IR 05000282/1997021
| ML20197F252 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 12/15/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20197F225 | List: |
| References | |
| 50-282-97-21, 50-306-97-21, NUDOCS 9712300169 | |
| Download: ML20197F252 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli
I Docket Nas:
50 282; 50-306 License Nos:
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Report No:
50 282/97021(DRP); 50 306/97021(DRP)
- Licensee:
Northem States Power Company
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Facility:
Prairie Island Nuclear Generating Plant-
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Location:
1717 Wakonade Drive East Welch, MN 55089 Dates:
' October 22 - December 2,1997 Inspectors:
S, Ray, Senior Resident inspector P. Krohn, Resident insptetor S. Thomas, Resident inspector Approved by; J. W. McCormick-Barger, Chief Reactor Projects Branch 7
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.e 9712300169 971215 PDR ADOCK 05000282
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EXECUTIVE SUMMARY -~
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Pmirle Island Nuclear Generating Plant, Units 1 and 2
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.~ NRC inspection Report No. 50-282/g7021(DRP); 50-306/g7021(DRP)
This inspection was performed by the resident inspectors and included aspects of licensee
- operations, maintenhnce, engineering, and plant support.
Operations
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Normal plant operations were conducted without significant problems. Operators were e-especialty prompt and conservative in responding to a missing ladder that was needed for
access to several valves in the event of a loss-of-coolant-accident and a faulty breaker for
- a control room ventilation fan (Section 01.1),
All operations refueling activities observed were performed well with good pre-evolution e-
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briefs, careful execution, and proper procedure adherence. Activities observed included the flooding of the reactor cavity after the reactor held was removed, the unnatching, drag testing, and relatching of control rods, fuel shuffling, and the filling of the reactor vessel
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after steam generator restoration (Section 01.2).
All equipment responded as expected to the loss of the 10 bank transformer. Operators
'e property followed the appropriate annunciator response and abnormal operating.
procedures to recover from the event.- - The system engineer led a thorough investigation -
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into the cause (Section 01.3).
i Maintenance Maintenance, surveillance, and refueling outage activities were performed well with only
a minor problems. All activities observed were performed safely with proper procedures being used and followed. Activities observed included the disassernbly, inspection, and re-assembly of a main steam isolation valve; removal of the reactor intemals; and an
I emergency diesel generator 24-hour load test. System engineer involvement was strong
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Unit 1 containment penetration checklists and procedures contained inconsistencies L
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significant enough a prevent successful performance of the procedures. Labels-
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. specified by one procedure were not all installed and operators who performed the
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l procedure apparently failed to identify or correct the discrepancies (Section M3.1).
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~ e The Unit 2 containment penetration checklists and procedures demonstrated a much L
improved quality and consistency as compared to those for Unit 1 (Section M3.2l L
Enaineerina -
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System engineers were involved in all aspects of plant operations, refueling, e.
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maintenance, and surveillance activities. The en-ineers rapidly investigated any.
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operational abnormalities, took an active role in maintenance and troubleshooting activities, and closely followed all surveillance testing on their systems (Section E2.2).
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The licensee's discovery that there was no analysis for a dilution accident during
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'~ hutdown conditions was an excellent finding and indicated a thorough Updated Safety--
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- Analysis Repor1 review process (Section E8.6).-
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Plant Suppori The radiation protection staff performed wellin controlling exposures during refueling e
activities (Section R1).
Tlee response of the fire brigade, control room operators, and other licensee personnel to
a fire in thq maintenance shop was good (Section F1.1).
The licensee's finding that the reactor coolant pump oil collection system was inadequate
was a result of a proactive, voluntary review of fire protection issues in preparation for s '
future NRC pilot inspection. Prompt corrective actions were planned to modify the system to be in compliance with NRC requirements (Section F2.1).
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Report Details
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m Summary of Plant Status
Unit 1 ' remained shutdown in a refueling outage for the entire inspection period _ Unit 2 operated -
at or riear full power for the e.ntire inspection period.
I-1 1, Operations
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Conduct of Cperations
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01.1 General Comments al inspection Scope (71707)
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Using inspection Procedure 71707, the inspectors conducted frequent reviews of p8snt
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operations. These reviews included observations of control room evolutions, shift tumovers, logkeeping, as'well as evaluations of operability decir.lons. Section 13, " Plant
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Operations," of the_ Updated Safety Analysis Report (USAR) was revie" ed as part of the
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inspection.
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Observations and Findinas Normal plant operations were conducted without significant problems. The inspectors
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On November 3,1997, the inspectors noted that a ladder, staged for auxiliary
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building operator manipulation of valves CV-31411, CV 31381, CV 31383, and CV-31384, was missing.. Each of those control valves had a mechanical stop
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L designed to limit cooling water flow to the respective component cooling water E
heat exchanger (CCHX). Throttling cooling water flow through the CCHXs was l;
necessary to manage cooling water loads in cr.e a seismic event caused loss of water levelin the plant intake bay. If the emergency core cooling systems needed
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to be subsequently placed in the recirculation mode of operation during a loss of coolant accident event, the auxiliary building operator was required to remove the o
L mechanical stops and restore tull cooling water flow to the CCHXs.
The ladder provided the auxiliary building operator access to the overhead where l-CV-31411, CV 31381, CV-31383, and CV 31384 were located. it was normally L
~ taged adjacent to CV-31411 with a sign indicating its purpose and instructing s
- workers not to move it. The inspectorr, found the ladder under the 22 CCHX
' behind some plywood staged for component cooling system outage work on -
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l Unit 1. The inspectors brought the mislaid ladder to the attention of the auxiliary
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- building operator, The auxiliary building operator located the ladder and retumed it to the normal stov' age position. As an additional corrective action, the shift supervisor promptly nad temporary scaffolding erected for access to the valves.
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. Ths licensee also issued s' work order to install permanent platforms for access to -
j t-E the valves and had started work on that project at the end of the inspection j
Period, e
I On November 26,1997, a reactor operator (RO) taking control room logs noted
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that there was no light indication for the status of the 122 control room cleanup
fan. A local check confirmed that the breaker supplir*g the fan had tripped. The 1'
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.. operators reset the breaker and later ran the fan while the system engineer =
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observed it. The svstem engineer reported that the breaker was defective and ~
initiated a work order for repairs. -
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Operators were not sure exactly when the fan breaker had originally trirped, but i
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know conditions had been normal 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> earlier when the previous set of logs was taken. Although it was usually considered acceptable to start a Technical Specification (TS) allowed outage time from when a piece of equipment is first-i
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discovered to be inopr ; os, the opera %rs conservatively decided to consider the.
