOREC, AFW-TDP-FC-TDP, AFW-XIE-NOREC-EP 10
l
's e
l l
LER No. 282/96-012 Table 5. Conditional Cut Sets for Higher Probability Sequences fo r LER No. 282/96-012 Cut set Percent l
number contribution CCDP' Cut sets" LOOP Sequence 30 1.5 E-005 1
52.4 8.1 E-006 EPS-DGN-FC-1, EPS-DGN-FC-2, EPS-XilE-NOREC, PPR SRV-CO-SBO,OEP-XHE-NOREC-BD,
/RCS-MDP-LK-SEALS 2
47.6 7.4 E-006 EPS-DGN-CF-ALL, EPS-XHE-NOREC, PPR-SRV-CO-SBO, OEP-XHE-NOREC-BD, /RCS-MDP-LK-SEALS 92 Total (all sequences) 2.6 E-004
'The conditional probability for each cut set is determined by multiplying the probability of the initiating event by the probabilities of the basic events in that minimal cut set. The probabilities for the initiating events and t!:e basic events are given in Table 1.
' Basic event EPS-XHE-NOREC is a type TRUE events and these type of events are normally not included in the output of fault tree reduction programs. This event has been added to aid in understanding the sequences to potential core damage associated with the event.
l i
l 1
i 11 l
i
'y
?
n GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS
Background
The preliminary precursor analysis of an operational event that occurred at your plant has been provided for your review. This analysis was performed as a part of the NRC's Accident Sequence Precursor (ASP) Program. The ASP Program uses probabilistic risk assessment techniques to provide estimates of operating event significance in terms of the potential for core damage. The types of events evaluated include actual initiating events, such as a loss of off-site power (LOOP) or loss-of-coolant accident (LOCA), degradation of plant conditions, and safety equipment failures or unavailabilities that could increase the probability of core damage from postulated accident sequences.
This preliminary analysis was conducted using the information contained in the plant-specific final safety analysis report (FSAR), individual plant examination (IPE), and the licensee event report (LER) for this event.
Modeling Techniques The models used for the analysis of 1995 and 1996 events were developed by the Idaho National Engineering Laboratory (INEL). The models were developed using the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE). software. The models are based on linked fault trees.
Four types of initiating events are considered: (1) transients, (2) loss-of-coolant l
accidents (LOCAs), (3) losses of offsite power (LOOPS), and (4) steam generator tube ruptures (PWR only).
Fault trees were developed for each top event on the event trees to a supercomponent level of detail.
The only support system currently modeled is the electric power system.
The models may be modified to include additional detail for the systems /
components of interest for a particular event. This may include additional equipment or mitigation strategies as outlined in the FSAR or IPE.
Probabilities are modified to reflect the particular circumstances of the event being analyzed.
Guidance for Peer Review Comments regarding the analysis should address:
Does the " Event Description" section accurately describe the event as it occurred?
Does the " Additional Event-Related Information" section provide accurate e
additional information concerning the configuration of the plant and the operation of and procedures associated with relevant systems?
Does the "Modeling Assumptions" section accurately describe the modeling done for the event? Is the modeling of the event appropriate for the events that occurred or that had the potential to occur under the event conditions? This also includes assumptions regarding the likelihood of equipment recovery.
G D\\
Appendix H of Reference 1 provides examples of comments and responses for previous ASP analyses.
Criteria for Evaluating Comments Modifications to the event analysis may be made based on the comments that you Specific documentation will be required to consider modifications to provide.
References should be made to portion:; of the LER, AIT, or the event analysis.
other event documentation concerning the sequence of events.
System and component capabilities should be supported by references to the FSAR, IPE, Comments related to operator response times plant procedures, or analyses.
and capabilities should reference plant procedures, the FSAR, the IPE, or applicable operator response models. Assumptions used in determining failure probabilities should be clearly stated.
Criteria for Evaluating Additional Recovery Measures Additional systems, equipment, or specific recovery actions may be considered for incorporation into the analysis.
