Text

Insp Rept 50-263/97-03 on 970220-0411.No Violations Noted. Major Areas Inspected:Operations,Maint & Engineering
	ML20141D678
Person / Time
Site:	Monticello
Issue date:	05/09/1997
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20141D664	List: IR 05000263/1997003; ML20141D659;
References
	50-263-97-03, 50-263-97-3, NUDOCS 9705200171
	Download: ML20141D678 (44)
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U.S. NUCLEAR REGULATORY COMMISSION

REGION lli l

Docket No.:

50-263 License No.:

DPR-22 Report No:

50 263/97003(DRP)

Licensee:

Northern States Power Cornpany

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i Facility:

Monticello Nuclear Generating Station Location:

414 Nicollet Mall Minneapolis, MN Gr 401

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Dates:

February 20 - April 11,1997 Inspectors:

A. M. Stone, Senior Resident inspector J. Lara, Resident inspector

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l M. Bielby, Operator Licensing inspector T. J. Kim, Project Manager l

V. P. Lougheed, Reactor Inspector

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Approved by:

J. Jacobson, Chief, Projects Branch 4 Division of Reactor Projects l

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9705200171 970509

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t EXECUTIVE SUMMARY

Monticello Nuclear Generating Station, Unit 1 NRC Inspection Report 50-263/97003(DRP)

This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 7-week period of resident inspection.

Ooerations Initial operations personnel response to the loss of power event was observed to be

good. However, weaknesses were apparent in attention to detail during the restoration of plant equipment to standby status and walkdown of control room panels (Section 01.2).

Generation Quality Services personnel demonstrated a good questioning attitude

through the reviews of Technical Specifications interpretations (Sections 07.1 and 07.2).

Maintenance Maintenance activities were generally performed in a thorough and professional

manner. However, some problems encountered during these activities indicated a weakness in the technical adequacy of work instructions (Section M1.1).

Personnel errors during the performance of the undervoltage relay surveillance test

caused a loss of voltage to bus 15. Inattention to detail resulted in leaving a test meter installed (Section M1.2).

Although the cause of an uninterruptible power supply normal power source

transfer could not be positively identified, troubleshooting activities were well performed. Administrative Limiting Condition for Operation was properly implemented to limit the time that the inverter was on the alternate power source (Section M2.2).

The licensee had not determined the cause of a generator gross load computer

point alarm at the end of the inspection period. Engineering efforts continued to attempt to identify the cause of the alarm (Section M2.3).

Enaineerina

The actions to resolve the residual heat removal service water air vent valve failure I

problem were mixed. Installation of a permanent cast steel surge check valve was

not successful, apparently due to a difference in flange design between the air vent valve and the surge check valve which was not identified during the modification process (Section E2.1).

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PJpnt Sucoort

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Security personnelimplemented prompt corrective actions as a result of a security

issued identified at another utility. (Section S1)

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Report Details

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Summarv of Plant Status The unit operated at power levels up to 100 percent power for most of the inspection report period. The Mississippi River levelincreased significantly toward the end of the inspection period. Operations personnel monitored levels and initiated flooding precautionary actions. On April 8,1997, a loss of voltage to 4160 V bus 15 occurred due to personnel error during a surveillance test. Both emergency diesel generators (EDG)

started with #11 EDG supplying power to bus 15.

I. OperatiRDA

Conduct of Operations 01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. These reviews included observations of control room evolutions, shift turnovers, operability decisions, logkeeping, etc. Updated Safety Analysis Report (USAR) Section 13, " Plant Operations," was reviewed as part of the inspection.

i in general, the conduct of operations was acceptable; specific events and notewor-thy observations are detailed in the sections below. Operator performance during routine surveillance activities was excellent. Discrepancies were promptly identified, communicated to operations management, and resolved satisfactorily.

For example, the operators demonstrated a good questioning attitude during the prejob briefing for the reactor water clean-up modification test. This issue is discussed in Section M1.1.

Operator performance during non-routine activities was mixed. Operations

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personnel responded appropriately when the inverter power source swapped to the alternate supply. However, operators were unaware that the #13 emergency service water (ESW) pump had started and was operating for 2 days without j

notice. This event is discussed below.

During this period, operator requalification examinations were conducted. The results were documented in inspection Report 50-263/97004.

01.2 Loss of Voltaae to Bus 15 Durina Surveillance Testina a.

Insnection Scone (71707 and 93702)

On April 8,1997, the licensee performed a surveillance test associated with the essential bus undervoltage relays. During this test, a loss of voltage to bus 15

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occurred. The activities leading to this event are discussed in Section M1.2. This

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discussion focuses on operations personnel performance.

The following documents were reviewed:

Test procedure 0301, " Safeguard Bus Voltage Protection Relay Unit

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Functional Test" Procedure C.4-F, " Rapid Power Reduction"

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Operations Manual B.8.1.4-01, " Emergency Service Water"

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Operations Manual B.9.06.C, " Loss of Bus 15 or Bus 16"

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Operations Manual B.9.8-05, " Emergency Diesel Generators"

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b.

Observations and Findinos A prejob briefing was conducted to alert the control roorn operators of expected alarms and the pending test of electrical relays. Shortly after the briefing, operators received alarms indicating an automatic start of both the #11 and 12 EDGs due to loss of voltage to the 4160 V essential bus 15. Control room annunciators indicated that the normal power source to bus 15 had tripped open. Operators noted that voltage to bus 15 was restored. However, a few seconds later, the bus was again de-energized when the feeder breaker from the alternate power source (transformer 1 AR) tripped. Since the #11 EDG had already received a start signal, its output circuit breaker closed onto bus 15 to restore power. The #12 EDG was running unloaded since bus 16 was still powered by offsite power sources.