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fan to have been inoperable since the previous log readings. Plant electricians promptly completed repairs on the breaker and the system was retumed to an
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operable status the next day.
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Conclusions '
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' All normal operations observed were completed property. On two occasions, operator L
actions were especially prompt and conservative.
C 01.2 Operations Refuelina Activities a.
Inspection Scope (71707)
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l, The inspectors observed significant portions of several operations refueling activities on Unit 1. Major activities observed included flooding the reactor cavity after the reactor l
head was removed, unlatching control rods, drag testing on selected control rods, fuel L
shuffling for refueling, control rod relatching, and filling of the reactor vessel after steam L
generator restoration. _ Updated Safety Analysis Report Section 10.2.1, " Fuel Storage and Fuel Handling Systems," was rcviewed as part of this inspection.
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Observations and Findinas e
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t All operations evolutions observed were carefully performed without significant problams -
1 3 General comment applicable to the evolutions included Mcd pre-evolution briefings, i
proper pmcedures being used and followed, and adequais communications. Noteworthy
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- specific comments are discussed below.
The inspectors observed the pre-evolution brief for uniatching the control rod drive e-
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' shafts and performing drag tests on selected control rods prior to reactor vessel
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y upper internals removal. The inspectors noted that the unistching portion of the.
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brief was very good and that management personnel presented relevant plant
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specific and industry wide lessons teamed regarding this evolution, a thorough
' briefing of the control rod unlatching procedure was given, and a topic specific
_ video.was shown to all personnelinvolved with the evolution; However, the-
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inspectors noted that the briefing for the drag testing portion of the evolution was adequr.te but not as thorough.
The ' ispectort, observed both the unlatching of all of the control rod drive shafts and the drag testing of selected control rods. The inspectors noted that very good
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control and verification was demonstrated during the entire evolution. Three-party verification occurred prior to the connection of the unlatching tool to any control j
rod drive shafts for untatching and/or drag testing. Also, good coordination occurred between personnelin the containment and in the control room during the j
drag testing to monitor for changes in source range indications.
Fuel shuffling operations were observed to be cor.,pleted in a controlled, i
e douberate manner. Three-party verification was used to verify that the correct fuel assembly was being grappled before the tcol was placed on the assembly and that fuel assemblies were about to be placed in the correct locations at the end of the moves. The licensee relaxed the requirement for a nuclear engineer to be one of the individuals performing the verifications and allowed the control room reactor operator to be the third verifier by performing an independent check of the reported location of the rnanipdator crane against the refueling log procedure.
The :ntpectors observed filling of the reactor coolant system (RCS) from the ievel
of the top of the hot legs to one Dot below the reactor vessel flange. The prejob brief was thorough and discussed the procedures to be used, participant 4'
responsibilities, communications, equipment involved in the evolution, expected volume control tank (VCT) pressure transients, potential problems (including RCS dilution and overfilling), the expected volume of water to be added to the RCS, and RCS vent paths. The RO took the additional precaution of having other plant operators locally check the vent path and the status of the charging pump to be used dudng RCS filling.
The RCS level was raised in a controlled and careful manner Control room l
operators checked diver $c indications such as boric acid storage tank levels, VCT levels, hot leg ultrasonic level indicator readings, reactor vessel level indicating system readings, and containment loc.11 standpipe levels to ensure that MCS j
inventory was being increased as expected and that water usage corresponded with the level increase.
During the briefing, the RO discussed the actions that would be taken to add nitrogen to the VCT vapor space if VCT pressure decreased. The RO noted that, although an automatic nitrogen regulator was available to add nitrogen to the i
VCT, no procedure existed to add nitrogen to the VCT automatically. The RO instead referenced and decided to use a procedure describing manual addition of nitrogen to the VCT (Operating Procedure C12.4, "VCT Gas Control," Section 5.5,
" Raising VCT Nitrogen Pressure," Revision 3). After filling die RCS to 1 foot below the reactor vessel flange was complete, the RO submitted a request for a
procedure to automatically add nitrogen to the VCT.
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The inspectors observed the pre evolu'lon brief for latching of the coatrol rod drivo e
shafts and drag testing of all control rods. The brief thoroughly covered all aspects of the latchinc procedure, lessons learned from past control rod latching evolutions, control rod drag testing, and specific instructions on the operation of cpecial tools and lifting devices required by this evolution.
The inspectors observed that the evolution was conducted in a slow and controlltd menner. The inspectors noted that three-party verification was utilized prior to placing the latching tool onto any control rod drive shaft and that good coordination was exercised between personnel conducting the evolution in containment and those monitoring the evolutiun from the control room.
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Qgnpfgjpng All operations refueling activities observed were performed well with good pre-evolution briefs, careful execution, and proper procedure adherence.
01.3 Lqta_gf One Offsite Power Source Transformet a.
Inspection Scope (93702)
On November 17,1997, the sudden pressure relay on the 10 bank switchyard transformer actuated, causing the transformer to automatically isolate. At the time, the 10 bank transformer was supplying safeguards bus 20, on Unit 2, through the 12 cooling tower transformer. The inspectors reviewed the circumstances of the event and the licensee's corrective actions. Updated Safety Analysis Report Section 8.3," Auxiliary Power Gystem," was reviewed as part of this inspection.
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Observations and FirL DR1 After the loss of the 10 bank transformer, bus 26 was automatically repowered from the altomate offsite power source (transformer 2RY) within a few seconds, as designed. The D6 emergency diesel generator did not receive a start signal, nor was one expected, because of the short time the bus was deenergized. All equipment responded as designed. The operating charging pump had been powered from bus 26, therefore, charging flow was lost and the charging and letdown lines isolated Operators promptly restored charging and letdown when the bus was reenergt:ed. Containmer.1 cooling fans and radiation monitor pumps powered from bus 26 were lost and were also promptly restarted. During this time the operators were properly following the appropriate annunciato: response procedure.
When thi cause of the trip was determined and it became known that the 10 bank transformer would not be immediately restored, the licensee decided to cross tie the 11 and 12 cooling tower transformer outputs so that bus 26 could be supplied from the 11 cooling tower transformer. Operators conducted a prejob briefing and completed the cross tie and power transfer using the appropriate abnormal operating procedure without problems. Tha inspectors observed portions of the above evolutions.