However, to assess the viability and effectiveness of the equipment and methods, the appropriate documentation must be included in your response. This includes:
normal or energency operating procedures.'
piping and instrumentation diagrams (P& ids),'
electrical one-line diagrams,'
results of thermal-hydraulic analyses, and operator training (both procedures and simulator),' etc.
Systems, equipment, or specific recovery actions that were not in place at ths Also, the documentation should time of the event will not be considered.
address the impact (both positive and negative) of the use of the specific recovery measure on:
the sequence of events, the timing of events, the probability of operator error in using the system or equipment, and other systems / processes already modeled in the analysis (including operator actions).
For example, Plant A (a PWR) experiences a reactor trip, and during the subsequent recovery, it is discovered that one train of the auxiliary Absent any further information feedwater (AFW) system is unavailable.
regrading this event, the ASP Program would analyze it as a reactor trip The AFW modeling would be patterned with one train of AFW unavailable.
after information gathered either from the plant FSAR or the IPE.
However, if information is received about the use of an additional system (such as a standby steam generator feedwater system) in recovering from this event, the transient would be modeled as a reactor trip with one train of AFW unavailable, but this unavailability would be
- Revision or practices at the time the event occurred.
I
^
y
.o,
mitigated by the use of the standby feedwater system. The mitigation effect for the standby feedwater system would be credited in the analysis provided that the following material was available:
l standby feedwater system characteristics are documented in the i
FSAR or accounted for in the IPE, i
procedures for using the system during recovery existed at the time of the event, l
the plant operators had been trained in the use of the system prior to the event, a clear diagram of the system is available (either in the FSAR, IPE, or supplied by the licensee),
previous analyses have indicated that there would be sufficient J
time available to implement the procedure successfully under the circumstances of the event under analysis, 1
the effects of using the standby feedwater system on the operation and recovery of systems or procedures that are already included in l
the event modeling.
In this case, use of the standby feedwater system may reduce the likelihood of recovering failed AFW equipment or initiating feed-and-bleed due to time and personnel constraints.
Materials Provided for Review The following materials have been provided in the package to facilitate your review of the preliminary analysis of the operational event.
The specific LER, augmented inspection team (AIT) report, or other e
pertinent reports.
l e
A summary of the calculation results.
An event tree with the dominant l
sequence (s) highlighted.
Four tables in the analysis indicate:
(1) a summary of the relevant basic events, including modifications to the probabilities to reflect the circumstances of the event, (2) the dominant core damage sequences, (3) the system names for the systems cited in the dominant core damage sequences, and (4) cut sets for the e minant core damage sequences.
Schedule Please refer to the transmittal letter for schedules and procedures for submitting your comments.
References t
1.
L. N. Vanden Heuvel et al., Precursors to Potential Severe Core Damage l
Accidents: 1994, A Status Report, USNRC Report NUREG/CR-4674 (ORNL/NOAC-l 232) Volumes 21 and 22, Martin Marietta Energy Systems, Inc., Oak Ridge l
National Laboratory and Science Applications International Corp.,
December 1995.
J i
\\V
.b,O g%
b' s >.
Northern States Power Company l
Prairie Island Nuclear Generating Plant 1717 Wakonade or. East Welch, Minnesota 55089 l
l l
l July 29,1996 10 CFR Part 50 l
Section 50.73 U S Nuclear Regulatory Commission 1
Attn: Document Control Desk Washington, DC 20555 l
PRAIRIE ISLAND NUCLEAR GENERATING PLANT Docket Nos. 50-282 License Nos. DPR-42 l
50-306 DPR-60 Loss of Offsite Power to Unit 2 and Degraded Offsite Power to Unit 1 Followed by Reactor Trios of Both Units l
The Licensee Event Report for this occurrence is attached. In the report, we made no new NRC commitments.
This event was reported via the Emergency Notification System in accordance with 10 CFR Part 50, Section 50.72, on June 29,1996. Please contact us if you require additional information related to this event.