The loss of voltage to bus 15 and its corresponding motor control centers resulted in the trip of the #11 circulating water pump. In anticipation of a condenser vacuum perturbation due to the loss of this pump, operators reduced reactor power via recirculation flow by about 40 MWe. Once the cause of the voltage loss to bus 15 was determined, operators restored the normal power supply to bus 15 by synchronizing the running #11 EDG with the offsite power source. Both operating EDGs were then secured. Restoration of tripped equipment also commenced to restore the plant configuration to normal status. In accordance with 10 CFR 50.72, a 4-hour non-emergency notification was made due to the automatic start of both EDGs.

The inspectors were in the control room at the time of this event and observed good operator response to the plant conditions. Good communication and teamwork were noted. Shift management maintained a good overview of activities and ensured appropriate procedures were available and adhered to. Emergency operating procedures were available and used in response to a reactor building positive pressure alarm. Status briefings were informative.

However, on April 10, the inspectors reviewed the control room panels and noted that the #13 ESW pump was operating as indicated by the red status light. When l

questioned by the inspectors, operators were unable to explain why the pump was

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operating and secured the pump a few minutes later. The licensee initiated condition report (CR) 97001149 to document the #13 ESW pump start and

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f operation. Preliminary licensee reviews indicated that the pump had been operating s

since the April 8, loss of power to bus 15 event. The pump start logic automatically started the pump upon a transfer of the power supply to bus 15 from the normal to the alternate sources (transformer 1 AR and #11 EDG). Manual operator action was required to secure the ESW pump when autometically started.

However, the ESW pump was not secured and returned to normal standby status following restoration of normal power to bus 15. This condition had existed for about 46 hours5.324074e-4 days 0.0128 hours 7.60582e-5 weeks 1.7503e-5 months prior to identification by the inspectors. During this time, four shift turnovers involving three crews had occurred between shift management, control room operators and auxiliary plant operators.

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The operators performance during this event is considered an Unresolved item (50-263/97003-01) pending review of the root cause and corrective actions.

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Conclusions Initial operations personnel response to the loss of power event was observed to be good. Team work and good communications were noted. However, weaknesses in

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attention to detail during the restoration of plant equipment to standby status and l

walkdown of control room panels were identified,

Operational Status of Facilities and Equipment O 2.1 Enaineered Safetv Feature System Walkdowns The inspectors used Inspection Procedure 71707 to walk down selected portions of

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residual heat removal (RHR), core spray, residual heat removal service water (RHRSW), and standby gas treatment systems. No discrepancies were identified.

Operator Tralning and Qualification 05.1 Missed Notification of Chanae in Medical Status for Ooerator On October 29,1996, a licensed operator notified the shift manager of a medical condition. The shift manager contacted operations management and monitored the licensed operator's performance in accordance with the licensee's fitness-for-duty manual. On February 14,1997, the licensed operator was removed from duty due to a different medical condition. During follow-up from this event, the superintendent of operations-training identified that the first change in medical status required notification of the NRC and review of licensed duties. On March 12,1997, the licensee informed the inspectors of this missed notification.

Corrective actions included revising the fitness-for-duty manual to include the requirements of 10 CFR 55.25, training, and documenting the event in CR 97000781. This is considered an Unresolved item (50-263/97003-02) pending receipt of formal notification and review by regional inspectors.

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Quality Assurance in Operations

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l 07.1 Concern with Freauency of Shiftly Surveillances a.

Insoection Scone (71707)

Operations personnel working hours changed from 8 to 12-hour shifts sometime in 1990. During this period, Generation Quality Services (GOS) auditors identified that the frequency of some Technical Specification (TS) surveillances were affected when the operators changed to 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shifts..The inspectors evaluated the licensee's response to the GOS audit.

l The following documents were reviewed:

TS Interpretation 4.0.B-1, "Use of 25 Percent Tolerance for Periodic Actions

in Section 3.0" TS 6.1.F.1

CR 97000874, " Extended Shift Surveillance Intervals Due to Changed

Operations Shift Lengths" GOS Observation Report 1997100, " Evaluation of TS Interpretations to the

Licensing Basis" b.

Observations and Findinas in Inspection Report 50 263/96003, the inspectors identified a discrepancy concerning operators' normal working hours. TS 6.1.F.1 stated that operating personnel work normal 8-hour day,40-hour week while the plant was operating.

This definition of a " normal" shift has existed since original TS issuance. However, since sometime in 1990, the operations staff has worked 12-hour shifts. The licensee did not change the TS when the crew changed from 8-hour to-12-hour shifts. The inspectors concluded no violation existed since the specification concerned the use of overtime and no problems were noted in this area. On August 15,1996, the licensee submitted a license amendment request to change the phrase "8-hour day,40-hour week" to "8 or 12-hour day, nominal 40-hour week."

During this inspection period, GOS auditors identified that the frequency of some TS "shiftly" surveillances were affected by the change in operators' base hours.

Some of these surveillances included performing sensor checks for radiation monitors and reactor levelinstruments. Operations personnel performed these surveillances once a shift or about twice a day. However, these same surveillances were performed 3 times a day, about 7 years ago, when operations personnel were working 8-hour shifts.

The licensee evaluated this finding and determined that the present surveillance t

l frequencies were acceptable since "shiftly" was not defined in TS and the l

frequencies were consistent with Standard TS.

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The inspectors had the following concerns:

Changing operations working hours from 8 to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months affected TS

surveillance frequencies. A definition of "shiftly" was implied in TS 6.1.F.1.

10 CFR 50.59 stated that changes to the facility were allowed without NRC approvalif such changes did not change TS. Modifying surveillance frequencies when the operators' base hours changed may have required prior NRC approval. This is considered an Unresolved item (50-263/97003-03)

pending review by NRR.

In response to inspection Report 50-263/96005, the licensee submitted a TS

amendment request on August 15,1996, to change the operator working hours to allow a 12-hour work day. This amendment request did not address changes in TS surveillance frequencies. The licensee planned to submit a supplement to this amendment request.