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l The system engineer directed a thorough review of the event and attempted to determine the cause of the sudden pressure relay actuation. Oil and gas samples from the transfomier were anatyzed with no unusualIndications. The prersure detector setpoint and relay operation were checked and no problems were found. Only one person was in the switchyard relay house at the time of the event and he was eating lunch in an area not near the relay. When the potential causes of the trip were all examined and eliminated, the licensee carefully reenergized the transformer and gradually applied load while closely monitoring its performance. No problems were identified and the transformer was restored to full service on November 30.
The licens6e reported the event to the NRC in accordance with 10 CFR 50.72 and intended to issue a follow up Licensee Ewnt Repor1(LER). The I.ER will be considered open, when issued, pending inspector review.
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Concluslong All equipment respeded to the loss of the 10 bank transformer as expected. Operators property followed the appropriate annunciator responsa and abncrmal op6.ating procedures la recover from the event. The system engineer led a thorough, but fruitless, investigation into the cause of the event.
02 Operational Status of Facilities and Equipment fDD.nipred Safety S.ystem Walkdown (71707)
i O2.1 The inspectors conducted a walkdown of the containment piping penetrations on Unit 1 in the auxiliary building, shieltf building, and containment building during this inspection period. Containment penetrations on Unit 2 were inspected from the auxiliary building.
The purpose of the inspection was to verify the information in vadous procedures and documents. The results are discussed in Section M3 of this report.
Miscellaneous Operations issues (92700,92901)
08.1 (Closed) LER 50 282/96012 (19612): Loss of Offsite Power to Unit 2 and Degraded Offsite Power to Unit i Followed by Reactor Trips of Both Units. This LER was previously discussed in Integrated inspection Report 50-282/96007; 50-306/96007, Section 01.2, and Inspection Report No. 50-282/96008(DRP); 50-306/9600B(DRP), Section 08.1. The inspectors verified that all corrective actions discussed in the LER were completed except one. The remaining action was to consider improvements to increase the assurance that the emergency response computer system would be available following a loss of power event. Despite extensive troubleshooting, licensee computer engineers were unable to determine why the computer system did not perform as designed during the event.
Without that knowledge, improvements could not be proposed.
The NRC Office for Analysis and Evaluation of Operational Data conducted a review of the event and determined that it was considered an accident sequence precursor for
1996 with a conditional core damage probability of 5.3 x 10 as reported in a letter to the licens2e dated October 9,1997.
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08.2 (Closed) LER 50 282/97007 (197-07). Revision 0 and Revision 1: Both Trains of Spent Fuel Special Ventilation Inoperable While Handling Loads Over Spent Fuel. This event was previously discussed in Inspection Report No. 50 282/97011(DRP);
50 306/97011(DRP), Section 08.2. The inspectors verified that the interim actions for activi'les in the spent fuel pool, as discussed in the LER, were in place until September 15,1997, wtien the NRC issued License Amendenent 130 (Unit 1);
122 (Unit 2) wtilch modified the TGs for fuel handling to correct the problem. As part of the amendment, a new license condition wab imposed which decreased the probability of a fuel damage accident by requiring the use of a single-fallure-proof crane or spent fuel pool covers when handling heavy loads over irradiated fuel.
08.3 fClosed) Violation (VIO) 50-282/97011-03(DRP): 50 306/9701103(DRP): Three Examples of Failure of the Operations Committee to Meet TSs Requirements. This violation was previously discussed in Inspection Reports No. 50 282/97011(DRP);
50 306/97011(DRP), Section 07,1, and 50-282/97016(DRP); 50 306/97016(DRP),
Section 07.1. The I;censeo responded to the violation in a letter dated August 25,1997.
As discussed in the previous reports, the remaining corrective action was to revise Administrative Work 'nstruction SAWI 3.3.0, * Operations Committee," to incorporate management expectation clarifications. The inspectors reviewed Revision 5 to SAWI 3.3.0 issued on September 15,1997, which completed the corrective action.
& Maintenance M1 conduct of Maintenance M1.1 General Comments a.
Inspection Scope (61726. 62707)
The inspectors observer 4 all or major portions of the following maintenance, surveillance, and refueling outage activities. Included in the inspection was a review of the surveillance procedures (SP), work orders (WO), or refueling activity procedures listed as well as the appropriate USAR sections regarding the activities. The inspectors verified that the surveillance procedures observed met the requirements of the TSs.,
SP 1264 Reactor Vessel Level instruments Calibration, Revision 11
SP 1334 D1 Diesel Generator 24 Hour Load Test, Revision 5
SP 2295 DS Diesel Generator Fast Start Test, Revision 19
WO 9707342 Remove Reactor Vessel Upper Intemals per D58.11.5 WO 9707432 P31701 11, Lt.,op A Main Steam Isolation Valve Refuehng
Inspedion
WO 9708818 Reactor Vessel ISI [ Inservice inspection) Exams on the Reactor Vessel and Nonles
WO 9712183 Replace Loop A Main Steam Safety Valves
R101240A Reactor Vessel Head Removal The inspectors also observed minor portions of numerous additional refueling outage activities.
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Observations and findinas For all of the work observed, procedures were property used and followed. Maintenance personnel were experienced and knowledgeable of their tasks. The inspectors observed frequent monitoring of work by system engineers. Noteworthy comments on specific work activities are discussed below, The inspectors observed the disassembly, inspection, and reassembly of the A o
main steam isolation valve during performance of WO 9707432. The inspectors observed performance of a dye penetrant examination on the valve seat. The examination identified five cracks beginning in the valve body and continuing into
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the valve seating area. The dye penetrant examiner recorded the indications and forwarded the information to the system engineer for evaluation. The system
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engineer identified that the same indications had been observed duririg previous refueling inspections and were being monitoied for growth. Comparison with previous inspection results showed that no growth of the cracks was taking place.
The cracks did not affect the structuralintegrity or performance characteristics of the valve.
The inspectors observed the pre evolution brief for the performance of e
WO 9707342, ' Remove Reactor Vessel Upper Intemals per D58.11.5.* The work order accomplished the lifting and removal of the upper reactor vessel intemals and the movement of the vesselintemals to a storage stand located in the reactor vessel cavity. The brief was attended by all personnelinvolved in the evolution and included representatives from operations, plant management, radiation protection, and maintenance. The inspectors noted the brief was thorough and complete.
