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Insp Repts 50-282/92-29 & 50-306/92-29 on 921109-930104. Violations Noted.Major Areas Inspected:Plant Operational Safety,Maint,Surveillance,Engineering & Technical Support, Radiological Protection & Refueling
	ML20128A965
Person / Time
Site:	Prairie Island
Issue date:	01/25/1993
From:	Jorgensen B; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20128A893	List: IR 05000282/1992029; ML20128A889; ML20128A937;
References
	50-282-92-29, 50-306-92-29, NUDOCS 9302020358
	Download: ML20128A965 (67)
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U. S. NUCLEAR REGULATOP.Y COMMISSION REGION 111 Reports No. 50-282/92029(DRP); 50-306/92029(DRP)

Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60 Licensee: Northern States Power Company 414 Nicollet Mall

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Minneapolis, MN 55401 facility Name:

Prairie Island Nuclear Generating Plant

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Inspection At:

Prairie Island Site, Red Wing, MN Inspection Conducted: November 9,1992, through January 4,1993 Inspectors:

M L. Dapas D. C. Koslof f R. L. Bywater T. J. Kobetz

{kw-ed. >hks: $7

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Approved By:/g~B. L. Jorgensen, Chief Reactor Projects Section 2A Date l!Lsnection Summarv Inspection on November 9,1992, through January 4,1993, (Reports No. 50-282/92029(DRP); 50-306/92029(DRP))

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Areas Insnected:

Routine unannounced inspection by resident and regional inspectors of plant operational safety including onsite followup of events and cutage activities, maintenance, surveillance, engineering and technical support, radiological protection, refueling, licensee followup on previously identified items, licensee event report followup, regional initiatives, cold weather preparations, and information meetings with local officials.

A routine management meeting was conducted at-the NRC Region III office on December 18, 1992.

A copy of the licensee's handouts for this meeting is attached.

9302020358 930126 PDR ADOCK 05000202 G

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LXJCUTLVE SUMMARY Enforcement Two cited violations and three non-cited violations of NRC requirements were identified in the areas inspected.

Operations No new strengths cr weaknesses were identified. Two cited violations were identified involving control of fire doors and related reportability

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(paragraph 1.c).

Few operationhl events occurred during a lengthy and complex

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dual-unit outage. There was no apparent trend to the causes for the few events that did occur.

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liaintenance and Surveillance a

No new strengths were identified.

Three non-cited violations were identified

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in the area of surveillance involving Technical Specification (TS) required

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testing of the hydrogen recombiners (paragraph 3.d), 4KV safeguards buses J

(paragraph 7.b), and steam exclusion system check dampers (paragraph 7.c).

These surveillance testing violations we m identified through licensee programmatic reviews.

One new weakness was identified which involved inadequate control of equipmerit isolations to ensure personnel safety (paragraph 2.1).

The licensee took immediate action to address this weakness. Generally, work was controlled well during the many work activities conducted during the dual-unit outage.

Enoineerina and Technical Support No new strengths or weaknesses were identified.

Engineering support of outage activities was clearly evident.

Examples include, system engineer involvement

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with work activities and testing (paragraphs 2.d, 2.e, 2.h, 2.m and 9 a),

nuclear engineering support of refueling (paragraph 6), and project engineering support for modifications and testing (paragraphs 2.b, 4.b, and 8.n).

Safety Assessment /0uality Verification No new weaknesses were identi#ied.

One new strength was identified in the area of outage risk management.

Scheduling and control of work reflected an appropriate sensitivity to managing shutdown risk.

Poor communications contributed to the f ailure to report inoperable fire doors (paragraph 1.c).

Radiological Controls No new weaknesses were identified. One new strength was identified in the area of emergency medical response to a non-work related medical emergency (paragraph 5.a).

Response was excellent by the security force emergency medical technicians and the radiation protection technicians.

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~4 REPORT DETAILS-1.-

Operational Safety Verification (71707. 93702)

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General

Both units remained shut down for refueling, maintenance, and,

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f modification throughout the inspection period.

Only Unit 1: was refueled.

Major modifications included realignment of the plant electrical system to utilize two new emergency diesel. generators (EDG), replacement of cooling water piping, replacement of bleed steam piping, and installation of a new drain path for the Unit I reactor coolant system.