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Conclusions GOS personnel demonstrated a questioning attitude by identifying this issue. The j

appropriateness of modifying TS surveillance frequencies without NRC approval will be reviewed.

07.2 Inaoorooriate Technical Soecification Interoretation a.

Insnection Scone (71707)

During a GOS audit, the auditors identified that a TS interpretation was not supported by, and was contrary to, TS. The inspectors reviewed the licensee's response to this finding.

The following documents were reviewed:

TS Interpretation 4.0.B-1, "Use of 25 Percent Tolerance Band for Periodic

Actions in Section 3.0" Standard TS SR 3.0

GOS Observation Report 1997100, " Evaluation of TS Interpretations to the

Licensing Basis" CR 97000875, " Inappropriate TS Interpretation on Limiting Condition for

Operations (LCO) Required Actions" b.

Observations and Findinas As discussed in Section M7.1, the licensee performed TS Section 4 surveillances using a fixed schedule with a i 25 percent interval band. In April 1994, the

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operations committee approved a TS interpretation which allowed the same

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l percent tolerance band to be applied to TS Section 3 surveillances. The conclusion l

was based on the impracticality of strict TS interpretation and the acceptance of

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this band in TS Section 4 testing. The auditors identified that this TS interpretation

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changed the license and was inappropriate. The inspectors agreed.

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i The operations committee met on April 3,1997, and canceled the TS interpretation. A letter stating that TS Section 3 surveillances must be completed within the specified period, without extensions, was issued to operations personnel.

The licensee determined this issue was reportable.

The inspectors reviewed TS and several completed surveillances to identify when this interpretation was previously used. TS 3.13.G.2 required either a continuous fire watch or an hourly fire watch (with operable fire detectors) be established if a fire barrier became inoperable. Procedure 2406, " Fire Watch High Energy Line Break Patrol," contained notes which allowed a 25 percent deviation from the specified 1-hour requirement. The inspectors reviewed some completed Form 2046A, "Fi.

Watch Patrol Log Sheets," and identified several examples where hourly fire watch patrols were not performed within 60 minutes. For example, on January 14 and 15,1997, fire door #41 was inoperable due to a broken latch mechanism. Several fire watch patrols were performed about 70 minutes apart.

j One patrol was performed 81 minutes after the previous patrol.

l Failure to perform fire watch patrols in accordance with TS is considered a violation (50-263/97003-04). Although the inspectors identified the specific TS violation, the auditors identified the inappropriate use of the 25 percent tolerance band on TS Section 3 surveillances. Accordingly, this issue is considered licensee identified.

Corrective actions were promptly implemented. Therefore, this issue is being treated as a non-cited violation consistent with Section Vll.B.1 of the NRC Enforcement Policy.

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Conclusion The GOS auditors demonstrated a good questioning attitude during their review of TS interpretations. The licensee responded appropriately to the finding.

07.3 Underfundina of Decommissionina Fundina On December 20,1996, the licensee issued a letter to the NRC stating that a GOC audit had determined that the decommission funding calculations starting in 1993 had been non-conservative, resulting in under funding below the NRC minimum required levels specified in 10 CFR 50.75, " Reporting and Recordkeeping for Decommissioning Planning," Section (b). The letter also described the licensee's intended corrective actions. The inspectors referred the issue to the NRC Office of Nuclear Reactor Regulation staff for a determination of enforcement aspects of the finding.

The NRC staff determined that the finding constituted a violation of 10 CFR 50.75(b) but that the violation was licensee identified, adequate corrective actions were initiated, and the issue was not safety significant. Thus this licensee-

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sA identified and corrected violation is being treated as a non-cited violation (50-

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263/97003-05), consistent with Section Vll.B.1 of the NRC Enforcement Policv.

11. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.

Insoection Scone (62703)

The inspectors observed several maintenance and surveillence activities. This review included evaluating procedure adherence, confirming that acceptance criteria as specified was met, verifying that activities were conducted as described in the appropriate USAR section, and determining the appropriateness of post-maintenance testing. The work orders (WO) and tests included:

WO 9602998

12 Reactor Water Clean-up (RWCU) Pump (P-2048) Preoperational Test WO 9603133 Replace Ammeter Switch for #11 RHRSW

WO 9703361 Realign Strut SR-625

WO 9703532 Preoperational Testing of Modification 960150

WO 9703548 Replacement of the Channel "A" Spent Fuel Pool Radiation Monitor Fuses

WO 9703577 Routine Maintenance of PCV 3004

WO 9703699 Perform 4850-505PM on #11 Core Spray Pump 4KV Supply

WO 9703807 Repair Flange Leak Between AV-3147 and RHRSW-52-1

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WO 9703832

12 EDG Lube Oil Circulation Pump Motor Repair / Replacement

Test 0012 APRM/ Rod Block / SCRAM Surveillance Test

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Test 0068

"A" Channel Spent Fuel Pool (SFP) and Reactor Building (RB) Exhaust Plenum Radiation Monitor Functional Test

Test 0255-03-IA-1 Core Spray Quarterly Surveillance Test Test 0255-04-IA-1

"B" RHR Ouarterly Surveillance Test

Test 0255-0MA-1

"A" RHRSW Ouarterly Surveillance Test

Test 0255-17-IA-5 Alternate Nitrogen System Train "A" Valve Test, Revision 8

MP0960130-05 Design Procedure Change for #12 RWCU Pump (P-048) and SV-2403, RWCU Excess Flow Control Valve

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Observations and Findinas l

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The inspectors found the work performed under these activities to be generally professional and thorough. Supervisors and system engineers monitored job progress, and quality control personnel were present whenever required by procedure. All work observed was performed with the work package present and in active use.

Technicians were experienced and knowledgeable of their assigned tasks.

