ML20046C725
| ML20046C725 | |
| Person / Time | |
|---|---|
| Site: | Hatch, Monticello, Dresden, Davis Besse, Browns Ferry, Mcguire, Indian Point, Saint Lucie, Grand Gulf, Byron, Pilgrim, Arkansas Nuclear, Susquehanna, Brunswick, Surry, Limerick, River Bend, Haddam Neck, Diablo Canyon, Waterford, Robinson, San Onofre, Cook, Quad Cities, McGuire, LaSalle File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 05/07/1986 |
| From: | Trager E NRC |
| To: | |
| References | |
| TASK-AE, TASK-T604 AEOD-T604, NUDOCS 9308120014 | |
| Download: ML20046C725 (25) | |
Text
-,
epe AE00 TECHNICAL REVIEW REPORT *
)4 TR REPORT N0.:
AE00/T604 UNIT:
Various DATE:
May 7,1986 DOCKET NO.:
LICENSEE:
EVALUATOR / CONTACT: E. A. Trager NSSS/AE:
j
SUBJECT:
EVENTS RESULTING FROM DEFICIENCIES IN LABELING AND IDENTIFICATION SYSTEMS EVENT DATE:
Various
REFERENCES:
See Table 1
SUMMARY
A number of recent events at nuclear power plants were the result of deficien-cies in labeling and identification systems, that is, administrative systems for ensuring the correct identification of units, trains, and components.
Pacent studies have shown (References 1 and 2) that deficiencies in labeling and identification (L&ID) systems is a widespread problem in the nuclear power industry.
The purpose of this study was to better characterize this type of event.
DISCUSSION Thirty-eight (38) events were identified that involved deficiencies in labeling and identification (L&ID).
This is in addition to the 35 events earlier identified in which deficiencies in labeling and identification systems led to errors involving the wrong unit, train, or component (Reference 1)
'The 38 events are listed in Table 1 in order of ascending LER number and are described in Appendix A in chronological order.
It seems clear from the descriptions of the 38 other events that, although deficiencies in L&ID systems is one of many factors contributing to human error, it continues to be a significant one.
- This document supports ongoing AE00 and NRC activities and does not represent the position or requirements of the responsible NRC program office, j
i 9308120014 860507 PDR ADOCK 05000213
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. TABLE 1 Events Involving Deficiencies in Labeling and Identification Time From Event Power Personnel Initial LER #
Plant Date
(%)
Type System Criticality Notes 21385025 Connecticut 09/19/85 100 E0 Waste Gas.18.2 yrs Release of.
Yankee material 23784010 Dresden 2 06/26/84 5
Non-Lic.
Oper 24784017 Indian Point 2 10/21/84 10 Non-Lic.
'Turb Gen.
11.4 yrs Rx Trip Oper 25484011 Quad Cities 1 06/15/84 0
E0 RPS 12.7 yrs RPS Trip 25486003 Quad Cities 1 01/02/86 78 EA RBCCW 14.2 yrs 1/2 DG Inop.
25486006 Quad Cities 1 01/22/86 0
Inst. Mech RB Vent 14.3 yrs RB Vent.
Sys Isolation' 25486013 Quad Cities 1 03/10/86 0
I&C Tech RPS 14.4 yrs ATWS Trip 25985052 Browns Ferry 1 09/24/85 0
NA Electric 12.1 yrs
.Def's in Fuse Prog.
26184010 Robinson 2 11/07/84 0
Lic. Oper Battery 14.1 yrs Safeguards Actuation 16185013 Robinson 2 05/21/85 100 Non-Lic.
RPS 14.7 yrs Rx Trip oper 26186004 Robinson 2 01/22/86 33 I&C Tech Nuc Inst 15.4 yrs Rx Trip 26384025 Monticello 07/15/84 0
Non-Lic.
EDG 13.6 yrs EDG Start Oper 27584007 Diablo Canyon 1 03/09/84 0
Lic. Oper 120 Vac (Pre-IC)
ESF Actuations 28084005 Surry 1 03/01/84 0
Operator Electrical 11.7 yrs SIAS 29385131 Pilgrim 11/05/85 0
NA RHR/LPCI 13.4 yrs LPCI Mis-labeled 31385002 ANO-1 01/29/85 30 Non-Lic.
MFW 10.5 yrs Rx. Trip Oper 31584025 D.C. Cook 1 11/08/84 100 NR Fire Prot.
9.8 yrs Fire Prot.
Sys. Labeling.
316 DRPT D.C. Cook 2 03/11/86 0
I&C Tech NIS 8.0 yrs PRNI RPS Trip 32185026 Hatch 1 06/27/85 64 Non-Lic.
Fire Prot.-10.8 yrs' Rx Scram oper 32386002 Diablo Canyon 2 01/17/86 0
Non-Lic.
RHR 5 mths RHR. Isolation Oper 32483083 Brunswick 2 09/05/83 87 A0 SBGT 8.5 yrs Fire Prot.
Sys. Mispos.
32484002 Brunswick 2 01/29/84 94 A0 4160 Vac.
8.9 yrs Primary Cont.
.Isol.
32486008 Brunswick 2 03/10/86 0
A0 RPS 11.0 yrs Primary Cont.
Isol.
32585030 Brunswick 1 05/19/85 0
NR RPS Power 8.6 yrs Primary Cont.
Isol.
34684005 Davis-Besse 1 05/07/84 94 UNK CREVS 6.7 yrs-CREVS Inop.
, Time From Event Power Personnel Initial LER #
Plant Date
(%)
Type System Criticality Notes 35285019 Limerick 1 01/29/85 0
UNK HPCI 1 mths HPCS Declared Inop.
36284036 San Onofre 3 08/23/84 0
AC0 AMI 12 mths AMI Inop.
36985030 McGuire 1 10/09/85 100 UNK NSW 4.2 yrs Valve'Mispos.
37084005 McGuire 2 02/02/84 89 IAE SSPS 9 mths Rx Trip 37484102 LaSalle 2 05/03/84 10 Non-Lic.
MDRFP 2 mths Rx was Oper scrammed 38286002 Waterford 3 01/22/86 100 UNK CEA 11 mths EFAS 38786003 Susquehanna 1 02/16/86 0
Non-Lic.
RHR 3.4 yrs Loss of SDC Oper 38886004 Susquehanna 2 03/14/86 70 Non-Lic.