1 l
h Aichael D Wadley Plant Manager Prairie Island Nuclear Generating Plant l
c:
Regional Administrator - Region 111, NRC NRR Project Manager, NRC Senior Resident inspector, NRC Kris Sanda, State of Minnesota Attachment
)pgg
- Vo66Gt06e5--960729 PDR ADOCK 05000292 S
PDR l
~. - - _, _........ _. - _.
..m_.
a y
?
I i
NRC FORM 366 U.S. NUCLEAR ARGULATORY CCBsCSS10W APPROVED SY OMB NO. 3150 0104 j
1 assi EXPIRES 04/30/98
($71u1TIO BURDEN PER Rf3PONSE TO COMPLV iMTH TM!$ MANDATORT INFORMAT10h COLLICT10h Rt3UEST: 50.0 NR3 REPORTED LESSONS LEARNED ARE IN00RPCRATED INTD l
l LICENSEE EVENT REPORT (LER)
E,8,'Is*NAT[$*Tu'"Mbu'A$'On'SEREIS'Os'0[AE!EONT /RINCE'T s"EN U3 NUCLIAR REGULATORT COMW!S$ lost WASHINGTOIL OC 205554001 AND TO THE l
(See reverse for required number of
'@nc$"fcE3 "*I "" "I "
"""'"I " "0II' a
digits / characters for each block) i u
a-a w Prairie Island Nuclear Generating Plant Unit 1 05000 282 1 OF 9
,.m
\\TripsofBothUnits Loss of offsite Power to Unit 2 and Degraded offsite Power to Unit 1 Followed by Reactor j
avam paTE (5)
LEm nowsm is) aErgx1 paTE UJ v4===
rAcILmas anyw&vua is; g
DAY It.An rtAn auutnis nevmun uvuiti DAT nan rACALm wei, ovem2.4 nunnu I
lmunin Prairie Island Unit 2 05000 306 00 7
29 96 rACIL W NAME uvbr.& 4 NUMEM 30 96 96 -- 12 1 06 05000
-~
u m s muromT Is swan 244.s totsuanT wo rmE aswui..n.m s or ao cra si tenecx one cx more; saas Iwrartav as0Ds W 20.ZZ04b)
Zg auAaXZXv)
A 50.7AaXZ/w 501AaXZXvm) r=.a 100 20.2203(a)(1) 20.2203(aX3)(1) 50.73(a)(2Xu) 50.73(a)(2Xx) 13Y33' Il03 ZD.aveaxZXi)
ZU.uvAaX3Xu)
A 50.7AaXZXm) 73 71 20.2203(a)(2Xn) 20.2203(a)(4)
X 50.73(aX2Xtv)
OTHER ZD.uveaXZXus) 50 36(CX1)
DQ.7Aa)(ZXV) b Abs below or ZD.uveaXZXrv)
DD.JOtc)(2)
DO ThaXZXvp)
L1E "IT.4 J Jack Leveille 1 - es 1 21 6uns a.ETE ONE LINE rQR EACE 6unrvanne rAILUKE Ussi Lassu IN TKls REFQET (U)
WNM W
ET5IEM N
%VJF AL1UPLt.M MtrUMi AUit TO NPRDS TO NPRDS i
l 3Vrrhamma4AL RErQRT RAraw4mu (AG) marsw4au MUN itt UA' NAM SUBatISSION TEs X
NO I
(If yes, complete EXPECTED SUBMISSION DATE).
asiTaa;T (Limat to levo spaces, A.e.,
approxAmately 15 sangle-spacec typewrAtten Aanes) ta iJ On June 29,1996, both Units 1 and 2 were operating at 100% power. In summary, both reactors tripped following the loss of three of four 345 KV offsite transmission lines to the plant substation, due to high winds. The plant safeguards busses were supplied power by the four safeguards diesel generators for several hours.