However, the following concerns were noted:

WO 9602998 #12 RWCU Pumo (P-20418) Preooerational Test: During the prebrief for the RWCU modification test, the operators expressed concern about aligning RWCU to the main condenser while at power. This alignment was not specified in an existing procedure. Furthermore, operators were concerned about the potential to inadvertently drain the reactor if the discharge valve (s) to the main condenser hotwell failed open. As a result, an Operations Committee meeting was held prior to the preoperational test to address their concerns. The inspectors noted that these concerns were not raised by the operations crew which performed a similar test during the previous week. No problems occurred during either test; however, the inspectors were concerned that the licensee heavily relied on the operators as the last barrier to identify potential problems.

Reolacement of SFP and RB Exhaust Plenum Radiation Monitor Trio Unit

Power Suoolv Fuses: The inspectors witnessed an instrument and control fl&C) technician replace the "A" 24 VDC power supply fuses and calibrate the SFP and RB exhaust plenum radiation monitor trip units for channel "A."

The WO did not provide specific direction on where to take the power supply vo;tage readings. Task completion was delayed until the system engineer identified the proper measuring points. After replacing fuses and obtaining power supply voltage readings, the l&C technician found that trip settings on the SFP trip unit were out of tolerance. The trip setpoints were consequently adjusted. The I&C supervisor identified that the technician did not obtain as-found readings prior to and after replacing the fuses. This action should have been performed although steps were not specified in the WO.

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Conclusions Maintenance activities were generally performed in a thorough and professional manner. However, some problems encountered during these activities indicated a weakness in the technical adequacy of work instructions.

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M1.2 Personnel Errors Durina Undervoltaae Relav Testina

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Insoection Scone (61726)

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The inspectors reviewed the performance of a surveillance test associated with the safeguard bus undervoltage relays. This event is also discussed in Section 01.2.

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This discussion focuses on surveillance aspects of the event. The following documents were reviewed:

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Drawings NE-36399-9 and NF-36397

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i Test procedure 0301, " Safeguard Bus Voltage Protection Relay Unit

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Functional Test," Revision 21 b.

Observations and Findinas

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.1 As discussed in Section 01.2, on April 8, licensee personnel began to perform surveillance test 0301, " Safeguard Bus Voltage Protection Relay Unit Functional Test," Revision 21. This test was performed pursuant to TS Requirement 3.2. and involved testing individual undervoltage relays and verifying that appropriate relay contacts closed when the tested relays dropped out. During the performance of this test, the loss of voltage protection logic was satisfied resulting in the trip of the normal power source to 4160 V bus 15. This resulted in the automatic start of the

11 and 12 EDGs. The undervoltage logic was satisfied due to personnel error

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during the performance of the surveillanco test.

Procedure steps 5 and 6 required that the continuity across undervoltage relay contacts be verified upon testing the corresponding UV relays. To accomplish this task, electricians connected a multi-meter in the resistance mode across relay contacts 127 5Y and 127-5Z in cubicle 152-510. Upon completion of Step 6, the electricians proceeded to step 7 which required opening a switch in a different switchgear cubicle (152 505). However, the multi-meter was not removed from cubicle 152-510. Since the meter was still connected in the resistance mode, continuity across the contacts was maintained through the meter.

Upon opening the switch required by procedure Step 7 in cubicle 152-505, relay contacts associated with relays 127-5 and 127-5X closed and the UV relay protection logic was satisfied. This resulted in the tripping of the normal power source to bus 15, automatic starting of the #11 and #12 EDGs, and initiation of two timers (5 and 10 seconds). After the 5-second timer timed-out, a transfer to the bus 15 alternate source (transformer 1 AR) was initiated. Since the meter leads were still connected across the UV relay contacts, the 10-second timer continued to time-out even though bus 15 was now powered from the 1 AR transformer.

When it timed out, the source circuit breaker to bus 15 from transformer 1 AR was tripped open and a transfer to the diesel generator was initiated. A simplified elementary diagram of the undervoltage relay protection is provided below.

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The procedure instructions for verifying continuity did not require that the multi-meter be connected via leads to the relay contacts. The method to verify

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continuity (momentary contact or landing of meter leads) was left up to skill-of the-l craft. Therefore, there was no explicit procedural requirement to remove any installed instruments upon completion of tasks in cubicle 152-510. This issue is j

identified as an Unresolved item (50-263/97003-06) pending further NRC review of l

the adequacy of the surveillance procedure and personnel errors during the test.

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Conclusions l

Personnel errors during the performance of the undervoltage relay surveillance test caused a loss of voltage to bus 15.

M2 Maintenance and Material Condition of Facilities and Equipment i

M2.1 Current Material Conditions and lmoact on Ooerations Personnel The inspectors conducted control room and plant inspections and interviewed i

operations personnel to assess the material condition of plant equipment. During

this period, the following conditions were found:

i Freauent inventorv makeuo to soent fuel cool. Leaks past some spent fuel

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pool system valves resulted in manual operator actions to maintain pool l

level. Troubleshooting indicated that the diverted water was contained in l

the radioactive waste collector tanks. This condition resulted in additional operator actions and potential for increased radiation dose.

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Inocerable reactor buildina ventilation wide ranae oas monitor. On April 1,

chemistry personnel noted that the filter paper from channel "B" was significantly darker than that of channel "A." Further investigation by the system engineer indicated that air in-leakage at the high pressure pump caused bypass flow around the filter. The channel was declared inoperable

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and a WO was initiated. The licensee found a small tear in the pump j

diaphragm. Review of previous samples indicated that the pump had been inoperable since early February. TS Table 3.8.2 required at least one channel operable; channel "B" had remained operable during this period. TS Table 3.14.1 required the licensee to repair an inoperative channel within 7 days or write a specialletter describing actions to repair the inoperable

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channel. Channel "A" was inoperable for about 2 months prior to the identification of the discrepancy. The licensee planned to submit a letter pursuant to TS Table 3.14.1.

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Conclusions The material condition of plant equipment was acceptable. The operators j

interviewed were knowledgeable of the discrepant conditions.