Power 1.8 yrs Rx was Oper Scrammed 38986002 St Lucie 2 01/11/86 99 Lic. Oper Turbine 2.6 yrs Turbine Trip (then Rx, Trip) 41684043 Grand Gulf 1 10/02/84 0
NA SPMU 2.1 yrs SPMU Actuated-41684S40 Grand Gulf 1 12/14/84 0
NA DG 2.3 yrs OG shutdown 45486001 Byron 1 01/16/86 98 Non-Lic.
RPS 11 mths Rx Trip Oper 45886005 River Bend 1 01/07/86 3
Contruct.
Electrical 2 mths Fire Prot.
Actuation 1
I
~4-Table 2 shows the distribution of the 38 events with respect to time.
The relatively large increase in events beginning in 1984 is probably due to the changes in event reporting requirements that occurred in that year.
In 1984, 10 CFR 50.73 made an explicit requirement that Licensee Event Reports (LERs) include a clear, specific, narrative description of events and that the LERs must contain the cause.of each personnel error, if known.
That is, it was no longer sufficient to report only that a personnel error had occurred.
TABLE 2 Number of Number at Plants with Number of Plants with Year L&ID Events
<2 Years Experience
<2 Years Exp vs. >2 Years Exp-1983 1
0 8
69 1984 15 4
9 74 1985 9
1 15 77 1986 13 5
15 78 Total 38 A large number of the events in early 1986 occurred at plants with less than two years operating experience (from date of initial criticality).
Tne Table 1 data indicate that operators were involved in a majority of the events resulting from labeling deficiencies.
Non-licensed operators accounted for 18, licensed operators for 4, and I&C technicians accounted for 5 of the 28 events for which a responsible personnel type was reported.
Roughly two-thirds of the events (25 of 38) involved electrical transmission comp nents and the remaining third (13 of 38) involved fluid transmission-components.
However, there was no dominant component or system in the events i
involving the electrical components (breakers., switches, fuses, panels, etc.)
or fluid components (instrument root valves and valves for fire protection, lube oil and waste gas).
Table 3 is a breakdown of the 38 events by type of L&ID deficiency.
Tne greatest number of events (16) were due to the fact that the labeling Was missing, either because it was accidentally removed or was never present.
The other events resulted because the labeling was incorrect (10), contained only partial information (7), or was confusing or ambiguous (5).
TABLE 3 Type of Labeling Deficiency Number Missing 16 Incorrect 10 Incomplete / Partial 7
Ambiguous / Confusing
_5 Total 38 i
v.
) 1 i
Table 4 contains in#9rmation on why these events were reported.
Reactor trips (13) and ESF actuations (10) accounted for 66% of the 38 total events.
TABLE 4
)
Reason the Deficiency was Reported Nuniber Reactor Trips 13 E3F Actuations 10 System Inoperable 6
Miscellaneous
_2 Total 20 i
Resident Inspectors were contacted at a number of the sites that had experi-enced multiple events involving L&ID deficiencies.
Tha residents expressed the views that the licensees were thorough in the ir.vestigation and reporting of events and/or that plants that reported multiple ever.ts cera perceptive enough to realize that such deficiencies might enntritote to events, e.g.,
that having NIS channel identity information inside a cabinet might help to prevent a technician from working on the wrong channel.
FINDINGS AND CONLLUSIONS A number of recent events have resulted from deficiencies in labeling and identification systems.
However, the characteristics of the events are not differ nt from those that were the subject of other recent studies of eveats that resui'ed from human error.
The events are additional evidence that labeling anC identification deficiencies are one of a number of contributing factort that lead to events.
Because NRR/DHFT is currently working to obtain improvements by industru in this and related areas, no further action on this specific topic is need. t this time.
REFERENCES 1.
Memorandum for W. T. Russell, from F. J. Hebdon, " Wrong Unit / Wrong Train Events, 1981-1985," FeDruary 13, 1986.
2.
Memorandum for H. R. Denton, from W. T. Russell, " Human Error in Events Involving Wrong Unit or Wrong Train," March 13, 1986.
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APPENDIX A Labeling and Identification Events Event Date Event Description 9/05/83 While performing Brunswick 2 weekly fire protection operability periodic test, PT-35.1, it was discovered that the supply valve (2-FP-V39), to the deluge systems of both SBGTs was shut.
Further review indicated that the valve had a clearance tag on it for the potable water valve 2-PWT-V5.
The plant was operating at 87% power.
i The auxiliary operator (AO) assigned to hang the tag on 2-PWT-V5 mistakenly closed and tagged 2-FP-V39.
Neither valve had valve identification and the A0 failed to follow procedures concerning operation of valves not positively identified.
In addition, the fire protection valve was not painted red, as required.
The A0 was appropriately disciplined, associated valves were tagged for identifi-cation, and a check was made that all fire protection valves were painted red.
Source:
LER 324-83-083 1/29/84 While performing an equipment clearance on emergency diesel generator (DG) No. 4 at 0648, a Brunswick 2 Auxiliary Operator (AO) deenergized the DG 4160V output breaker rather than the 125 Vdc normal control power supply breaker to DG No. 4.
Upon reenergizing the breaker, the DG emergency bus E-4 undervoltage relay tripped, thereby, causing E-4 to deenergize and Group 3 and Group 6 isolations to occur.
This event occurred because the A0 incorrectly remembered the location of the 125 Vdc normal co trol power s0pply breaker for DG No. 4 and becaut.
a identification labels or tags existed for the dc control power breaker mistakenly opened.
Following the event at 0715, the 125 Vdc normal control power breaker to the 4160 output breaker of DG No. 4 was labeled for proper identification.
In addition, a plant work request was generated to permanently label the 125 Vdc normal and alternate control power breakers of the plant emergency ac buses and DGs.
The involved plant Auxiliary i
Operator was counseled concerning his actions and was appropriately disciplined.
Source:
LER 324-84-002 l
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- Event Date Event Description 2/02/84 A McGuire Unit 2 reactor trip was initiated on February 2, 1984 at 1111 during performance of the " Solid State
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Protection System (SSPS) Periodic Test Above Reactor Coolant System Pressure of 1955 PSI."
The trip occurred when an Instrument and Electrical (IAE) Specialist, who was preparing to place the Train B bypass breaker in the " TEST" position, mistakenly opened the compartment for the Train B reactor trip breaker and accidentally pushed the red TRIP pushbutton.
Unit 2 was in Mode 1.at 89% when this incident-occurred.
4 While preparing to perform _ a step of the procedure which requires placing BYB in the " TEST" position, the IAE Specialist mistakenly opened the compartment for the Train B reactor trip breaker.