All safeguards diesel generators provided the needed electrical power throughout the duration of the svent. In addition, all cooling water (essential service water) pumps functioned as required. The event wts mitigated by the proper functioning of the safety related equipment and the proper management of tha event by operators.
mRC s0Ru au 4:si
NkC FORN 366A U.S. NUCLBAR REGULATORY COBOCISSION 340 LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY MAME (1)
DOCKET LER NUMBER (6)
PAGE (3)
Prairie Island Nuclear Generating Plant Unit 1 05000 282 HAn jug a
2 OF S
96 12 00 TRIT (Jf more space as requared, use addataonal copaes of NRC form J66Al (17)
EVENT DESCRIPTION On June 29,1996, both Units 1 and 2 were operating at 100% power. In summary, both reactors tripped following the loss of three of four 345 KV offsite transmission lines to the plant substation. The plant safeguards busses were supplied power by the four safeguards diesel generators for several hours.
In the aftemoon several isolated thunderstorms formed. At approximately 1418 the Blue Lake 345 KV line tripped and stayed out, from a single phase line to ground fault. At approximately 1429 both Red Rock 345 KV lines #1 and #2 tripped and stayed out, from a three phase fault. Towers on the Red Rock lines and the Blue Lake line are several miles from one another and about 10 miles north of the plant. The Prairie Island substation utiliz;s a ring bus with a breaker and a half configuration (see Figures 1 and 2). The electrical pre-event configuration was as follows:
P1 Unit 1 Main Generator' connections:
Red Rock line #1 2
Pi Bus 345-1 P1 Unit 2 Main Generator connections:
Blue Lake line until it was lost at 1418 Pl Bus 345-1 Pl Bus 345-1 connections:
Red Rock line #2 PI Unit #1 Main Generator PI Unit #2 Main Generator 8
Offsite source 2R transformer Offsite source CT-11 transformer via CT-1 transformer Pl Bus 345-2 connections:
Byron line Blue Lake line, subsequently disconnected prior to event Red Rock line #1 Offsite source 1R transformer via #10 transformer Offsite source CT-12 transformer via #10 transformer Safeguards Bus' 15 (Ur.it 1) source was 1R transformer (Path 1-1)
Safeguards Bus 16 (Unit 1) source was CT-11 transforme,- (Path 1-2)
Safeguards Bus 25 (Unit 2) source was 2R transformer (Path 2-1)
Safeguards Bus 26 (Unit 2) source was CT-12 transformer (Path 2-2)
Immediately following the loss of the Red Rock lines, the following electrical configuration existed:
- Ells System identifier: EL Ells Component identifier. GEN
- Ells Component identifier SSBU
- Ells Component idenWr. XFMR
- Ells System identifier. EK: Ells Component identifier. BU anneau assanse
I j. *.g se l
=c roam assa c.s. wocLaam asovLAtoar casesIssioet
- '<M j
f LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION j
FACILITY MAIEB (1)
DOCKET LBR W13EBER (6)
PAGE (3)
Prairie Island Nuclear Generating Plant Unit 05000 282 ffAn ju g 3
op 9
rie 96 12 00 (H more space as required, use adda caonal cop 2es of JctC form J66A) ' 17) ans.
I PI Unit 1 Main Generator connection:
1 l
Pl Bus 345-1 (which was disconnected from grid) i PI Unit 2 Main Generator connection:
Pi Bus 345-1 (which was disconnected from grid)
Pl Bus 345-1 connections:
No grid connections P1 Unit #1 Main Generator, at overspeed and overvoltage conditions P1 Unit #2 Main Generator, at overspeed and overvoltage conditions j
Offsite source 2R transformer Offsite source CT-11 transformer via CT-1 transformer Pi Bus 345-2 connections:
Byron line Offsite source 1R transformer via #10 transformer Offsite source CT-12 transformer via #10 transformer Safeguards Bus 15 (Unit 1) source was 1R transformer (Path 1-1)
Safeguards Bus 16 (Unit 1) source was CT-11 transformer (Path 1-2)
Safeguards Bus 25 (Unit 2) source was 2R transformer (Path 2-1)
Safeguards Bus 26 (Unit 2) source was CT-12 transformer (Path 2-2)
Nots that the Emergency Response Computer Systems' (ERCS) provided partial event sequence data. Without the ERCS record, some of the timing of the sequences is unknown.