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M2.2 Uninterruotible Power Suoolv (UPS) Inverter Power Source Transfer From Normal to Alternate Poggi a.

Insoection Scone (62707)

The inspectors reviewed the licensee's actions taken in response to an unexpected transfer of the power source to UPS inverter Y-71.

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Observations and Findinas

During reactor core isolation cooling (RCIC) system testing performed on March 26, an automatic transfer of the power supply to Division i 120 Vac UPS Y-71 inverter occurred. The normal power source to the UPS inverter was the Division i 250 DC i

battery with the alternate power source being the onsite AC system.

Troubleshooting did not positively identify the cause of the power source transfer.

However, the licensee suspected that degradation of a varistor in the trip coil logic circuit of RCIC valve MO-2080 allowed a voltage spike to be sensed at the UPS

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inverter. This condition resulted in an automatic transfer of the power supply to the alternate source. An operability evaluation was performed and it was determined that the RCIC system and inverter were operable.

l During troubleshooting activities, the licensee entered an administrative 14-day LCO i

due to UPS train Y-71 being supplied from its alternate power source. The administrative LCO was being implemented in accordance with the guidance provided in Generic Letter (GL) 91-11, " Resolution of Generic issues 48, LCOs for Class 1E Vital Instrument Buses, and 49, Interlocks and LCOs for Class 1E Tie Breakers pursuant to 10 CFR 50.54(f)," pertaining to LCOs for Class 1E vital

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i instrument. sa. ' The inspectoro verified that the administrative limit was in l

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accordance we N commitments made in the licensee's GL response.

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Ccoclusions

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Although the cause of the Un ? Y-71 power source transfer could not be positively

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identified, troubleshooting a:ctiv?ies were well performed. An administrative LCO i

j was properly implemented to lhnl. the time that the inverter was on the alternate

_power source.

M2,3 1Jnexoected Main Generator Gross Load Alarm l

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Insoection Scone (62707)

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The inspectors reviewed the licensee's evaluation of a main generator computer

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point alarm.

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Observations and Findinas On March 29, control room operators received the " Generator Gross Load Rate of Chraa" computer point alarm. The operators reviewed the plant parameters

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including the reactor and electrical system indications and questioned the system

dispatcher regarding the alarm. Plant parameters were observed to be normal and

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no electrical disturbances were identified on the utility's electrical distribution i

l system. No additional alarms were received at the time of the gross load alarm.

J Computer system engineers performed a review of data recorders and plotted the

data to ovaluate the computer alarm. The re; corded data indicated an approximate

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150 Mwe load drop and recovery over a 2 second interval, with voltage and current

fluctuations as well. At the end of this inspection period, electrical and computer i

syttem engineers were continuing the review of this unexplained alarm.

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Conclusions

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The licensee had not determined the cause of the computer point alarm at the end of this inspection period. Engineering efforts continued to attempt to identify the

cause of the alarm.

l M7 Quality Assurance in Maintenance l

l M7.1 Inconsistency Between TS and TS Bases for Surveillance Freauencv a.

Insoection Scope (40500,61726 and 71707)

During a GOS audit of TS interpretations, the licensee identified a discrepancy between the TS and its associated bases. The inspectors reviewed the GOS

[

finding, licensee's response, and the following documents:

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O TS 4.0.B concerning surveillance intervals and its associated bases

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SER for TS Amendment 32 issued on May 28,1985

SER for TS Amendment 63 issued on April 18,1989

NRC Inspection Report (50-263/85012)

b.

Observations and Findinas TS 4.0.B stated, " Specific time intervals between tests may be extended up to 25 percent of the surveillance interval to accommodate normal test schedules..." This TS implied that the surveillance clock was reset each time a surveillance was

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performed and was consistent with NRC Standard TS. The intent appeared to be to limit the maximum period of time a safety system or parameter may go untested or i

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unchecked.

The Bases section for TS 4.0 desciibed a fixed surveillance schedule in which

'

surveillances could be performed up to 25 percent earlier or later than a fixed date.

Subsequent tests were based on fixed dates, independent of when the surveillance was last performed. This fixed scheduling could allow a 50 oercent extension of a surveillance interval. The Bases appears to contradict with the associated TS.

j The licensee's current practice for scheduling surveillances most resembles the TS bases and may not be in verbatim compliance with TS 4.0.B. It appears that an l

l unofficial interpretation approving this practice was presented to the licensee in

'

1985 and 1989. A brief history is as follows:

l IV.ay 28,1985:

An SER was issued to amend TS 4.0.B. The licensee originally requested a plus or minus 25 percent interval to accommodate normal test schedules; however, as documented in the SER, i

l the reference to minus 25 percent was deleted. The SER also documented the licensee's use of a fixed schedule.

June 20,1985:

Licensee personnel met with the NRC resident inspectors and requested an interpretation of the TS wording. The resident inspectors consulted with the NRR license project manager and the Region 111 Section Chief (consultation with the SER l

preparer was not documented). An interpretation documented j

in Inspection Report 50-263/85012 dated July 17,1985, stated that the 25 percent allowance meant that each t

l surveillance must be completed within +/ 25 percent of each scheduled fixed date and "if test number one is performed 25 percent early, test number two could be performed 25 percent late with no violation."

May 5,1986:

The licensee submitted a license amendment request for the TS 4.0 Bases.

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o April 18,1989:

An SER for Amendment 63 was issued. This SER stated that

the Bases for TS 4.0 was revised to explain the surveillance l

testing and to assist in understanding and applying this section. It further stated that the Bases word:ng was derived from the NRC standard TS and contained additional clarifying information contained in NRC Inspection Report 50-263/85012.

l The significance of these inconsistencies between the TS and Bases has not been determined. The fixed schedule could result in a 50 percent extension of the surveillance interval and may not be conservative for some instruments. This issue is considered an Unresolved item (50 263/97003-07) pending review by NRR.

i c.

Conclusions

!