The Specialist was talking through parts of the procedure for a Technical Training Center (TTC) representative and intended only to instruct him how to place the bypass breaker (BYB) in and out of " TEST" position. As no action was intended at this time, independent verification had not yet been performed. As l
the IAE Specialist touched the red TRIP pushbutton (presumably while describing the steps necessary to restore the bypass breaker to " DISCONNECT" after the test), he was unaware that he was in the wrong breaker compa'rtment.
In reality, he depressed the TRIP pushbutton for reactor trip breaker for Train B, caut,ing the reactor to trip.
[No action to prevent recurrence is reported.]
Source:
LER 370-84-005 3/01/84 At 2135 hours0.0247 days <br />0.593 hours <br />0.00353 weeks <br />8.123675e-4 months <br />, with Surry Unit 1 at cold shutdown, Safety Injection Signals were initiated as the result of completing 3 of 4 High Containment Pressure Signals and completing 2 of 3 High Steam Flow Signals. At the time of f
the event, operators were performing M0P 26.9 (Removal of Vital Bus SOLA Transformer I-1) when vital buses I and III were mistakenly cross connected out of phase.
This resulted in a voltage transient on vital bus I and III, which caused spurious containment high pressure and high steam flow signals.
The vital bus synchronizing switch for vital buses II-IV had been used in error rather than the synchronizing switch for the buses being crosstied.
Vital Buses I and III were cross connected because a licensed operator failed to recognize which vital bus system was being placed in service and this was considered to be due in part to poor labeling of the Bus Transfer switches. Th.? operator was reinstructed in the correct manner of removing the vital bus SOLA transformer and labels were made for both unit's manual transfer switches.
Source: LER 280-84-005
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l Event Date Event Description 3/09/84 A' i916 PST, while Diablo Canyon Unit I was in Mode 5
,vold Shutdos:n), the 120V vital instrument ac bus 1-3 was deenergized when an operator inadvertently reset the
" Inverter Input" breaker which appeared to be tripped.
This action deenergized the bus which resulted in the automatic operation of two Engiacerad Safety Feature (ESF) systems. The ESF systems actuated were the Auxiliary l
Building Ventilation System and the Control Room Ventilation System.
j Ncnspecific labeling of the inverter bre:kers contributed to the operator's error.
To prevent recurrence of this event, a simplified inverter diagram showing the location, functicn and labelina of each breaker was mounted on all the 120V instrument fuverter panels in both Units 1 and 2.
Source: LER 275-84-007 5/03/84 At 11:40 p.m. LaSalle Unit 2 was manually scrammed from 10% power in response to a trip of the Motor Driven Reactor l
Feedwater Pump (MDRFP) on low lubricating oil pressure. ' No Turbine Driven Reactor Feedwater Pumps (TDRFP) were in operation.
Investigation revealed that the MDRFP lubri-cative oil loss resulted from the incorrect closure of the MDRFP downstream balancing stop valve 2CB037_which e
eliminated the balancing effect of feedwater pressure on the pump shaf t and forced the full thrust of the shaft against the thrust bearing. The rapid decomposition of the thrust bearing babbitt face caused that material to accumulate in the lube oil strainer, blocking lube oil flow.
The inadvertent closure of 2CB037 resulted from confusion between that valve and the numbering of the MDRFP Warm-up Line Upstream Stop Valve, 2FWO37, which the operator had been instructed to close. The two valves are similar in size and appearance and are physically located approximately six feet apart at the MDRFP.
Immediate licensee corrective action included the-installation of red signs affixed to 2CB037 and the upstream stop valve in the same line warning operators against valve manipulation unless the MDRFP is out of service. Training of personnel to alert them to the cause and significance of the event commenced immediately and continued to other crews. Other corrective action included revision of all station procedures from requiring the manipulation of valve 2FWO37 to instead operate valve 2FW115, which is located in the same line but outside the MDRFP room, thereby reducing the potential for confusion over nearly identical identification numbers and close physical locations.
Source:
IE Inspection Report No. 50-374/84-02
- Event Date Event Description 5/07/84 During a routine monthly surveillance test at 0930 while Davis-Besse Unit I was operating at 94% power, it was found that both Control Room Emergency Ventilation Chiller Control Power Switches were in the "0FF" position. This rendered the cooling function for both Control Room Emergency Ventilation System trains inoperable.
The cause was personnel error of undetermined origin.
It was determined by interviews and walk-throughs with the operators who run the surveillance test and by checking dates of previous surveillance tests that the switch for Unit 2 was in its proper position on April 23, 1984, after preventative maintenance activities. Also during the ir vestigation, it was determined that the administrative control of recent preventive maintenance work orders was inaCequate in not properly addressing the effect of these swittbas on system operability.
The switches and panels were also not labeled clearly.
l As corrective action, labels were placed above the switches to more clearly identify them and to require that the Shift Supervisor is notified prior to turning off. The panels on which the switches are located were more clearly labeled also. The preventive maintenance work order was modified to identify that it made the system inoperable, and to require that the switches be verified to be in the "0N" position after the work is performed. The surveillance test was modified to further identity the switches and to note the effect of these switches on system operability.
Source:
LER 346-84-005 6/15/84 Quad Cities Unit I was in the shutdown mode with no fuel in the vessel. At 1200 hours0.0139 days <br />0.333 hours <br />0.00198 weeks <br />4.566e-4 months <br /> Bus 13-1 tripped. This caused a channel "A" half-scram due to the fact that the main feed to the 1A RPS MG set was now lost. An Equipment Operator was sent to transfer the 1A RPS MG set to its reserve feed so the half-scram signal could be cleared.
Instead, the Equipment Operator transferred the 1B RPS MG set to its reserve feed, giving a Channel "B" half-scram and causing an RPS system trip.
The immediate corrective action was to restore power to the IB RPS MG set and put the 1A MG set on its reserve feed so that the scram signal could be cleared.
Further action was to more clearly label the respective NORMAL and RESERVE feed breakers "1A RPS" and "1B RPS" respectively.
This was expected to eliminate any confusion as to which channel's feeds are being manipulated.
Source: LER 254-84-011
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Event Date Event Description 6/26/84 At approximately 2040 hours0.0236 days <br />0.567 hours <br />0.00337 weeks <br />7.7622e-4 months <br />, with Dresden Unit 2 in the l
startup mode and critical, the Unit 2 NSO noticed that the position indicating lights for what he believed to be the MCC 29-7 feedbreaker from Bus 29 was not illuminated on Control Room panel 902-8. There are dual feedbreakers from Bus 29 to MCC 29-7 from a single control switch on panel 902-8 in the Control Room. The NSO verified that the problem was not in the lamp, as the light bulbs were replaced and an Equipment Attendant (EA) was dispatched to r
MCC 19-7 with instructions to reset the feedbreaker at approximately 2045. The EA mistakenly pushed the trip button on the breaker which resulted in a breaker trip.