At this point in time Pi Bus 345-1 and the Pl main generators were running separated from the grid. Both turbines began to accelerate and peaked at 110% speed within 4 seconds. All rotating loads connected to Pi Bus 345-1 or the main auxiliary transformers would have also accelerated. This included the reactor coolant pumps
- i (RCPs). With loss of load the generator output voltage increased approximately 10%. Unit 2 Emergency Response Computer System ERCS alarmed as the Nuclear instrumentation System (NIS) power range indication
)
reiched 102.7%. Unit 2 reactor tripped on a positve rate signal. Unit 1 had four "first out" annunciations'.
Based on the available information, the reactor received a turbine trip / reactor trip signal initiated by a turbine overspeed condition. The turbine stop valves' closed and the turbine started to coast down in speed. The Byron 345 KV line was the source to 1R and CT-12 via Bus 345-2 and #10 Transformer.
Approximately 20 seconds after the reactors tripped, the frequency would have been less than 58.2 Hz, the low frequency setpoint for the RCP breakers; apparently the reactor coolant pumps tripped at this time. Both reactor cool nt systems' began natural circulation. At about 25 seconds, apparently CT-12 source breaker'0 on Cooling Tower Bus CT-12 tripped on undervoltage. At about 30 seconds the main generators locked out. This would be
,' Ells System identifier. ID
' Ells System identifier. Asi Ell.""
aponent identifier: P
' Ells System identifier. Is
' Ells System identifier: TA Ells Component identifier. V
' Ells System identifier. As
" ElfS Ce,r.per.srt identifier. BKR sc pens assans
m.
_m.-._
h'#.
AIRC 70 Bat 366A 0.8. IfDCLEAR 8.tGU1ATORY CQISEISSIott 40 j
LICENSEE EVENT REPORT (LER) l TEXT CONTINUATION l
FACILITY alAaER (1)
DOCRET LER altBIBER (6)
PAGE (3)
Prairie Island Nuclear Generating Plant Unit 1 05000 282 FEAR aeg nc un 4
op 9
96 12 00 k
lH note space as requated, use addstional copses of MRC Form 166A) (11) soms
}
the expected time delay after a reactor / turbine trip. The normal 4 KV buses transferred to 1R (Unit 1) and 2R 3
i (Unit 2). Because 2R became de-energized, the Unit 2 normal busses also became de-energized. The main l
generators would have been below 56 Hz at this time. Following loss of power to the safeguards busses, the four l
safeguards diesel generators" auto-started and the load sequencers connected the safeguards busses to their t2 dedicated safeguards diesel generators (D1, D2, DS, and D6), the following indicates the significant equipment
]
configurations:
4 Safeguards Bus 16 (Unit 1) auto transferred from CT-11 transformer to D2.
l Safeguards Bus 25 (Unit 2) auto transferred from 2R transformer to D5.
Safeguards Bus 26 (Unit 2) auto transferred from CT-12 transformer to D6.
Safeguards Bus 15 (Unit 1) remained on 1R for approximately seven minutes before auto transfer to D1.
I Voltage on 1R varied at this time and apparently dipped low and long enough to cause a transfer.
12 Circ'8 Water Pump locked out.
i Bus 27 and 121 Motor Driven Cooling Water Pump" (fed by Bus 27) were de-energized for about 20 l
seconds before they were sequenced on to a DG powered bus. During the sequence delay, both diesel driven cooling water pumps started. By design this prevented the restart of 121 Motor Driven Cooling i
Water Pump.
l 21 Motor Driven Cooling Water Pump had a dead bus for a source.
l 11 Motor Driven Cooling Water Pump apparently remained running and fully functional throughout the event.
i The lack cf alarms indicates it prerformed as expected.
l The Low Cooling Water Pressure annunciator alarmed.