The GOS auditors demonstrated a good questioning attitude Osring their review this TS interpretation. The significance of these inconsistencies between the TS and Bases has not been determined.

Ill. Enainegring j

E2 Engineering Support of Facill' ties and Equipment E2.1 Residual Heat Removal Service Water #11 Pumo Air Vent Valve a.

Insoection Scoce (37551 and 62707)

During this inspection period, the inspectors continued to review the licensee's troubleshooting, maintenance, and engineering activities pertaining to the #11 RHRSW pump air veqt valve failure to seat. On March 19 and 20,1997, the

inspectors witnessed portions of the installation and post-modification testing for

,

modification 960150-04. The following documents were reviewed:

CR 97000890, "152 507 RHR-SW Auxiliary Switch Failed to Actuate"

WO 9703137, "#11 Surge Check Valve Replacement"

b.

Observations and Findinas As discussed in NRC Inspection Reports 50-263/96006, 50-263/96008, and 50-263/96011, the licensee experienced repetitive failures of air vent valve AV-3147 to close, necessitating declaring the #11 RHRSW pump inoperable on several occasions. The air vent valve was designed to close after air was ejected from the pump column and system piping. On November 8,1996, the licensee temporarily installed a cast iron surge check valve between the pump and the air vent valve.

Since the surge check valve was installed, the licensee has not experienced any

)

further failures of the air vent valve: therefore, a permanent modification was undertaken.

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The modification replaced the cast iron surge check valve on the #11 pump with a a

cast steel valve and instelled surge check valves on the other three air vent lines.

During the post-modification testing, water sprayed from the air vent line. The water stopped within a few seconds; however, a smallleak (on the order of a few drops a second) occurred around the flange of the newly installed surge check valve. The maintenance workers re-torqued the flange, but were unable to stop the leak. The test was terminated, and the maintenance workers disassembled the surge check valve. The inspectors noted that the removed gasket was uniformly compressed, indicating it had been properly installed. In trying to determine the cause of the leakage, the licensee noted two screws set into the flange face and determined that the gasket surface was not wide enough to cover the screws. The

)

licensee decided to replace the #11 surge check valve with the one previously

)

installed and to remove the newly installed surge check valve from the #13 RHRSW line.

During post-maintenance testing, water gushed from the #11 air vent line, and then stopped. The licensee again terminated the test. The licensee revised the test instruction to allow for testing of just the #13 pump. This enabled the operators to replace the 7-day LCO with a 30-day clock. The inspectors reviewed the modified procedure and ensured that it adequately tested the pressure regulating valve as well as operation of the #13 pump. During this test, operators immediately shut down the pump when control valve 1728 failed to open. The licensee later determined that the breaker for the valve motor malfunctioned due to a slight j

difference in size between the originally installed breaker and a recently replaced one. The original breaker was reinstalled and successfully tested.

The licensee engineers contacted the surge valve vendor representative. The vendor explained the flange leakage problem as being due to the air vent line having a raised face. The vendor stated that the flange mating surface should be flat, and a Garlock" brand gasket should be used. This difference in flange surfaces had not been identified during either the temporary or permanent modification procus. The licenseo prepared a third temporary procedure change to grind down the surface of the air vent line flange to obtain a better fit between the air line and check valve flange surfaces. The modification was put on hold and, as of the end of the inspection period, the licensee had not decided what to do with surge check valves for the remaining pumps.

The licensee satisfactorily tested both the RHRSW pumps and exited the LCO.

c.

Conclusions The actions to resolve the RHRSW air vent valve failure problem were mixed.

Installation of a permanent cast steel surge check valve was not successful, apparently due to a difference in flange design between the air vent valve and the surge check valve which was not identified during the modification process.

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E8 Miscellaneous Engineering issues

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E8.1 (Ocen) Licensee Event Reoort (LER) (50-263/97004). Revision 0: Failure to Submit

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Relief Requests for limited Inservice inspection Examinations. During an inspection at the Prairie Island facility, regional inspectors identified that the licensee failed to request inspection relief for limited examinations on some welds. A violation was cited in inspection Report 50-282/306-97003. Further review indicated that a

similar problem existed at the Monticello facility. The issue will be evaluated during l

the review of this LER.

E8.2 (Closed) Unresolved item (50-263/95010-01): Valve Degradation Not Considered During Stroke Limit Change. Stroke time data obtained during the past 18 months did not indicate valve degradation. Therefore, no violation occurred.

IV. Plant Support l

R1 Conduct of 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.

P1 Conduct of Emergency Preparedness Activities (71750)

During normal resident inspection activities, icutirm observations were conducted in the area of emergency preparedness using Inspection Procedure 71750. No discrepanciet were noted.

S1 Conduct of Security and Safeguards Activities (71750)

During normal resident inspection activities, routine observations were conducted in the areas of security and safeguards activities using Inspection Procedure 71750. No discrepancies were noted. On March 10, the inspectors met with the security supervisor l'

to discuss current security issues. Topics included personnel performance trending, training, status of corrective actions to previously identified concerns, and material condition of security-related equipment. The inspectors noted that the licensee responded promptly to an egress concern identified at another nuclear facility. The inspectors also attended a firearms training course which included realistic simulated scenarios.

!

V. Manaaement Meetinas

!

X1 Exit Meeting Summary

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i On April 10,1997, the inspectors discussed the inspection results with the plant manager.

,

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

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X2 Pre-decisional Enforcement Conference Summary s

On March 5,1997, a pre-decisional enforcement conference was held in the Rill office to discuss the apparent violation identified in inspection Report 50 263/96009. The licensee

discussed the events leading to the apparent violation and their proposed corrective i

actions. The regional administrator commended the licensee for taking a " bottom line" l

_ approach and for the comprehensiveness of the corrective actions. The slides used by the licensee during the pre decisional conference are attached. The results of NRC's deliberations into the matters discussed at the pre-decisional conference will be forwarded

,

under a separate correspondence.