The inspectors observed the performance of the entire evolution. The task was performed in a slow and controlled manner. The inspectors noted that the rigger in charge of the lift demonstrated good knowledge of the procedure and lifting equipment involved. Also, the radiation protection staff exercised good control of personnel by monitoring for increased general area exposure levels and by moving people to lower dose areas when warranted.
A brief delay was experienced during the initiallifting of the reactor vessel intemais when the maximum weight, as specified in the procedure, was about to be exceeded. After a brief investigation, it was determined that a protective ring, which was normally left behind in the vessel while the intemals were being removed, was still attached to the lifting rig. The reason the protective ring was left attached was to support later inservice inspections. The lifting procedure had not accounted for the extra weight of the protective ring. A temporary procedure deviatk.n was made to the heavy lift procedure and the evolution was completed without further problems.
The inspectors observed portions of SP 1334,"D1 Diesel Generator 24 Hour L.oad e
Test." While the engine was running, operators reported that a fitting (approximately 1.5" by 4.0"), that was part of the oil fill equipment, had been dropped into the diesel's oil sump. The problem occurred during a routine oil
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discussed the situation with the D1 diesel generator system engineer and it was
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determined that the fitting posed no immediate threat t' the engine or its lube on system and that the surveillance procedure could be completed. Subsequent discussions between the inspectors and the D1 system engineer revealed that the proposed corrective actions were to remove the fitting from the oil sump and place a coarse screen in the area of the oil filllocation. The actions were expected to be completed after the Unit i refueling outage.
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Conclusions Maintenance, surveillance, and refueling outage activities were performed well with only minor problems. All cetivities were performed safely with proper procedures being used and followed. System engineor involvement was strong.
M1.2 Reactor Vessel inservice In;oection (ISI) Weld Examinations a.
lanpection Scope (73753)
The inspectors observed portions of WO 9708818," Reactor VesselISI Exams on the Reactor Vessel and Nonles." The activity included an examination of Unit i reactor vessel welds 7 and 10, the nonle to safe end welds, the safe end to pipe welds and the inner redius region of both outlet nonles. The inspectors reviewed the ultrasonic data for all indications recorded during the inspection.
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Observations and Findinal For the strongest reportable indication in the outlet nonles, the inspectors observed the vendor's analysis of the ultrasonic data. The inspectors agreed with the licensee consultant's analysis methods and interpretation of the indication as a manufacturing, non-service related flaw.
The inspectors also reviewed procedure ISI LTS 1, " Limitations to Nondestructive Examination," Revision O. The procedure provided instructions for the identifying, quantifying, and recording of limitations encountered while performing ISI examinations.
When limited ISI examinations were encountered, ISI LTS 1 ensured that the examiner forwarded a descriptio,e of the specific limitations encountered to the licensee field supervisor for review, if after supervisory review, alternate inspection methods were unable to provide additional coverage and the maximum examination coverage was less than 90 percent, ISl LTS 1 required a relief request to be submitted to the NRC.
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Conclusions The inspectors agreed with the licensee's interpretation of the indications reported in the Unit i reactor vessel outlet nonles. The indications reported were original construction, manufacturing flaws and not the result of inservice conditions. Procedure ISI LTS 1 adequately covered situations where less than 100 percent examination coverage was achievable,
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l M3 Maintenance Procedures and Documentation
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M3.1 Unit 1 Containment Pgpetrations and Rela 3d Procedures a.
Inspection Scope (92902)
As a followup of previously identified errors in the documentation regarding some containment penetrations, the inspectors reviewed various checklists, procedures, and documents for the Unit 1 contalnment penetrations. The inspectors reviewed the following:
Integrated Checklist C1.1.19-1, * Containment Integrity Checklist Unit 1,"
Revision 27 Integrated Checklist C1.1.191 " Containment integrity Checklist-Unit 1,*
Revision 26 Integrated Checklist C13, ' Containment integrity Checklist Unit
. Revision 6
H19, * Containment Leakage Rate Testing,' Revision 2 Updated Safety Analysis Report (USAR), Section 5, Table 5.21-(Part A)," Unit 1
Containment Vessel Penetrations," Revision 13, SP 1072.1, * Local Leakage Rate Test of Penetration 1,* Revision 13
SP 1072.2, " Local Leakage Rate Test of Penetration 2," Revision 12
SP 1072.13A, ' Local Leskage Rate Test of Penetration 13A,' Revision 15 SP 1072.18, * Local Leakage Rate Test of Penetration 18,* Revision 12
SP 1072.21, " Local Leakage Rate Test of Penetration 21," Revision 13
SP 1072.25A, * Local Leakage Rate Test of Penetration 25A," Revision 12
SP 1072.250, " Local Leakage Rate Test of Penetration 258," Revision 12
SP 1072.26, * Local Leakage Rate Test of Penetration 26," Revision 18
SP 1072.41 A, * Local Leakage Rate Test of Penetration 41 A," Revision 10 SP 1072.418, * Local Leakage Rate Test of Penetration 418 " Revision 10
SP 1072.42A, * Local Leakage Rate Test of Penetration 42A," Revision 12
SP 1072.42F, ' Local Leakage Rate Test of Penetration 42F,' Revision 10
SP 1072.45, * Local Leakage Rate Test of Penetration 45,* Revision 12
SP 1072.49B, " Local Leakage Rate Test of Penetration 49B," Revision 10
SP i072.50, * Local Leakage Rate Test of Penetration 50," Revision 11
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Observations and Findinat In Integrated Checklist C1.1.191 the inspectors identified the following
discrepancies:
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The schematic associated with penetration 19 did not label valve SA-3 5.
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On page 9 of 102, for penetration 38A, the valve listed with MV 32139 should have been CL-22 3, not CL 221,
On page 9 of 102, for penetration 38B, the valve listed with MV 32133 should have been CL-221, not CL 22-3.
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Valve AF-30-1, which was associated with penetration 46A, was listed twice, on two different elevations.
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Valve AF-30-2, which was associated with penetration 46B, was listed twice, on two different elevations.
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Special Instruction (note 5) of Integrated Checklist C1.1.19-1 stated, " Containment e
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Integrity tags (blue tags) should be installed / verified in
"ed, during performance of this checklist. Containmont integrity tags should be v,' led on all components in this checklist." The inspectors identified the discrepas.1..J listed below during a spot check. Brown tags were formerfy used for marking components.