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The inspectors observed control room operations, reviewed-applicable logs,- conducted discussions with control room

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operators, and observed shift turnovers.

The inspectors verified.-

operability of selected emergency systems, reviewed equipment-

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control records, verified the proper return to service of affected components, conducted tours of the auxiliary-building, tu_rbine building, and external areas of-the plant. to observe plant equipment conditions, including potential fire hazards', Land to -

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verify that maintenance work requests had been initiated for equipment in need-of repairs.

The inspectors observed outage activities such as fuel movements, reactor reassembly, pre-operational testing,.and: preparations for startup.

The inspectors also attended outage: planning meetings to -

ascertain whether work was coordinated such that required. systems remained operable and shutdown risk was. minimized.

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Emeraency Olesel Generator (EDG) Start At 11:29 p.m.-(CST) on November 25,11992,- D5_EDG automatically - _

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started while construction electricians were working in' safeguards racks performing wire terminations associated with theLStation:

Blackout / Electrical-Systems Upgrade project.

The electrician 1

foreman supervising the work activity failed to contact: thel control room and request tr.e operators.to perform required procedural steps before_the constr_uction electrician' continued with. cable terminations. These procedural steps would have prevented the D5 EDG.from starting. This event is more fully

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discussed-in NRC Inspection Report-50-282/92024;_50-306/92024 (DRP).

_c.

Control of Fire Doors On December 2, 1992, the inspectors asked _the shift manager about

the status of two open fire doors in' the control room area., The

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fire doors penetrated the fire barriers that1 separate the control-room from the-rooms on either side of the control room; ~ Work-in--

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progress on the cooling water system prevented the rooms.from being cooled with their normal cooling systems,- and the doors had been blocked open to keep the rooms habitable.

The doors had been-open since November 29, 1992, but the' licensee did not consider-the plant to be in Technical Specification-(TS) 3.14.G.2, With the fire doors blocked open, the fire barriers were ino)erable.

Fire detectors were operable on both sides of the fire )arriers.

Therefore, TS 3.14.G.2.b) required an hourly fire watch be established for the affected areas within one hour.

After discussion with the inspectors, the licensee logged entry into TS 3.14.G 2 and stated that since the control room was continuously.

occupied, personnel in the control room provided the fire watch function.

The inspectors discussed this concept with Region III management and were informed that a fire watch had to be an identified individual unless the licensee had written authorization to take credit for personnel in a continuously; occupied space. A designated individual already assigned to a:

continuously occupied area is allowed to-perform fire watch duties.

if those duties do not interfere with other assigned duties..The inspectors informed the licensee of this policy, and the licensee designated a control room operator as the hourly fire watch.

The initial failure to establish a fire watch for the open doors is a violation (50-282/92029-01; 50-306/92029-01) of TS 3.14.G.2.b).

This violation had low safety significance because the control-room is required to be continuously occupied, the rooms on the other side of the barriers were seldom unoccupied, and fire detectors were available on both sides of the barriers. -The doors were closed and the fire barriers were considered operable on December 20, 1992.

The inspectors reviewed Operating Section Work Instruction (SWI) 0-13.

SWi-0-13 was. revised December 18, 1992, to include specific instructions on establishing fire watches for

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the fire doors.

The inspectors also verified that the licensee had placed permanent signs on the fire doors which reference TSt 3.14.G.2 and SWI-0-13.

This corrective action is considered adequate, and the inspectors have no further quest;cns on this.

violation.

This violation is closed.

During evaluation of the licensee's corrective actions for the fire door violation, the inspectors noted that,' as of January-4, 1993, the licensee had not submitted a Licensee Event Report (LER)

reporting the event. On December 4, 1992, the inspectors had

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notified the licensee of the TS violation. The LER rule

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(10 CfR 50.73) requires in paragraph 50.73(a)(2)(i) that licensees

report any operation or condition prohibited by the plant's TS.

Having the fire doors open without an hourly fire watch was a

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condition prohibited by the plant's TS.

Therefore an LER was.

required to be submitted within 30 days (January 4, 1993, since l.

January 3, 1993, was a Sunday).

Failure to submit an.LER is a l

violation (50-282/92029-02; 50-306/92029-02) of 10 CFR 50.73.