It should be noted that up to this point, despite the loss of 1
feedbreaker indication in the Control Room, MCC's 28-7 and 29-7 had not lost power. A GSEP' Unusual Event was declared because ' control power was lost to both LPCI injection valves (M0 2-1501-21 A and B) causina LPCI to become inoperable.
t Corrective actions included labeling the 902-8 panel indication lights to show which light represented which i
breaker, and placing a warning sign on the incoming feedbreaker for each of the MCC's involved to warn personnel that tripping the MCC feedbreakers without tripping the bus feedbreaker first will result-in a loss of the MCC's.
Source:
LER 237-84-010 7/15/84 While isolating the #16 bus for relay maintenance during a Monticello refueling / maintenance outage, the #11 Emergency Diesel Generator (DG) started when an. operator opened a bus potential transformer (XPT) door on the rear of cubicle 152-610 rather than cubicle 152-601 as required by the procedure. The DG started properly.
It did not load onto the bus as the bus was being supplied by an off-site power source.
DG was shut down.
To prevent recurrence, the operators were reminded to take care in reading numbers and potential consequences of inverting two digits.
A caution tag placed on bus pot door warning of a potential DG start if door was opened. A modification was in progress to eliminate the DG start from opening of subject bus XPT door.
Source:
LER 263-84-025 l
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l 1 Event Date Event Description 8/23/84 At 0100, during an unrelated surveillance on San Onofre 3, an Assistant Control Operator (ACO) noted that Steam Generator Wide Range Level Indicator 3LI-1125-2_had failed low.
However, because the instrument was not uniquely-identified as part of Accident Monitoring Instrumentation (AMI), the AC0 did not recognize that it had to be restored within seven days.
The AC0 prepared a routine maintenance request instead of an accelerated maintenance request.
1 This condition was observed at 1920 on 8/23/84 with the unit in Mode 3 and cooldown to Mode 4 was initiated in accordance with Limiting Condition for Operation 3.3.3.6.
At 2000, on 8/23/84, 3LI-1125-2 was returned to service following replacement of a faulty lumnigraph assembly and cooldown to Mode 4 was terminated.
As corrective action, all AMI was labeled. Additionally, the significance of this event, the labeling of AMI, and i
the use of accelerated maintenance requests were discussed i
at shift briefings.
Source:
LER 362-84-036 l
10/02/84 At 0945 hours0.0109 days <br />0.263 hours <br />0.00156 weeks <br />3.595725e-4 months <br />, the Grand Gulf 1 Division 2 Suppression Pool Makeup (SPMU) system initiated and dumped water from i
the Upper Containment Pool into Oe Suppression Pool. The Upper Pool water level was lowered by approximately two feet before the dump valves were closed. The excess water that was dumped into the Suppression Pool was later transferred back to the Upper Pool.
The SPMU system was initiated during the performance of a routine time relay calibration.
The test instructs the Technician to remove relay 1E30-R12 at Panel 1H13-P872.
However, the technicians were not aware that there were two relays in the panel labeled 1E30-R12. One was actually 1E30-R10. By removing the incorrect relay and leaving relay R12 still in the circuit a SPMU initiation was produced during performance of the test.
Research of maintenance records revealed no maintenance work on either of the relays and the cause of the mislabeling was uncertain.
Relay R10 was relabeled.
System relays in Panel IH13-P872 (Division 2) and Panel 1H13-P871 (Division 1) were inspected for proper
)
a identification. No other nonconformances were found.
Source:
LER 416-84-043
h Event Date Event Description 10/21/84 While Indian Point 2 was at 10% power, following a i
refueling-maintenance outage, a reactor trip occurred because of an error made during a Turbine. Generator Trip i
Test.
The test required a check of various parameters during each test before test handles were released from the test position, so that an actual trip would not take place.
For the overspeed test, the oil pressure to the turbine stop valves was to be checked to assure restoration to the original pretest value before the test handle was reposi-tioned.
The operator inadvertently checked a gauge located in the isolated portion of the system, not included in the test. Thinking that the pressure had been restored, he.
repositioned the test handle; however, the oil pressure to the stop valves (auto-stop oil) had not been returned to its pretest value and a turbine trip occurred, followed by a reactor trip.
This event and its cause was discussed-with the operators involved.
In addition, the test gauge was relabeled to more accurately describe its function.
4 Source:
LER 247-84-017 11/07/84 While Robinson 2 was in cold shutdown, a safeguards actuation on "A" Train occurred due to an inadvertent. low pressurizer pressure signal.
The Safety Injection Pump breakers were racked out per Plant procedures, therefore, no water was injected into the Reactor Coolant System.
]
Deenergizing "A" battery bus for a modification resulted in removing a blocking signal from the Train "A" low pressurizer pressure safeguards actuation signal.
It was not recognized that when the "A" battery bus was reenergized the blocking signal would not automatically reinstate. This resulted in an inadvertent low prdsurizer pressure safeguards actuation when "A" battery bus was reenergized.
Corrective action included installation of a label plate on the breakers for safeguards logic Train "A" and "B" i
describing the precautions to be taken when returning these circuits to service.
Source:
LER 261-84-010
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i Event Date Event Description 11/08/84 At 1530 hours0.0177 days <br />0.425 hours <br />0.00253 weeks <br />5.82165e-4 months <br />, with both DC Cook Units I and 2 in Mode 1 at 100 percent reactor thermal power, technical 'specifica-tion surveillance requirements were discovered unfulfilled for firewater ring header valves 12-FP-109 and 12-FP-111.
Technical specification surveillance ~ requires verifying the valves are in their correct position at least once per 31 days and completing one full cycle of travel at least once per 12 months.
Because of an effort to verify physical piping arrange-ments and locations versus piping diagrams, valves 12-FP-109 and 12-FP-111 were excavated.
It was discovered that valves identified as 12-FP-109 and 12-FP-111 were incorrectly labeled and actual valves 12-FP-109.and 12-FP-111 were not labeled due to both flow diagrams and physical piping diagrams being incorrect. The actual valves were then correctly labeled and tested on 11/8/84 per the surveillance requirements.
Source:
LER 315-84-025 12/14/84 The Grand Gulf 1 Division III Diesel Generator was started for a surveillance but had to be shut down because the stopwatch timing of the start was not recorded as_specified in the procedure.