Components not Components Components, not labeled with blue labeled with required by the tags brown tags checklist, labeled with brown tags CV 31741 MV-32065 CV 31447 CV 31634 MV 32066 S116-4 CV 31311 MV 32199 SI 16-5 MV 32141 MV 32273 81-16-6 MV 32135 MV 32024 8120 30 CL 57 5 CV 31444 SI 21 1 CL 57-3 RC 31*
CV 31449 MV 32242 Penetration 498 MV 32069 inner blind CV 31458 flange *
MV 32068 CV 31450
- labeled with VC-16-18 both brown and blue tags The above discrepancies indicated a lack of attention-to-detail on the part of the operators who last performed the checklist, The inspectors performed a spot check of the physical condition and labeling of e
the containment vessel penetrations. The condition and labeling of the inspected penetrations was good, with no observed discrepancies, e
in USAR Table 5.21-(Part A), the following discrepancies were noted:
1.
On page 1 of 0, referring to penetration 6A, the valve listed as CV-31908 should have been CV 31098.
2.
On page 3 of 6, referring to penetration 29A, the valves listed (CS 18, MV-32103, and CS 11) should have been associated with penetration 298. The valves that should have been listed with penetration 29A were CS 19, MV 32105, and CS-12. After further discussion with the licensee and review of planned corrective documentation, the inspectors loamed that this discrepancy had already been identified by the licensee during the USAR update program and that corrective actions would be taken.
3.
On page 3 of 6, referring to penetration 298, the valves listed (CS-19, MV 32105, and CS 12) should have been associated with penetration 29A. The valves that should have been listed with penetration 29B were CS-18, MV 32103, and CS 11. After further discussion with the licensee
and review of planned corrective documsntation, the inspectors teamed that this discrepancy had already been identified by the licenseo during the USAR update program and that corrective actions would be taken, e
During a cross-reference check of Integrated Checklist C1.1.191 and the penetration specific local leakago rate surveillance procedures (SP 1072 series),
the inspectors identified the following inconsistencies in the given location of the containment vessel penetrations:
Penetration Number Location per Location per Integrated Checklist penetration specific C1.1.191 procedure
728'6" 323'
724'
39'
723'
39'
725'
330'
13A 729'6" 330'
720'
274'
715'
240'
716'
240*
720'
271*
720'
269'
25A 770'
316'
770'
345'
258 770'
345'
770'
316'
720'
226'
720'
266'
41A 783'
57'
806'
57'
418 806'
57'
760'
57'
42A 723'
262'
724'
37'
42F 723'
37'
723'
350'
719'
40'
738'
278'
49B 719'
43'
720'
43'
723'
41'
720'
43'
c.
Conclusions The Unit 1 containment penetration checklists and procedures contained inconsistencies between procedures and editcrial errors within procedures. Although many errors were corrected by Revision 27 to the Containment integrity Checklist-Unit 1, there were still many remaining Most of the component labeling discrepancies and editorial errors should b
' been identified and addressed during performance of the checklist and incorpov into Revision 27, That failure indicated lack of attention to-detail on the part of the opc.ators who last performed the checklist. However, the errors were not significant enough to prevent successful performance of the checklist. After being informed of the above errors, the licensee actively pursued correcting the discrepancies.
The USAR discrepancies also appeared to be editorialin nature and were of minor safety significance.
M3.2 Unit 2 Containment Penetrations and Related Procedures a.
Inspection Scope (92902)
The inspectors reviewed various checklists, procedures, and other documents regarding all of the Unit 2 containment penetrations. The inspectors reviewed the following:
Integrated Checklist C1.1.19-4, * Containment integrity Checklist-Unit 2,*
Revision 24 Integrated Checklist C13, *Containtnent integrity Checklist Unit
- Revision 0
Updated Safety Analysis Report, Section 5, Table 5.2-1-(Pari B), " Unit 2
Containment Vessel Penetrations,' Revision 13 Updated Safety Analysis Report, Section 5 Table 5.21-(Par 1 A), " Unit 1
Containment Vessei Penetrations,' Revision 13 SP 2072.1," Local Leakage Rate Test of Penetration 1,* Revision 8
SP 2072.2, * Local Leakage Rate Test of Penetration 2,* Rev!sion 8
SP 2072.11, " Local Leakage Rate Test of Penetration 11,* Revision 7
SP 2072.16, * Local Leakage Rate Test of Penetration 16,* Revision 10
SP 2072.20, ' Local Leakage Rate Test of Penetration 20,* Revision 16
SP 2072.23, * Local Leakage Rate Test of Penetration 23,* Revision 10
SP 2072.31, * Local Leakage Rate Test of Penetration 31,* Revision 10
SP 2072.44, * Local Leakage Rate Test of Penetration 44,* Revision 8
SP 2072.52, * Local Leakage Rate Test of Penetration 52,* Revision 13
SP 2072.55, * Local Leakage Rate Test of Penetration 55,* Revision 8
b.
Observations and Findinas The inspector identified that the * containment integrity tag' for valve CV 31209
was hung on the piping adjacent to the valve and not on the component itself.
In Integrated Checklist C1.1.19-4 the inspectors identified the following:
1.
On the schematic for penetration 28B, the valve labeled CV-31516 should have been labeled CV-31518, 2.
Valve 2CS 24 2, which was associated with penetration 298, was labeled with a containment integrity tag even though not required by the checklist.
- The inspectois performed a spot check of the physical condition and labeling of
the auxiliary building penetrations. The condition and labeling of the inspected penetrations were good, with no observed discrepancies.
The inspectors compared the Containment integrity Checklist Unit 2 (C1.1.19-4)
and the Unit 2 specific localleak rate surveillance procedures. No inconsistencies were noted in the given locations for any of the listed penetrations.
in USAR Table 5.21-(Part B), for penetration 12, the table listed 2VC-8 2 as the e
required isolation valve. The correct valve was 2VC-81. After discussion with the licensee, and review of planned corrective documentation, the inspectors leamed that this discrepancy had already been identified by the ongoing USAR update program and that corrective actions would be taken.
c.
Conclusions The discrepancies with the Unit 2 checklists and procedures were generally editorial or
,
l minor in nature. No unlabeled components were found and the corresponding auxiliary l
building penetrations were clearly labeled. The Unit 2 checklists and procedures demonstrated a much improved attention to detail and consistency compared to Unit 1.