J l

Attachment: Conference Slides l

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k PARTIAL LIST OF PERSONS CONTACTED Licensee

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E. Watzl, President, Nuclear Generation

M. Wadley, Vice President, Nuclear Generation

W. Hill, Plant Manager B. Day, Training Manager M. Hammer, General Superintendent Maintenance K. Jepson, Superintendent, Chemistry & Environmental Protection L. Nolan, General Superintendent Safety Assessment M. Onnen, General Superintendent Operations E. Reilly, Superintendent Plant Scheduling

C.- Schibonski, General Superintendent Engineering W. Shamla, Manager Quality Services J. Windschill, General Superintendent, Radiation Protection

,

L. Wilkerson, Superintendent Security NRQ

A. B. Beach, Regional Administrator

B. Berson, Regional Counsel

J. Caldwell, Director, Division of Reactor Projects

H. B. Clayton, Enforcement Officer

J. Hannon, Director, Project Directorate ill 1, NRR

,

' J. Heller, Enforcement Coordinator

J. Jacobson, Chief, Division of Reactor Projects Branch 4

T. J. Kim, Project Manager, NRR

M. Leach, Acting Deputy Division Director, Division of Reactor Safety

V. P. Lougheed, Reactor inspector

R. Pedersen, Office of Enforcement, NRR

M. Ring, Chief, Lead Engineering Branch, Division of Reactor Safety

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A. M. Stone, Senior Resident inspector, Montice!Io

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Indicates those participating in the March 5,1997, pre-decisional enforcement conference.

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INSPECTION PROCEDURES USED

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IP 37551:

Onsite Engineering IP 40500:

Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems I? 01726:

Surveillance Observations

'P 02703:

Maintenance Observations IP 71707:

Plant Operations IP 71750:

Plant Support

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'IP 92700:

Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

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Facilities IP. 93702:

Prompt Onsite Response to Events at Operating Power Reactors

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ITEMS OPENED, CLOSED, AND DISCUSSED

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Opened i

50-263/97003-01 URI Operator unawareness of operating ESW pump

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50-263/97003-02 URI Change in operator medical status

50-263/97003-03 URI Modified surveillance frequency with change in shift hours

l 50-263/97003-04 NCV Failure to perform fire watch patrols

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50-263/97003-05 NCV Underfunding of decommissioning funding j

50-263/97003-06 URI Personnel errors during undervoltage relay testing

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50-263/97003-07 URl'

Discrepancy between TS and bases on surveillance

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i frequencies 50-263/97004-00 LER Failure to Submit Relief Requests for Inservice Inspection Examinations Closed 50-263/97003-04 NCV Failure to porform fire watch patrols 50-263/97003-05 NCV Underfunding of decommissioning funding

50-263/95010-01 URI Valve Degradation Not Considered During Stroke Limit Change

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LIST OF ACRONYMS USED

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CR Condition Report EDG Emergency Diesel Generator

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i ESW Emergency Service Water

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GL Generic Letter l

GOS Generation Quality Services j

l&C '

Instrument and Controls LCO Limiting Condition for Operation j

LER Licensee Event Report j

NCV Non-cited Violation j

NRR NRC Office of Nuclear Reactor Regulation RB Reactor Building

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RCIC Reactor Core Isolation Cooling l

RHil Residual Heat Removal

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RHRSW Residual Heat Removal Service Water I

RWCU Reactor Water Clean-Up SER Safety Evaluation Report SFP Spent Fuel Pool TS Technical Specification UPS Uninterruptible Power Supply

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URI Unresolved item USAR Updated Safety Analysis Report

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UV Undervoltage j

WO Work Order l

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c AGENDA MARCH 5,1997 NRC-NSP PRE-DECISIONAL ENFORCEMENT CONFERENCE Theissue

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Configuration Management Program

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Review of FSAR

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RHR Intertie Line

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Design Basbs Reconciliation

Overall Safety Perspsciive

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Root Causes

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Corrective Actions

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Other Actions Completed to Date

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NSP's Safety Philosophy

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Conclusion

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THE ISSUE

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NSP Safety Review Item 92-030, DBD-LOCA

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Containment Resaonse/USAR Diesel Generator Loading Table Addressed analysis and USAR changes to support DBD-LOCA containment cooling with one LPCI Pump, one RHR Service Water Pump, one RHR Heat Exchanger, and one Emergency Diesel Generator

Incorrectly concluded that these changes did not

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involve an unreviewed safety question.

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C CONFIGURATION MANAGEMENT PROGRAM

NSP committec to a Configuration Management Program in a letter from C E Larson to A Bert Davis, November 13,1989.

Major part of this program was to identify and maintain the design basis of the olant. Issues identified by t1is arogram were to be tracked and disaositioned under a

"ollow-on item (FOI) arocess.

Containment Analysis Error Discovery August 3,1992 (FOl-92-0032)

Personnel working on the Configuration Management Program identified that assumptions of pump availability used in USAR post-LOCA containment

,

analysis could not be supported if a failure of one emergency diesei generator was assumed.

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G REVIEW OF FSAR.

Chapter 5, Plant Containment Systems, Section 2.3.3, Containment Characteristics After Reactor Blowndown, Pages 5-2.18 thru 21 and Figure 5-2-14 thru 16.

'

Five cases are presented with the most limiting one being one LPCI pump and one RHRSW pump producing a maximum suppression pool temperature of 190 F.

Chapter 6, Engineering Sa eguarc s Table 6-2-2 Residual Heat Removal System (RHRS)

Equipment Design Parameters, Page 6-2.11 '

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identified the RHRSW pumps as "4 - 50% (2 required to provide required cooling capacity)"

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REVIEW OF FSAR (CONT'D)

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Section 2.3.2.2 Low Pressure Coolant iniection i

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Subsystem (LPCIS) Page 6-2.13A

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Discusses the diesel loading concerns following 600

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seconds: "One of the RHRS circulating pumas :LPCI

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aumas' can be shutdown and two RHRS service water i

pumps' started manually to provide cooling water to the RHRS heat exchangers."