At 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br /> the generator received a second manual start signal in order to rerun the surveillance, but it failed to start.
According to procedure, air discharge valves F041A and F041B were closed to isolate their respective air train from the diesel start system so that the operability of the air start solenoids and check valves of the remaining train could be shown. When the generator received the start signal, the air pressure switches sensed a loss of air due to the depletion of air to the air start logic circuit.
It was discovered that a contributing cause was that air pressure switches 107A and 108B were in series rather than parallel because they had been mislabeled. The pressure switches were correctly labeled and the wiring changed to agree with the correct designation, fource:
Special Report 84-40 t
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> Event Date Event Description 1/29/85 At 1417 hours0.0164 days <br />0.394 hours <br />0.00234 weeks <br />5.391685e-4 months <br />, an AN0-1 reactor trip occurred during steady state operation at 30% full power.
Instrumentation and Control (I&C) personnel were calibrating a main feedwater (MFW) train "A"-flow instrument and noted that one of the instrument's isolation valve was leaking by the stem. Operations personnel were requested to isolate the instrument by closing the sensing line root valve while the I&C technicians obtained a replacement instrument isolation valve.
Due to incorrect labeling of the sensing line root valves, the redundant MFW train "A" flow instrument was-isolated. The Integrated Control System (ICS) automatically increased t1FW flow upon detecting no flow in MFW train "A" as a result of the flow control. instrument being isolated. Recognizing the ICS response, operations personnel placed MFW control in the manual mode to prevent steam generator (SG) overfeed. Operator actions to correct the feedwater flow transient led to a SG underfeed resulting in a high Reactor Coolant System pressure trip.
Investigation of the event revealed, for both MWF trains, that the flow instrument sensing line root valve identification (ID) tags corresponded to the redundant flow instrument.
It was believed reversal of valve ID tags occurred in October 1979 when all MFW flow instrument sensing line root valves were replaced.
Inattention to f
detail during the root' valve replacement was the' suspected cause of the valve ID tag reversal. ~The leaking instrument isolation valve was replaced and the sensing line root t
valves were properly labeled.
Source:
LER 313-85-002 1/29/85 At approximately 0930 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.53865e-4 months <br /> with Limerick Unit 1 operating at 3.5 percent power in the startup mode, instrument and control technicians, while investigating a reported-temperature switch problem, discovered a High Pressure Coolant Injection (HPCI) Room differential temperature switch, TDTS-55-1N601B, with reversed thermocouple leads.
This switch generates a signal to close the HPCI turbine steam supply outboard isolation valve in the event of a measured high differential temperature between HPCI equipment room supply and exhaust ventilation. The reversed leads of this switch precluded its ability to satisfy this ' function. Both the inboard and outboard HPCI steam supply isolation valves were immediately manually closed. Technicians discovered the problem to be unlabeled, reversed thermocouple wires. The technicians labeled and connected the thermocouple wire to the proper terminals, performed a functional test to verify operability of the temperature switch, reopened the isolation valves, and returned the temperature switch to service on January 30, 1985.
Source:
LER 352-85-019
Event Date Event Description l
i 5/19/85 While hanging a clearance to deenergize the Brunswick
.l Unit 1 outboard MSIV actuator power, a Group 2, 6, and 8 containment isolation was received when breaker CB5B in the Reactor Protection System'(RPS) ~ power distribution panel was opened.
Prior to hanging the clearance, research of the Reactor Protection System Operating Procedure.(0P-3) and the local breaker identification label indicated that breaker CBSB supplied power to the outboard MSIV actuator logic only.
During this event, Unit I was in a refueling /
maintenance outage.
A review of systein logic prints determined that breaker CB5B supplies power to outboard MSIV actuator logic power, drywell floor and equipment drain isolation valve logic, RHR shutdown cooling isolation valve logic, and Reactor Building high radiation instrument 012-RM-N0108. Loss of power to those components caused the identified isolations.
3 l
To correct this problem, breaker labels on the RPS power supply and OP-03 were to be revised by 9/1/85, to reflect actual breaker loads.
In addition, the labeling of other electrical distribution breakers throughout the plant was under review to assure their adequacy.
The breakers would be labeled / relabeled by 6/30/86, to correct identified discrepancies.
Source:
LER 325-85-030 5/21/85 While operating at 100% reactor power at approximately 1308 hours0.0151 days <br />0.363 hours <br />0.00216 weeks <br />4.97694e-4 months <br />, Robinson 2 tripped on 2 of 3 lo-lo level signals from "A" steam generator.(S/G). One of the three "A" S/G level transmitters was to be taken out of service for maintenance on a leaking condensing pot vent valve.
It was intended to trip the bistable and isolate the transmitter.
However, the trip occurred when the S/G level transmitter isolated in the field was different from and redundant to the level transmitter whose bistable was tripped. This error resulted in the reactor trip, Corrective action included replacing the missing valve identification tag.
Source:
LER 261-85-013 6/27/85 At approximately 1320 CDT, with the Hatch Unit 1 operating at approximately 64% power, and while plant personnel were preparing to increase load on the unit, the "1C" start-up transformer (SUT) shorted to ground causing loss of power to the "A" and "B" 4160 volt busses.
This resulted in loss of power to the "A" and "B" reactor recirculation pumps.
While plant personnel were attempting to manually scram the
s 1 Event Date Event Description unit (required by Technical Specifications, Section 3.6.J.1), an automatic scram from the Neutron Monitoring system (i.e., loss of recirculation pumps resulted in an APRM Flow Bias scram signal) was received.
j The event resulted from nonlicensed plant personnel closing j
the incorrect fire protection deluge valve diaphragm i
chamber water supply valve because the valves were mislabeled. This caused the fire protection water system to actuate and spray the IC" SUT, resulting in a phase-to-ground fault trip on the "1C" SVT.
Corrective actions included directing operations personnel not to perform actions on valves that are not clearly labeled and identifying and marking correctly the fire protection deluge valve's diaphragm chambers.
Source: LER 321-85-026 9/19/85 During routine scheduled maintenance on a pressure actuated valve in the Haddam Neck gaseous waste system, an unplanned radioactive release to the environment was detected.
The release occurred when an isolation valve, required to be closed on the station tagout sheet, was inadvertently left open.
this allowed radioactive gas, from the on-line waste gas decay tank, to escape through a pressure gage connection that had been opened to vent the system.
On September 19, an equipment operator was assigned to tagout the valve stem leadoff cooler in accordance with station tagout clearance #636.