_ _ _
After being informed of the above errors, the licensee actively pursued correcting the discrepancies. The one USAR discrepar'cy was licensee identified and appeared to be editorialin nature and of minor safety significance.
M8 Miscellaneous Maintenance Activities (92700,92902)
M8.1 (Closed) LER 50 282/97005 (197-05): Survell'ance interval Discrepancies with Diesel Oil Sample Analyses. This event was previously discussed in Inspection Report No. 50 282/97011(DRP); 50-306/97011(DPP), Section M8.2. It was considered a Non Cited Violation (NCV 50-282/97011-04(DRP); 50 306/97011-04(DRP)). The inspectors verified that the corrective actions discussed in the LER were completed. The licensee determined that nJmerous other surveillances, such as battery and charcoal efficiency tests, which requ: red laboratory or other analyses, were also being counted as complete before the analyses were done. The surveillances were revised to insure that all required analyses were completed before the surveillances were counted as complete.
M8.2 [C.kthed) VIO 50-306/97002 04(DRP): Inadequate Procedure for Control of Heavy Loads.
This issue was previously discussed in inspection Reports No. 50 282/97002(DRP);
50-306/97002(DRP), Section M3.1, and 50-282/97005(DRP); 50 306/97005(DRP),
Section M3.1. The licensee also discussed the issue in LER 2 97 01. The licensee responded to the violation and discussed the corrective actions in a letter to the NRC dated March 26,1997. On March 18,1997, a predecisional enforcement conference was held for another violation involving control of heavy loads, and a Notice of Violation for that event was issued on April 30,1997 (Enforcement Action (EA) 97 073/01013(DRP)).
Since the licensee's corrective actions for both violation 50-306/97002 04 and the enforcement action were closely related in that the entire heavy loads program was undergoing a comprehensive review, the complete set of corrective actiuns will be reviewed when EA 97-073 is closed. This violation was closed to avoid duplication.
Ill. Enoineerino E2 Engineering Support of Facilities and Equipment E2.1 Review of USAR Commitments (37551. 92903)
While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the USAR that related to the areas inspected and used the USAR as an engineering / technical support basis document. The inspectors compared plant practices, procedures, and/or parameters to the USAR descriptions as discussed in each section. The inspectors verified that the USAR wording was consistent with the observed plant practices, procedures, and parameters. Some minor discrepancies were noted regarding Table 5.21 for containment penetrations as discussed in Section M3 of this report.
E2.2, General Comments (37551)
Throughout the inspection period, the inspectors noted frequent involvement by system engineers in all aspects of plant operations, refueling, maintenance, and surveillance activities. The engineers rapidly investigated any operational abnormalities, took an
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active role in maintenance and troubleshooting activities, and closely followed all surveillance testing on their systems.
E8 Miscellaneous Engineering lasues (92700,92903)
E8.1 (Qjosed) LER 50 306/96001 (2 96-01): Reactor Trip Caused by Failure of Feedwater Regulating Valve. This event was previously discussed in Integrated Inspection Reports No. 50-282/96004; 50 306/96004, Sections 1.2 and 3.2,50 282/96006; 50 306/96000, Section 08.1, and 50 282/96007; 50 306/96007, Section E2.2. The licensee completed a Spare Parts Change Evaluation to modify the feedwater regulating valve stem joint configuration and increase the joint resistance to torsional moments. The modification was made to the Unit 2 valves in the 1997 spring outage and to the Unit i valves in the 1997 fall outage. Prior to the modification, the valves were instrumented and stem torsional stresses were measured in various flow regimes. Stresses were found not to be excessive in any postilon for the valve design.
Although the licensee determined that operating procedures did not need to be changed to expedite transition through the low flow region during plant startup, the inspectors'
observations in several recent startups indicated that operators were sensitive to avoiding long term operation with the feedwater regulating valves in low flow regions. For a different reason, there was already a precaution in Operating Procedure 1(2)C1.2,
" Unit 1(2) Startup Procedure," Revision 17, to minimize the time spent between hot standby and 15 percent power. In addition, Operating Procedure 1(2)C28.2," Unit 1(2)
Feedwater System," Revision 11(8), contained precautions, notes, and steps, intended to help minimize the time the feedwater regulating valves were operated in now flow conditions.
E8.2 (Closed) Inspection Followun item (IFI) 50-282/96007-03fDRP): Resolution of Incorrectly Stated Hydrogen Monitor System Component Locatlans in USAR, Section 5.4.2.2.3. This issue was previously discussed in Integrated Inspection Report No. 50 282/96007; 50 306/96007, Sections E2.3 and E8.1. It involved an inaccurate statement in the USAR regarding the location of the containment hydrogen monitor system data acquisition and control assemblies. The inspectors verified that the most recent revision of the USAR deleted the inaccurate information.
- E8.3 (Closed) IFl 50-282/96010-02(DRP): Drawing Error in USAR. This issue was previously discussed in inspection Report No. 50 282/96010; 50-306/96010, Sections M3.1 and E2.1. It involved an error in USAR Figure 11.15, Revision 13. The inspectors verified that the USAR figure had been corrected in Revision 14 (Drawing NF 39222, Revision AW).
E8.4 (Closed) LER 50-282/96019 (196-19): Spent Fuel Storage Racks Outside Design Basis due to Boroflex Degradation. This LER was previously discussed in Inspection Report No. 50 282/96016; 50 306/96016, Section E8.1. On June 12,1997, the NRC issued License Amendment 129 (Unit 1); 121 (Unit 2) which established the TSs necessary to take credit for soluble boron in the spent fuel poolinstead of Boroflex. The inspectors verified that the TS changes granted by the amendment had been implemented.
E8.5 (Open) LER 50382/97011 (197-11): Failure to Test the Low Pressure Auto-start Function of 121 Motor Driven Cooling Water Pump and inadequate Separation Between
Trains A and B Low Pressure Auto start Switches. This LER was previously discussed in inspection Report No. 50-282/97018(DRP); 50 306/97018(DRP), Section E1.1. The LER was left open pending a review of the enforcement aspects of the f~mdings.
As reported in the LER, the licensee-identified findings involved both a violation of the TS 4.5.A.S.a surveillance requirements and reflected a failure to assure that the design basis for switch separation was properly translated into specifications, drawings, procedures, and instructions in accordance with 10 CFR 50, Appendix B, Criterion Ih.