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d.

lenroper Instrument Bus isolation On December 10,1992, Unit 1 120 Volt instrument Bus No.114 was lost when No.14 inverter was isolated before the instrument bus was transferred to its alternate source, non-interruptible Bus No. 117.

The residual heat removal (RHR) system suction line from each reactor coolant system loop contains two motor-operated isolation valves, MV-32164 and MV-32165 for loop A, and MV-32230 and MV-32231 for loop B.

When the RHR system is aligned for shutdown cooling, MV-32164 and MV-32231 are opened, and the associated motor-operator breaker is tagged open to remove power to the valve.

This protects the RHR system from a single failure resulting in loss of cooling flow.

Upon loss of instrument Bus No.114, control room operators noted

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that both MV-32165 (Loop A Hot leg to RHR suction isolation valve)

and MV-32230 (Loop B Hot leg to RHR suction isolation valve) were shut.

Closure of MV-32230 upon loss of instrument Bus No. 114 is consistent with plant design.

Bus 114 powers pressure transmitter PT-420 and its associated high pressure bistable.

Loss of power to PT-420 results in closure of MV-32230 and MV-32164 (breaker tagged open).

MV-32165 should not have shut upon loss of power to instrument Bus No, 114 since pressure transmitter PT-419, associated with MV-32165 and MV-32231, is powered from 120 Volt instrument Bus No. 111.

With both MV-32165 and MV-32230 shut, the running RHR pump, No. 12, lost suction and was secured. Unit I was defueled at the time of the event.

The licensee was unable to identify the cause for both RHR suction isolation valves closing during initial investigation and decided to recreate the event.

The inspectors observed the de-energization of instrument Bus No.114 in a controlled evolution and verified that MV-32230 closed and MV-32165 remained open per plant design.

With the failure to recreate the postulated event of both MV-32230 and MV-32165 closing upon loss of power to instrument Bus No. lli, the licensee investigated the possibility that MV-32165 was closed at the time the original event occurred.

The licensee reviewed pre-and post-event data from the Emergency Response Computer System (ERCS) for No. 12 RHR pump suction pressure, motor current, and RHR system flow. The licensee noted that suction pressure was higher aft r the event when both MV-32230 and MV-32165 had been re-opened. This indicated that one of the suction. isolation valves was closed at the time power to instrument Bus No. 114 was lost.

The licensee noted during a review of the Unit 1 Reactor Log that an entry had been made on December 8, 1992, for returning No.11 and No.13 inverters to normal operation.

No. 11 and No.

13 inverters are the normal power supply for 120 Volt inst rument Buses 111 and 113, respectively. A review of an ERCS dato plot for No.12 RHR suction pressure showed that at the time of the inverter restorations there was a reduction in suction pressure

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equivalent to the value recorded prior to the event on December 10.

The licensee concluded that transfer of power for No, 111 instrument bus (from its alternate source, non-interruptible Bus No.117, to its normal source, No.11 inverter),

resulted in closure of MV-32165.

Based on observation of the controlled de-energization of instrument Bus No.114 and review of applicable ERCS data and the Unit 1 Reactor Log, the inspectors concluded that the licensee's analysis of the event was correct.

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Inadvertent Safeauards Bus lock-out On December 10, 1992, 4160 Volt safeguards Bus 25 received a lock-out signal when a test switch was not opened during test tripping of the 2RY source breaker. This resulted in a loss of the running residual heat removal (RHR) and component cooling pumps on Unit 2.

The standby RHR pump was started in 24 seconds.

The reactor vessel head was removed, and the reactor cavity flooded up at the time of the event.

This event showed that the licensee's decision to flood up the cavity to provide an additional margin for core cooling, was an example of conservative shutdown risk management.

This event is more fully discussed in NRC Inspection Report 50-282/92024; 50-306/92024 (DRP).

f.

Hiah Flux at Shutdown Alarm Blocked On December 14, 1992, during refueling operations, control room operators for Unit 1 observed that both source range "High Flux at Shutdown" monitors were blocked.

These monitors are not required by the Technical Specifications, however, they are additional safety devices, and it was the intent of management that they be in use when appropriate. The inspectors verified that the licensee restored the monitors to service in a timely manner.

The licensee's review of activities related to the monitors did not identify a specific time when the monitors were left blocked.