Upon entering the radio-active trench, he found one of the valves labeled only as
- 401.
He proceeded to shut #401 concluding that it was WG-V-401, the waste gas outlet valve.
However, the, operator was inadvertently shutting CC-V-401, the component cooling water inlet valve to the cooler.
At approximately 0830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br />, maintenance was to begin work on DH-PV-1170.
To vent the system, pressure gage PIC-1170 was removed and DH-V-1170 opened.
However, instead of venting the valve stem leadoff cooler, opening DH-V-1170 vented the on-line "A" waste gas decay tank via WG-V-401.
Total discharge to the environment was 19.7 curies over a one-hour period.
Corrective action included clearly relabeling the valves to prevent recurrence.
Source: LER 213-85-025 i
-4
.,v
6 Event Date Event Description 9/24/85 Report on the status of the TVA fuse labeling and identi-fication program at Browns Ferry.
During the fuse labeling process, approximately 10% of the fuses labeled were found to have discrepancies typically involving variations in fuse amp rating, fuse type and class, and fuse block type. Approximately one half of the discrepancies are counted against an internal upgrade-program in switching from Bussman type MIC fuses to Shawmut ATM fuse types. The cause of the remaining discrepancies is basically attributed to the lack of a comprehensive fuse control program.
Source: LER 259-85-052 10/9/85 At approximately 1400, with McGuire Unit 1 at 100% power, it was discovered that valve 1RN-33 (RN Pump 1A Discharge Crossover Isolation Valve) was in the " locked closed" position instead of " locked open." The valve (a manually operated butterfly valve) was placed in the indicated open position on October 7, 1985, to cross-connect the Unit 1 and Unit 2 Train A RN (Nuclear Service Water) discharge headers.
The local valve position indicator was reversed showing the valve open when it was actually closed and vice versa.
The Unit was in Mode 1 at 100% power at the time of the incident.
It could not be determined when and how the valve position indication was reversed.
The valve was opened and properly labeled. The manually operated butterfly valves in the component cooling, chilled water, and nuclear service water systems for both units were checked for position indication; four discrepancies were identified (2 missing indicators, 1 broken, 1 incorrect).
Source:
LER 369-85-030 11/5/85 An NRC Inspector at Pilgrim reviewed the valve lineup of the "B" loop of the LPCI mode of the Residual Heal Removal (RHR) system. The Inspector found all valves properly aligned. However, the operating procedure and the valve checklist used to align the system were found to contain numerous errors, and the licensee's efforts to tag the valves remained incomplete.
Section VII.A, Standby Status, of operating. procedure 2.2.19 improperly listed outboard LPCI injection valve 28B as open and inboard LPCI injection valve 19B as closed.
This lineup reversed the status as observed on control panel 903 and as listed in the valve
P Event Date Event Description checklist and the P&ID. This error was corrected by SR0 change 85-178 dated December 5, 1985, to procedure 2.2.19.
The inspector marked up a copy of the valve checklist to indicate the status of tagging and to show checklist errors. The marked up copy was given to the Chief Operating Engineer.
Of the greater than one hundred valves reviewed, the Inspector found that slightly more than half of the valves did not have tags, six valves had the wrong tags, and four valves were tagged but not listed in the checklist.
Sn the valve checklist the Inspector found the following err]rs:
4 valves were not shown on the drawing and were not found in the listed location.
5 valves had the wrong number.
7 valves had the wrong location.
3 valves were duplicated on different pages.
2 valves had the wrong description.
In addition, the Inspector reviewed the last completed valve checklist, performed in December 1984, on an earlier revision of the checklist. The Inspector found that some of the above checklist errors had resulted from "correc-tions" made via the procedure change process following the last checklist completion.
At the inspection exit meeting, the Inspector identified the checklist's lack of organization by valve location and the lack of valve tags on all system valves as the root causes of the above checklist errors.
Plant management stated that ongoing efforts to organize checklists and to tag valves would be accelerated to aid in correcting checklist errors.
The Inspector stated that the accuracy of valve checklists would be reviewed during periodic system walkdowns.
Source: NRC Inspection Report No. 50-293/85-31 1/02/86 At 0800, while QLad Cities Unit 1 and Unit 2 were operating in the RUN mode at 78% and 87% of rated core thermal power, respectively, it was discovered that the 1/2 Diesel Generator Cooling Water Pump was inoperable because the circuit breaker control power fuses for the pump had been inadvertently removed during an out of service operation performed at 0530 that morning.
This in turn rendered the i
1/2 Diesel Generator inoperable.
i l
. Event Date Event Description The cause of this occurrence was less than adequate system design. The labels for the control power transformer fuses located at Busses 18, 19, 28, and 29 were not standardized.
The labels for the fuses at Busses 28 and 29 were located directly above their corresponding fuses. At Busses 18 and 19, however, the labels were located below their corresponding fuses and, in'many instances, were closer to the fuses below them than to the correct fuses above them.
This design could result in confusion to personnel operating the equipment.
Source: LER 254-86-003 i
1/07/86 At 0847, with River Bend 1 in Mode 2 at 3% power, a construction employee (insulation) attempted to open a remote data acquisition cabinet (RDAC) panel to seal a conduit and mistook a solenoid actuation switch for a door latch. Water from this actuation ran into two motor control centers and through an unsealed penetration in the floor and eventually into a load center on the next lower elevation.
The resulting short in the load center caused a transformer to burn up which caused the breaker feeding that load center to trip. This breaker also fed two additional load centers, the loss of which eventually I
caused a reactor trip on high Intermediate Range Monitors.
Investigation into the event determined that the solenoid activation switch was unmarked and mistakenly thought to be a door latch. The identification and proper labeling of all similar switches was ongoing.
Source:
LER 458-86-005 1/11/86 At 0749 EST, while St. Lucie Unit 2 was at 99% power, j
the weekly turbine overspeed trip mechanism test was in progress.
This procedure requires operation of a lever labeled TEST, which is adjacent to the turbine manual TRIP lever.
The utility licensed operator performing the test i
erroneously actuated the manual turbine TRIP lever versus the required TEST lever. The turbine trip actuated a reactor trip on loss-of-load as designed.
The root cause for the manual turbine trip and subsequent reactor trip was inattention to detail by a utility licensed operator. The similarity and the close location of the TEST and TRIP levers may have contributed to this erro r.
The turbine T. RIP lever has been painted RED to distinguish it from the TEST lever.
The operator involved has been counselled concerning his actions. Additionally, i
the Training Department will evaluate this item to determine appropriate training requirements and methods.