However, the issues were licensee-identified as part of the actions to address NRC Generic Letter 96-01. Conceming the low pressure auto start function, although it was not regularly tested, the low pressure detector setpoint was routinely calibrated. In addition, several actual starts of the pump on low pressure have been documented as a result of operational events. Conceming the switch separation issue, the 121 cooling water pump was not usually considered a safety related pump and inadequate separation would only be a condition outside the design basis on the relatively rare occasions when the 121 pump was aligned to replace the 22 cooling water pump. In those cases, a single fault might affect both the remaining 121 and 12 cooling water pumps.
The licensee's corrective actions, as discussed in the LER, were adequate to resolve the issues. The low pressure auto start feature was successfully tested during this inspection period. A design change to move the switch was being developed and was anticipated to be completed in early December 1997. The LER will remain open until the completion of the design change.
These non-repetitive, licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-282/97021-01(DRP); 50-306/9702101(DRP)).
E8.6 (Open) LER 50-282/97012 (197-12): Chemical and Volume Control System Malfunction Unanalyzed for Boron Dilution During Shutdown Modes of Operation. As part ofits ongoing USAR review project, the licensee discovered and reported that there was no analysis for a potential boron dilution accident occurring in shutdown conditions. The results of such an accident might be more severe than the analyzed accident at power because operators might have less time to recognize and correct the condition due to l
decreased effective reactor coolant system volume, The licensee also reported that a t
boron dilution event, when the residual heat removal system was retuming flow via the
!
vesselinjection path insiead of the normal cold leg path, could result in a different type cf
'
dilution translent because thorough mixing of the water in the reactor vessel would not occur.
,
The discovery was an excellent finding and indicated a thorough USAR review process, initiallicensee actions to specify higher shutdown boron concentrations and assure adequate mixing when returning residual heat removal flow through the vessel injectbn path (the licensee intended to run at least one reactor coolant pump when in that condition) were adequate to compensate for the lack of final analysis results. The LER I
will remain open pending an NRC specialist's review of the long-term corrective action results.
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IV. Plant Support R1 Radiological Protection and Chemistry Controls (71750)
During normal resident inspection activities, routine observations were conducted in the areas of radiological protection and chemistry controls using inspection Procedure 71750. No discrepancies were noted. The inspectors noted good performance of the radiation protection staff in controlling exposures during refueling activities.
P1 Conduct of Emergency Preparedness Activities (71750)
During normal resident inspection activities, routine observations were conducted in the area of emergency preparedness using inspection Procedure 71750. No disempancies were noted.
Si Conduct of Security and Safeguards Activities (71750)
Curing normal resident inspection activities, routine observations were conducted in the areas of security and safeguards activities using Inspection Procedure 71750. No discrepancies were noted. The Superintendent Security and Team Leader Security Services met with the inspectors during the inspection period to provide a briefing of current security activities and plans.
F1 Control of Fire Protection Activities F1.1 Fire in the Maintenance Shop a.
Inspection Scope (93702)
Cn October 28,1997, a fire was reported in the maintenance shop which was located in the service building off of the 735 foot elevation of the turbine building. The inspectors observed the response to the event from the control room and Technical Support Center.
b.
Observations and Findinas The licensee's fire brigade responded rapidly to the event with sufficient personnel and equipment. The fire brigade leader clearly established his authcrity and properly followed response procedures. The fire was located in an air filtration unit serving a cutting and welding table. Although there was apparently only a small fire in the unit, smoke discharge was very heavy due to a service air supply blowing through the unit. It took about 20 minutes to identify the air supply and isolate it.
Personnel were immediately evacuated from the adjacent maintenance and computer areas and eventually the entire turbine building was evacuated. The Technical Support Center was manned in order to assist in personnel accountability. Other actions taken ir.cluded calling the city of Red Wing fire department, starting the control room cleanup fans, isolating the control room outside air dampers, starting the turbine building roof exhaust fans, and isolating the service building computer room halon system.
The Red Wing fire department responded to the site but the fire was out and smoke was being cleared by the time they arrived on the scene. The fire department ambulance service briefly treated 11 employees for smoke inhalation and one additional employee
- -
f was administered oxygen by the licensee's safety department personnel. All employees retumed to work after treatment.
j The cause of the fire was believed to be a spark or hot particle drawn into the air filtration unit, igniting the paper filter. The unit apparently contained a large amount of dust end I
slag which contributed to the fire. Smoke was released primarily from a duct which was blown off by a series of small dust explosions in the unit.
At the time of the event, the licensee made a Notificatiori of Unusual Event due to a fire lasting more than 10 minutes and notified the NRC in accoraance with 10 CFR 50.72. On November 24,1997, the licensee also voluntarily issued I.ER 19714 for the event. The LER is closed in Section F8.1 of this report.
c.
Conclusiant The response of the fire brigade, control room operators, and other licensee personnel to the fire was good. No significant discrepancies were noted.
F2 Status of Fire Protection Facilities and Equipment F2.1 Inadequate Lubo Oil Collection System for Reactor Coolant Pumos a.
Lrtspection Scope (92904)
On November 11,1997, thw ilcensee reported in accordance with 10 CFR 50.72 a condition outside the design basis of the plant whereby the lube oil collecten system for reactor coolant pumps on both units did not meet all the requirements of 10 CFR 50, Appendix R, Section Ill.O. The inspectors reviewed the circumstances of the finding and the licensee's corrective actions.
b.
Observations and Findinas During a walkdown of the lube oil collection system by a consultant, the licensee identified that the system was not adequate to contain a pressurized oil 1:ak from the oil lift pump system piping. The oil colisction system was adequate to collect leakage from the low pressure portions of the tube oil system.
The licensee could not immediately determine why a system capable of collecting pressurized oilleakage had not been originally installed. The licensee had requested and received an exemption from another of the requirements of Section 111.0 of Appendix R,
- that the oil be collected and drained to a vented closed container, as discussed in a letter from J. R. Miller (NRC) dated July 31,1984, but no exemption from the requirement to have the ability to collect pressurized leakage was identified. The NRC had conducted an inspection of the implementation of Appendix R requirements as discussc:t in inspection Report 50-282/87004(DRO); 50-306/87004(DRS) and determined that the colle:: tion system was in conformance with Section ll1.0 of Appendix R. However, it was not clear from that report whether the inspectors were aware that pressurized leakage might not be collected. The inspection apparently was primarily focused on verifying the licensee's justification for the exemption request.