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i Chapter 8 Plant Electrical Systems, Table 8.4.2 Standby Diesel-Generator System Emergency Loads (per D/G Set)

After 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , the major aump loads on orie Emergency Diesel Generator are 1 Core Spray pump,1 LPCI aump, j

and 2 RHRSW Pumps.

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REVIEW OF FSAR (CONT'D)

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-Conclusion It appears that 1 LPCl/2 RHRSW aumps was the assumed post-LOCA containment cooling mode even though the 1 LPCl/1 RHRSW pump case was analyzed

.

and found acceptable. Loading for the 1 LPCl/2 RHRSW

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pump case exceeds the continuous KW rating of t7e diesel gerierator.

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RHR Intertie Line-

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RHR to RECIRC Intertie Line installed in 1984 to eliminate

water hammer events (NSP Modification 83ZO49).

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Potential break area increase of 0.08 ft

GE Safety Analysis (NEDO 3047712/27/83) prepared to

,

assure ECCS performance and containment response acceptaale.

'

. NRC prior approval and LAR obtained

.

GE Analysis, DBA Containment Pressure and Temperature Response (NEDO 3048512/27/83)

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. An ys s o

a of Modi ica ion 83ZO49

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RHR Intertie Line (Cont'd)

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Lack of detailed NSP review

Used in USAR, Revision 2 to establish single containment response curve, maximum long term torus

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water temperature is 182 F.

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NEDO 30485 used to support LAR on May 1,1986 to

increase Appendix J test pressure.

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MONTICELLO UPDATED SAFETY ANALYSIS REPORT USAR 5. FIGURES

Revision 14 Page 15 of 29

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Figure 5.2-1/ Suppression Pool Temperature Response OO O

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c Design Bases Reconciliation

Objective of the Configuration Management Program was to identify the plant design bases.

Performance capability of the ECCS system, the Containment Cooling systems, or the Emergency Diesel Generators has not changed.

FSAR not. clear on what cesign bases rea ly was.

New analysis requestec from GE for containment response for DBD-LOCA with 1 LPCl/1 RHRSW puma

!

(NEDO 32417 December 1994) shows maximum long term torus water temperature is 184 F.

SRI 92-030 prepared to document reconciled design bases DBD-LOCA containment response and diesel loading tables.

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More accurate decay heat code used in dontainment response analysis, conservative input assumptions maintained.

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RHRSW p. umps become 4 - 100% capacity pumps.

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Emergency Diesel Generator loading decreased i

providing flexibility for operation following LOCA.

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CONTAINMENT ANALYSIS I Suppression Pool Temperature 200 190 F

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FSAR-1 P/1 P

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100 -------------------r' ---------------------------l-----------------------------------------

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to 100 1000 10000 100000 1000000 Time (seconds)

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Emergency Diesel Generator. Loading

.

Emergency Diesel Generator Capability 2,500 KW i

continuous

2,750 KW for 2,000 hours0 days 0 hours 0 weeks 0 months FSAR 1 Core Spray Pump Table 8.4.2 1 LGPl Pump 2 RHRSW Pumps Pumps Operating at 2,745 KW Maximum conditions:

USAR 1 Core Spray Pump EDG #11 2,114 KW Table 8.4.2 1 LCPI Pump 1 RHRSW Pumps EDG #12 2,226 KW l

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C Root Causes

Poor Understanding of 50:59 Focus has been on safety analysis more so than ac'cressing tle 50:59 questions

Lack of aapreciation for the USAR and Technical S3ecification bases from a regulatory aerspective.

Incomplete knowledge of total integrated safety analysis.

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l Corrective Actions Cause:

Poor Understanding of 50:59 Ac: ions:

50.59 Screening Process Being Develo3ed

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50.59 Process Being Enlanced Training will be Provided to the Engineering Staff on the above clanges

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Corrective Actions (Cont'd)

Cause:

Lack of Appreciation for the USAR and Technical Saecification bases from a regulatory persoective.

Actions:

Training.wi I be provided on the importance o USAR and Technical Specification Bases A USAR review program wi l be initiated.

Enlance Operabii:y Determination Process

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Corrective Actions (Cont'd)

Cause:

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Incomalete knowledge of Total Integrated Safety

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Analysis.

Actions:

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t Power Rerate i

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Through the Power Rerate Process, we have improved our know edge of :le Tota Integrated Safety Ana ysis i

Develop a Safety Ana ysis input Data 3ase.

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Other Actions Completed to Date

Oaerability Assessment completed and documented in a Condition Report.

Identified this issue as LER 97001.

License Amendment Request Submitted.

Power Rerate schedule extended.

General Superintendent Engineering has discussed the SSOPI Findings with the engineering staff.

Engineering Technical Staff Training was conducted on the SSOPI Findings.

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Permission has been requested and approved to hire ten (10) additional engineering personnel.

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NSP's Safety Philosophy

Maintain the P ant

Conservative 03erating Phi osophy

Invest in Safety, e.g.:

Mark 1 Containment Modifications and Recirculation Piping

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Replacement

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Addition of the' 2R Transformer and Auto Load Tap Changer

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Addition of 2 - 250 VDC Batteries (one of which is safety related)

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Addition of the Non IE Diesel Generator 560

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Diesel Fire Pump to RHR Crosstie

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Safety Grade Instrument Air Supply to SRVs and Inboard MSIVs i

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Two (2) Divisions of IE Uninterruptible instrument AC

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Conclusions

An Unreviewed Safety Question was not oroperly identified.

The plant has been safely operated.

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We believe the proposed corrective actions will be

effective.

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v t e Inspection Report - Monticello - 1997003
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \|
1997 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 17(0) 18(0) Security 201(0) Operator Exams Emergency Planning Other

IR 05000263/1997003

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