22 Diesel Cooling Water Pump and 12 Diesel Cooling Water Pump were running about 22 seconds after the j
low pressure alarm.
j 11 Auxiliary Feedwater Pump'8 (AFWP) started.
j 12 Auxiliary Feedwater Pump started.
21 Auxiliary Feedwater Pump started.
22 Auxiliary Feedwater Pump started.
j Operators restored letdown to regain pressurizer" level and pressure control and verified natural cooling at approximately 1500, and took control of cooldown and steam generator levels by throttling of the auxiliary l
feedwater valves.
" Ells System identmer. EK; Ells Component identmer. Io i
" Ells System identifier. ER
" Ells Component identifier. P i
" Ells System identifier. BI; Ells Component identifier P
. " Ells System identifier. BA Ells Component identifier: p
~
"' Ells System identifier. cs s
j
" EMS Component identifier PzR
" Ells Systemidentifier: R; Ells Component identmer, so
" EliS System identifier. BA; Ells Component identmer. v mic tenm assa nse
.. _. ~. _ _.
y l
IfRC FORM 366A
.#.S. arDCLEAR REGULATORY COBSEIS540tf l
- 9 51 LICENSEE EVENT REPORT (LER)
{
TEXT CONTINUATION j
FACILITY alAatB (1)
DOCKET LBR NDNBER (6)
PAGE (3)
Prairie Island Nuclear Generating Plant Unit 1 05000 282 YEAR gf 5
oF 9
1 96 12 00 1
k TEET IH more space as requ1 red, use adds t10tal copses of NRC forn 366A) (11) 1 l
A Notification of Unusual Event (NUE) was declared by the Shift Manager based on initiating condition EAL #20C, i
"Ccnditions that involve other than controlled shutdown." This decision was partially based on the belief that th:ra was a steam line break in the Turbine Building 2o because of reports of steam filling the area. The steam 2
was coming from 15B Feedwater Heater Tube Side Relief Valve ' which opened and rotated 90 degrees, causing l
a lerk at the threaded connection of the relief valve.
t l
The Shift Manager directed the communications engineer to augment plant staff. The Emergency Response t
Organization was radio-paged and telephoned. Atthough the Technical Support Center and Emergency Offsite i
Fccility were never formally activated, they were staffed and utilized for staff augmentation and communications.
i The performance of the ERO was judged to be effective.
During management of the event, loss of ERCS on Unit i required manual scanning of the Critical Safety i
Function Status Trees which is normally performed by the computer.
i i
At approximately 1700 the operators manually closed the Main Steam isolation Valves 22 (MSIVs) on both units;
. this was done in order to maintain the reactor coolant system temperature. Also, they began borating both units j
to pl:ce them at hot shutdown concentration with shutdown banks inserted.
j Fodowing consultation with the Technical Support Center, it was planned to restore 2R, re-establish the ring bus, and to obtain voltage support from the grid. Per standing operating procedure,2R transformer was re-energized i
by transferring it to Pl Bus 345-2 and, at approximately 1800, Unit 2 normal buses were being re-energized from l
2R transformer. The substation voltage was at or below 330 KV several hours into the event. The Prairie Island i
plint manager requested voltage support from System Operations, i
System Operations adjusted taps on system transformers and, at 1925, purchaced additional power from the j
adjacent utilities, thus restoring voltage to the Byron line; this provided a stable offsite source, allowing transfer of l
safeguards busses back to an offsite source and restart of reactor coolant pumps.
Since full functionality and redundancy of all safeguards equipment existed and the load sequencers would have cutomatically transferred any safeguards bus to the energized offsite source in the event of the failure of a diesel generator, priority was given to re establishing forced circulation in the reactors. At 1953 the operators restarted a Urnt 1 RCP and, at 2028, they restarted a Unit 2 RCP. Prairie Island Technical Specifications require that, cbove 350 degrees F, at least one reactor coolant pump be operating, except for a one hour allowed time with both pu nps out-of-service. There is no specific limiting condition for operation action statement for this condition, so the general limiting condition for operation action statements in TS 3.0.C was in effect. The general action stit: ment was not exceeded.