Source: LER 389-86-002 i
)
8 Event Date Event Description 1/15/86 At 1437, Susquehanna Unit 2 was manually scrammed from approximately 70% power due to overheating of the "B" Phase Main Transformer (2X101B).
Prior to the event, the unit was operating at 100% power.
An alarm on Unit Two Main Transformers annunciated.
Upon investigation by an operator, the transformer was found with a pressure relief device relieving oil from the transformer top.
As a result of the event, the Shift Supervisor implemented a controlled shutdown of the reactor per procedure E0-200-101, " Scram." Reactor recirculation was runback per the procedure, then the reactor was manually scrammed.
l The problem was found to be improper alignment of the knife l
switches to the transformer cooling loops and improper l
labeling of the knife switches. Subsequently, a ground i
fault on one of the cooling fans caused a trip of the feeder breaker and loss of all cooling to the transformer.
l Source:
388-86-004 1/16/86 At 0449, with Byron Unit 1 at 98% power, a reactor trip occurred during performance of the " Bimonthly, Staggered Basis, Reactor Trip Breaker (RTB) Shunt and Under Voltage Trip Independence Test - Train B" surveillance.
The reactor trip occurred due to ambiguities in the temporary procedure in use.
The trip resulted when, with the RTB's aligned to test the "B" RTB (Bypass breaker "B" closed),
the nonlicensed operator incorrectly pressed the Auto Shunt Trip TRIP pushbutton on the Train "A" Auto Shunt Trip Test Panel in lieu of the Train "B" pushbutton. This opened RTB A which tripped the reactor.
As a result of the plant's normal response to the transient an Auxiliary Feedwater actuation occurred on low steam generator level. The plant was restored to stable conditions in Hot Standby at approximately 0520.
The cause of the trip was due to insufficient detail in the procedure to identify which of two nearly identical Auto Shunt Trip Test Panels the operator was to be at.
This was l
compounded by a lack of clear labeling at the panels to l
distinguish Train "A" from Train "B".
To prevent recurrence these cabinets and panels have been more clearly labeled. Additionally, the station's pro-cedure for writing procedures will be revised to require a walk-through of the the procedure prior to issuance,
}
switches be identified as they are labeled in the field, i~
and notes or caution statements be added at steps that cause breaker trips.
Source:
LER 454-86-001
4 4 Event Date Event Description 1/17/86 A loss of residual heat removal (RHR) occurred at 0455 PST, while Diablo Canyon Unit 2 was in cold shutdown.
While attempting to transfer instrument ac panel PY 2-1A from normal to backup power supply, an unlicensed operator went to the wrong panel and inadvertently transferred instrument ac panel PY 2-1 to its backup power source.
This momentary loss of power caused relay actuation which resulted in the closure of RHR valve 8702.
In response to the ensuing loss of flow alarm, RHR pump 2-1 was secured by a licensed operator.
RHR valve 8702 was reopened-from the control room. RHR pump 2-1 was restarted, observed for seal damage, and declared operable at 0508 PST, January 17, 1986.
To prevent recurrence, the operator involved was counseled, operating procedures on transferring instrument ac panel power supplies were revised to require independent verifi-cation of proper devices prior to any equipment operation, and panel identification labels in the instrument ac panels were upgraded such that the panel identification number is clearly visible with the panel door open.
Source: LER 323-86-002 1/22/86 At 1330 hours0.0154 days <br />0.369 hours <br />0.0022 weeks <br />5.06065e-4 months <br />, while Quad Cities Unit I was snutdown for maintenance and refueling, a spurious trip of the IB Reactor Building Vent Monitor occurred which isolated the Reactor Building Ventilation System.
The occurrence would have also initiated the Standby Gas Treatment System [BH],
however it was already operating at the time.
The Technical Staff and Instrument Maintenance Department personnel investigating a problem with the IB Fuel Pool Monitor mistakenly removed a cable from the main chassis housing trip units for the IB Reactor Building Vent Monitor and the IB Fuel Pool Monitor instead of the. alarm cable from the IB Fuel Pool Monitor Trip Unit itself. This occurred because the personnel became confused by the labeling of the connectors on the equipment.
The equipment manual that was being used as a reference showed that the alarm cable from the 18 Fuel Pool Monitor Trip Unit was 1
connected at connector d4.
The personnel saw the J4 connector on the main chassis, and assuming that this was the correct connector, disconnected the cable. This caused a spike and initiated the trip.
The personnel involved in this occurrence were instructed of the importance of verifying that the correct equipment is being worked on before disconnecting any wiring.
Source:
LER 254-86-006 e
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. - Event Date Event Description 1/22/86 At 1127 hours0.013 days <br />0.313 hours <br />0.00186 weeks <br />4.288235e-4 months <br />, while operating at 33% power, Robinson 2 i
received a reactor trip from a Nuclear Instrumentation System (NIS) Power Range High Neutron Flux Trip signal.
At the time of the trip, an evolution was in the process to reduce the NIS trip setpoints on the four Power Range Channels (N-41 through N-44).
The bistable for N-42 was placed in the " Tripped" position and the setpoint reduced. When returning N-42 to " Normal" the individual inadvertently opened the N-43 cabinet and switched the 4
bistable for N-43 to the " Tripped" position.
This satisfied the two-out-of-four channel logic needed to initiate the reactor trip.
Although the N-43 cabinet was labeled, and the bistable trip switch in the cabinet was labeled as to " Normal" and
" Tripped" positions,-some improvements regarding the location of and specific information on the labeling were identified.
To ensure each NIS Cabinet was clearly marked, labeling was added inside each cabinet beside the bistable switch that identifies the associated NIS Channel.
Additional labeling for the cabinet doors identifying the NIS Channel was to be installed near the lock on each door.
The technician involved in this event was counseled and-formally reprimanded by his management.
Source:
LER 261-86-004 1/22/86 At 1717 hcurs, while Waterford Unit.3 was operating at approximately 100% reactor power, Control Element Assembly (CEA) number 88 inadvertently dropped into the core precipitating a Core Protection Calculator (CPC) reactor F
trip.
Upon receiving the reactor trip, an Emergency Feedwater Actuation Signal was generated (this is a. normal occurrence after a trip from high power levels).
Plant conditions were subsequently stabilized in Mode 3 (hot standby).
However, Blowdown Isolation Valves, BD-103A and BD-103B, failed to fully close upon receiving a close signal as a result of the Emergency Feedwater Actuation Signal.