_ __ As an interim corrective action, the licensee issued temporary changes to the reactor coolant pump operating and annunciator response procedures to specify an inspection of the reactor coolant pump area attor the last start of the oillift pump prior to full power operations and after a low oillevel alarm. The licensee discussed the issue with the NRC Office of Nuclear Reactor Regulation by telephone on November 21,1997. After the discussion, the licensee agreed to modify the collection system on Unit 1 prior to startup from the current refueling outage and on Unit 2 at the first shutdown of sufficient duration.
The Operations Committee reviewed Design Change 97FP02 on November 25,1997, which was to correct the problem.
The inadequate oil collection system was only of moderate safety significance because the oillift system was normally only pressurized for short times and plant conditions at those times wt not normally expected to be such that an oilleak would ignite. In addition, there was no safe shutdown equipment in the immediate area of the reactor coolwnt pumps. Although there have been fires at other facilities due to pressurized leakage from the oil lift pumps, the fires usually involved cases where the lift pumps were run foi extended periods and/or fibrous insulation in the area was oil soaked. For the Prairie Island facility, the insulation in the area is metal reflective type and is not subject to oil soaking.
Section Ill.O of Appendix R, of 10 CFR Part 50 required, in part, that reactor coolant pumps be equipped with an oil collection system, if the containment is not inerted during normal operation, and that such collection systems shall be capable of collecting lube oil from all potential pressurized and unpressurized leakage sites in the reactor coolant cump lube oil systems. However, the licensee identified that the collection systems for both reactor coolant pumps on both units were not capable of collecting lube oil from all potential pressurized sites in the oillift pump system. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.a.1 of the NRC Enforcement Policy (50 282/9702102(DRP);
50-306/9702102(DRP)).
The licensee intended to issue an LER for the finding. The LER will be considered open, when issued, pending the inspectors' review.
c.
Conclusipm The licensee's finding was the result of a proactive, voluntary review of fire protection issues in preparation for a future NRC pilot inspection. Prompt corrective actions were planned to modify the system to be in compliance with NRC requirements.
F8 Miscellaneous Fire Protection issues (92700)
F8.1 (Closed) LER 50-282/97014 fi 9714): Maintenance Shop Fire in the Service Building.
This event was discussed in Section F1.1 of this report. The report was submitted as voluntary supplementalinformation for the Notification of Unusual Event. The inspectors verified that the report adequately discussed the cause and contributing factors for the event and that corrective actions would be tracked through the licensee's Error Reduction Task Force.
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V. Mananoment Megtinas
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X1 Exit Meeting Summary
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i The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on December 2,1997. The licen6ae acknowledged the findings l
presented. The inspectors asked the licensee whether 6ny materials examined during the l
Inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED f
UcensSS J. Soreneen, Plant Manager
'
K Albrecht, General Superintendent Engineering, Electrical / Instrumentation & Controls
T. Amundson, General Superintendent Engineering, Mechanical i
J. Goldsmith, General Superintendent Engineering, Generation Services
>
J. Hill, Manager Quality Services
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G. Lenertz, General Superintendent Plant Maintenance
J. Makl. Outage Manager
D. Schuelke, General Superintendent Radiation Protection and Chemistry T Silverberg, General Superintendent Plant operations
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M. Sleigh, Superintendent Security
INSPECTION PROCEDURES USED IP 37551:
Engineering
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IP 61726:
Surveillance Observations lP 62707:
Maintenance Obnivations IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
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IP 73753:
Inservice inspection
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IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor
,
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Facilities IP 92901:
Follow up Operations IP 92902:
Follow up Maintenance IP 92903:
Follow up - Engineering IP 92904:
Follow up Plant Support IP 93702:
Prompt Onsite Follow up of Events
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 60 282/97012 LER Chemical and Volume Control System Malfunction Unanalyzed for Boron Dilution During Shutdown Modes of Operation 50-282/97021-01(DRP)
NCV Failure to Test the Low Pressure Auto start Function of the 50-306/9702101(DRP)
121 Motor Driven Cooling Water Pump and inadequate Separation Between Trains A and B Low Pressure Auto-start Switches 50-282/9702102(DRP)
NCV Inadequate Lube Oil Collection System for Reactor Coolant 50-306/9702102(DRP)
Pumps Closed 50 306/90001 LER Reactor Trip Caused by Failure of Feedwater Regulating Valve 50-282/90012 LER Loss of Offsite Power to Unit 2 and Degraded Offsite Power to Unit 1 Followed by Reactor Trips of Both Units 50 282/90019 LER Spent Fuel Storage Racks Outside Desl0n Basis due to Boroflex Degradation 50 282/97005 LER Surveillance interval Discrepancies with Diesel Oil Sample Analysis 50 282/97007 LER Both Trains of Spent Fuel Special Ventilation Inoperable While Handling Loads Over Spent Fuel 50-282/97014 LER Maintenance Shop Fire in the Service Building 50 282/96007 03(DRP)
IFl Resolution of incorrectly Stated Hydrogen Monitor System Data Acquisition Components in Updated Safety Analysis Report, Section 5.4.2.2.3 50 282/96010-02(ORP)
IFl Drawing Error in the Updated Safety Anutysis Report 50-306/97002 04(DRP)
VIO Inadequate Proceduce for the Control of Heavy Loads 50-282/97011-03(DRP)
VIO Three Examples of Failure of the Operations Commatee to 50-306/97011-03(DRP)
Meet Technical Specifications Requirements
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i piscussed
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VIO Inadequate Control of Heavy Load over the Reactor
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50 262/97011 LER Failure to Test the Low Pressure Auto start Function of the
121 Motor Driven Cooling Water Pump and inadequete
[
Separation Between Trains A and B Low Pressute Auto-
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start Switches
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t LIST OF ACRONYMS USED l
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CCHX Componeret Cooling Her.1 Exchanger l-CFR Code of Federal Regulations
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DRP Division of Reactor Projects
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DRS Division of Reac;or Safety
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L EA Enforcement Action 181 Inservice inspection i
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IP Inspection Procedure LER Llodnsee Event Report
NOV Non Cited Violation
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NRC Nuclear Regulatory Commission
PDR Public Document Room i
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RO Reactor Operator SP Surveillance Procedure
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USAR Updated Safety Analysis Report
.-YGT Volume Control Tank
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, %ht Work Order
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