On Sunday, June 30,1996, at 0135, the Blue Lake 345 KV line was restored. The diesel generators were sequentially loaded onto the grid and loaded for a period of time and then restored to standby condition while the
Ells System ident6er. NM
)
Ells Systemidentifien SJ; Ells Componentidentifier RV
" Ells System identmer. ss; Ells Component identifier Isv i
ene eenu mu ssou
_ ~
',. f
- r**
s roan 366A 0.S. NUCLEAR REGULA,ORY CCseCSSION l
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY MANI (I)
DOCKET LER NUMBER (6)
PAGE (3)
Prairie Island Nuclear Generating Plant Unit 1 05000 282 HAR gg u
6 oF 9
96 12 00
,5., m -..n.
...n.........- - un... a -,-.... ~,
safeguarc buses were loaded onto offsite sources. We remained in the NUE until 1035 on June 30 when the last i
safeguardt diesel generator was tested and retumed to standby condition.
l The Red Rock line #1 was de-terminated at the Prairie Island substation. This allowed re-establishing the ring bus between Prairie Island Bus 345-1 and Bus 345-2.
Throughout the event, safety-related equipment performed as necessary to cope with this event.
The units were then brought back to power ever the next two days. There were some non-safety related 23 equipment problems during retum to power operations (e.g., turbine EH control problems on Unit 1 and the #9 bearings for both turbines were slightly wiped, probably during the turbine overspeed condition).
Red Rock 345 KV line #2 was restored to the electrical grid on July 4 and line #1 was restored on July 8,1996.
4 4
CAUSE OF THE EVENT Severe weather with straight-line winds caused three out of four 345 KV transmission lines leading into the Prairie island substation to fail. The Blue Lake line had a downed phase while both Red Rock lines had several failed support structures.
ANALYSIS OF THE EVENT All safeguards equir ment performed as expected:
Reactor Protection Reactor Trip Brewers Safeguards Diesel Generator Starts Bus Load Sequencers Cooling Water Pump Starts Auxiliary Feedwater Pump starts Reactor Coolant Pump trips Manual action was taken to control the event:
Control cooldown Stop & throttle the Auxiliary Feedwater Pumps Close Main Steam Isolation Valves Restart Reactor Coolant Pumps
~
Restore electrical sources and configurations Retum Diesel Generators to normal standby condition
- Ells System identifier: TG
Ells System identifier. TA me ranu ss6a sses
'. *- Q A asac Fve 366A o.s. stocLEAR asGM.ATORY CCASEISSION Em LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION j
FACILITY alAllE (1)
DOCKat LER 3rDNBER (6)
PAGE (3)
Prcirie Island Nuclear Generating Plant Unit 1 05000 282 MAR wge 7
oF 9
m 96 12 00 l
Ut more space 2s requ2 red, use adds c2onal copies of MRC Form 366A) l11) mans i
i Because of the proper functioning of the event mitigating equipment and the proper management of the event by
{
operators, heakh and safety of the public was not affected.
I j
Due to the entry into the general limiting conditions for operation action statements in TS 3.0.C this event is 1
reportable pursuant to 10 CFR 50.73(a)(2)(i)(A). Since there was an extemal condition (the wind storm) which j
posed a threat to the safety of the plant, this event is reportable pursuant to 10 CFR 50.73(a)(2)(iii). Due to minual and automatic actuations of the Engineered Safety Features as described above, this event is reportable pursuant to 10 CFR 50.73(a)(2)(iv).
l l
CORRECTIVE ACTION l
l The Blue Lake line downed phase was restored. The Red Rock lines failed support structures were repaired.
Both short term and long term adjustments are being made to the agreements between the plant and System l
Operations to provide voltage support during trip recovery.