An investigation into the above events revealed that the fan blower toggle switch for the cabinet cooler was in the off position. This may have overheated the Control Element Assembly circuitry resulting in the dropped rod.
Various work groups have been cautioned about performing work in
)
the area.
In addition, a gag was discovered on the above Blowdown Isolation Valves which prevented them from fully closing.
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. Event Date Event Description A change was been made to procedure OP-3-010 to clarify the opening of the Blowdown Isolation Valves and the removal of gags. Also, permanent marks were placed on the valves to identify the neutral position.
In addition, an Operations Daily Instruction was issued on the proper use of gagging devices.
Source:
LER 382-86-002 2/16/86 At 0900 a partial loss of power occurred to the Susquehanna Unit 1, Division I Nuclear Steam Supply Shutoff System. While applying protective blocking to a breaker on the Reactor Protection System (RPS), an operator opened circuit breaker CB3A as specified on the blocking permit.
However, the breaker was incorrectly labeled and was actually RPS circuit breaker CBSA. This caused a loss of Shutdown Cooling, isolation of the Reactor Water Cleanup System, isolation of the Zone III Heating, Ventilation and Air Conditioning System, initiation of the "A" Standby Gas Treatment System and "A" Control Room Emergency Outside Air Supply System, and various other inboard valve isolations.
The breaker was reclosed, the isolation reset, and shutdown cooling restored by 0920.
Four out of eight breakers on both Unit 1 and Unit 2 "A" RPS buses were found to be mislabeled. Temporary labels correctly identifying the circuit breakers were installed the same day.
Permanent labels were later installed.
Other corrective action would be considered pending the results of a Human Performance Evaluation System JHPES) investigation.
Source:
LER 387-86-003 3/10/86 Quad Cities Unit I was in the refuel mode during a refueling and maintenance outage.
Procedure QIS 47-1, Excess Flow Check Valve Surveillance, was in progress when an Anticipated Transient Without Scram (ATWS) [JC] trip was received at 1651 hours0.0191 days <br />0.459 hours <br />0.00273 weeks <br />6.282055e-4 months <br />. All control rods received a scram signal, however no control rod motion occurred since cll rods were already fully inserted.
lA Recirculation M3 Set
[AD] tripped as designed.
Cause of the ATWS trip was due to a valving error by Instrument Mechanics performing the test due to inadequate conucunications between the mechanics. An incorrect instrument rack drain valve was opened causing ATWS reactor level transmitters to see a j
false low reactor level.
. Event Date Event Description The cause of this event was personnel communication error.
While performing QIS 47, an Instrument Mechanic was at one end of the 2201-7 rack opening and closing the backflush header drain valve and monitoring a pressure gauge. A second Instrument Mechanic was 15 feet away from the first.
Instrument Mechanic at the other end of the rack, opening and closing the impulse line drain valve, and checking off the proper steps on the data sheets.
They had just finished pressuring the 1-220-67D check valve and closed the impulse line drain valve C4/X-518.
They drained the backflush header drain line and went on to the next check valve.
The first Instrument Mechanic told the other to go on to the next one.
He meant the next one on the data sheet (C7/X-29E). The Second Instrument Mechanic thought he meant the next valve over (C5/X-498), and opened the impulse line drain valve C5/X-49B instead of impulse drain valve C7/X-29E.
Prior to the C5 valve, all of the valve numbers on the rack had corresponded with the test data sheet seouence:
88, 89, B10, B11, C1, C2, C3, C4. The next valve on the test data sheet after C4 was C7/X-29E, however the next valve on the instrument rack was C5/X-498.
All Instrument Maintenance personnel were made aware of the cause of this event and the importance of good communication.
In addition, the instrument rack drain valves were to be checked for valve tags and retagged if necessary. The Station was also considering using special tags to aid in identifying the valves used for this procedure.
Source:
LER 254-86-013 3/10/86 At 1544, Brunswick Units 1 and 2 common emergency ac 4160V bus E-4 automatically deenergized, thereby deenergizing the units' conmon 480V bus E-8 and Unit 2 Reactor Protection System (RPS) bus B.
Loss of Unit 2 RPS bus B caused Reactor Building ventilation exhaust monitor 2-D12-RM-N010B to trip and initiate a primary containment Group 6 isolation signal and automatic isolation of the building ventilation exhaust dampers.
At the time, an equipment clearance was in place on the E-4 normal bus monitoring potential transformer compartment, AKO.
In addition, emergency ac diesel generator No. 4 and the standby gas treatment trains were under equipment clearances.
Unit I was at 65% power while Unit 2 was in a refuel / maintenance outage.
This event resulted from an Auxiliary Operator inadvertently deenergizing the potential transformer in i
compartment AK0 while searching for fuses removed for the potential transformer interrupted E-4 interlocks and caused involved equipment clearance.
Deenergization of the j
the bus master and slave feeder breakers to automatically i
open.
j
)
. Event Date Event Description The AK0 compartment fuses were located and on 3/10/86, at-1618, E-4 was reenergized.
RPS bus B was.reenergized, RM-N010B was reset, the incurred isolation signals were reset, and the affected systems were returned to service.
As a result of this event, Operations personnel were to receive appropriate training by July 8,1986, concerning bus trip interlocks of the Units 1 and 2 4160V switch-gear.
Appropriate plant procedures would be revised by July 8, 1986, to provide for better instruction concerning placement of electrical fuses which are removed from their respective switchgear for equipment clearances. Also, by June 3, 1986, caution labels were to be placed on the interlocked potential transformer housing covers of 4160V switchgear to indicate the cover is interlocked to deenergize the potential transformer upon opening of the cover.
Source: LER 324-86-008 3/11/86 At 1305 hours0.0151 days <br />0.363 hours <br />0.00216 weeks <br />4.965525e-4 months <br />, D. C. Cook Unit 2 was in Mode 5 preparing for refueling, and cleaning of the Nuclear Instrument (NI) drawers was in progress.
When Power Range (PR) drawer PR-41A was drawr, out, a control power wire inside became entangled with other cables, broke, and caused a short resulting in a one-of-two Intermediate Range (IR) N1 RPS trip.
Twelve minutes later as a' technician attempted to withdraw the broken wire for repair, a second one-of-two IRNI trip occurred.
Note that control power for IRNIS is routed through FRNI drawers.
Finally, a two-of-four PRNI RPS trip occurred at 1335 due to licensee personnel opening the wrong control power breakers.
The wrong breakers were opened due to bad labeling on Control Room Instrument Distribution (CRID) panels which house the breakers.
Socrce:
50.72 Report of 3/11/86
,