The 15B Feedwater Heater relief valve which opened, rotated, and thereby developed a leak was removed, l
repaired, and rotested. The leaking inlet nipple was replaced. The discharge line to the drain funnel was secured j
with the existing pilot holes provided for that purpose.
l To provide increased assurance that ERCS will be available following a loss of power event, several actions are j
being considered; these include hardware, software, and procedural changes.
The turbine EH control system was repaired.
The turbine bearings that were damaged when the turbine overspeed condition caused some increased vibration.
1 This was reduced on Unit 1 by adding balance weights to the rotor. Unit 2 vibration was still at an acceptable j
levIl. Plans are to repair the damaged bearings on both units during scheduled outages.
f FAILED COMPONENT IDENTIFICATION One 345 KV phase conductor was blown off of its support structure and thirteen wooden support structures were j
downed by high winds.
PREVIOUS SIMILAR EVENTS I
A loss of offsite power event was discussed in the Reportable Occurrence report 80-20.
i i
d suc peau assaWsta l
. r
- n
,6 s
y unc roam 366A o.s. wucLaAa asw Aroar concusstow
', $m LICENSEE EVENT REPORT (LER) i TEXT CONTINUATION FAc1LIrr NAxs (1)
Docart lea smata (6)
Paas (3)
Prairie Island Nuclear Generating Plant Unit 1 05000 282 ftAA NN OF NUMBER NUMB 0t 12 00 8 of 9 96 Tszt (11 note space as required, use addstsonal copses of h*c to.m 266A) (116 SOURCES TO UNIT 1 SAFEGUARDS BUSSES J
L i
< ~_T T M_____
f f
t.
i I
j
<t_--
{
t gj 2 ~:
S-
'g_
N-I g-I '. li 3
1
~~W l
Il, I
e.-
l:
i Ii l
.a
-y 'J
' }
))
'n j 5
i e
i 1,,
l; a..
5 t
l
~
=
l i
- r.--
m, i
- l Il O-,.
s 5
I I
T e
.L a
2 :-
_i
<=.Q-+! r
~
,,_~l
~_
9 l
l
~
~ ~ _,,
s l 'j
---]
j o-w t--.._,
l 3-1_ _L sj _
8.
t 3
4 e #
a e,
0 U
.- l
'~.T *L.,,
l g
a-n i
6
$5*
i 1
=
[5 M s
8
>....Q.....{
m
..n
,g, a
')g 1
Y>
.7
~
N-
....................e'
?:,
i FIGURE 1 sca nuns
- hW
'agtC FQaN 366A o.s. xvcLsAn a.sovLArcar cosoussaou LICENSEE EVENT REPORT (LER)
TEXT CO!.TINUATION FAczLzn xAns til pocKzr
{
Lsa er m za (6)
Pact (33 Prairae Island Nuclear Generating Plant Unit 1 05000 282 ftM M**
OF WUMafR NUMBER 96 12 00 9 of 9
'7512 111 note space is requirea, use adds csonal copses o: su form assu (12s SOURCES TO UNIT 2 SAFEGUARDS BUSSES vl rL7 g---- ;
a
.<J
,- 4 y
h
'E-[
i_
C
's-o.-.
-y-
["! l!
c l
w
,;;s :
3
._:J i
.g
. l;l w
p_-
~,
O,
- d-E l
0 2
3
~,,
j i
8-i
[
f-i i
,-l i.
i
.l p.,
- i. :;
L_. _' :!
I g
~-
.s s
.s.
0 ~ 's I
i T -) I l:
l !.3,:
P' E.,1. _il g
i j
L..
i m
y_,
._4 l
- ...y
. u _ L.w_.
l
.rI-EJ
}'
-T-Tfa. -
iz a
x 3
,iv
?
4.... o..... y p_4,....f....................o'...Di g_
)
i
- z..__ __ --_-___-__
_ _K _ _ _.
n 0
9 b
FIGURE 2
- namuu n