More thorough log keepine would have increased the likelihood of maintaining the monitors in the proper status.

The inspectors have observed other cases of minor deficiencies in documentation of activities. Although the licensee has made improvements in this area, it needs to continue its efforts.

The licensee also noted that procedure D5.2, " Reactor Refueling Operations," did not have a step to verify that the monitors are not blocked.

The licensee submitted a procedure change request to add a verification step, g.

Automatic Starts of Comogpent Coolina Water Pumps At 3:13 p.m. (CST) on December 30, 1992, No. 12 Component Cooling (CC) pump automatically started on low discharge header pressure when motor-operated valve MV-32120 (11 CC heat exchanger outlet crossover isolation valve) was inadvertently shut. The control room operator shut MV-32120 instead of MV-32132 (11 containment f an coil unit cooling water isolation valve) as required by the

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work request for fan coil cooling water valve testing.

This engineered safeguards featuro actuation was the result of-personnel error and is_therefore being reviewed by the licensee's-Error Reduction Task Force. The licensee will submit an LER for-this event and the inspectors will review the licensee's corrective actions identified in the LER. -

At 10:48 p.m.- (CST) on January 4,1993, No. 22 Component Cooling (CC) pump automatically started on low pressure in the CC system.

While switching residual heat removal (RHR)-trains.in accordance with Operating Procedure 2015, " Residual Heat Removal System,"

motor-operated valve MV-32129 (22.RHR heat exchanger CC inlet i

valve) was opened increasing the CC system flow.

This resulted in a lowering of system pressure and automatic start of the standby CC pump,-No. 22.

The licensee has experienced previous _ automatic starts of CC. pumps due to pressure fluctuations.- Precaution 3.3 was'added to Operating Procedure 2014, " Component Cooling System Unit 2" to alert _the operators to the need to start the standby pump prior to CC valve operations.

The operator performs CC valve operations in 2C15, and in this case the operator did not follow the precaution in 2014 when performing the valve operation in 2C15.

Since CC valve operations are performed by ste)s in procedure 2C15, it would have been prudent to alert tie operators-to the precaution in 2014. The licensee had a recent opportunity-to accomplish this.since procedure 2C15'had been revised in November 1992.

After this event, the operators submitted a-procedure change request to avoid a future occurrence.

The licensee will. submit a LER for this event, and the inspectors will-review the licensee's corrective actions identified in the LER.

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Two violations were identified. No deviations, unresolved items, or inspection followup items were identified.

2.

Maintenance Observation (37700. 62703)

Rautine preventive and corrective maintenance activities were observed

to ascertain that they were conducted in accordance with approved

- procedures, regulatory guides, industry ' codes or standards, and in conformance with Technical Specifications. The following items were

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considered during this review:

adherence to Limiting. Conditions for Operation while components or sys_tems were removed from service, approvals were obtained prior to initiating the work, activities were accomplished using-approved procedures and were inspected as applicable, functional testing and/or calibrations were performed. prior to returning components or systems to service, quality control records were maintained, activities were' accomplished by qualified personnel _~,

- radiological controls were implemented,- and-fire prevention controls-were implemented.

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- Portions of the following maintenance activities were observed or reviewed during the inspection period:

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Unit I and Unit 2 reactor vessel head reassembly, b.

Replacement of loop A and B cooling water piping. This project included demolition of existing piping, installation of new piping, weld overlay of non-removable piping sections, epoxy coating, installation of new branch lines to the auxiliary feedwater pumps, and hydrostatic testing. A portable 480V space heater was used to help cure the epoxy coating in the turbine building. On December 17, 1992, the heater overheated internally and began smoking. A fire alarm was received in the control room, but personnel in the vicinity of the heater had already observed the smoke, disconnected the heater, and discharged a fire extinguisher irto the heater.

Those actions were reported to the control room shortly after the fire alarm was received.

The inspectors verified that there was no damage to permanent plant equipment.

The inspectors.also observed that there was slight visible damage to the space heater, c.

Madification of Unit 1 4160 Volt safeguards Buses 15 and 16.

Modification activities included the installation of new digital load sequencers on each bus, the addition of an offsite source to Bus 15 (CT-ll), removal of the old bus ties between safeguards Buses 15 and 26 and safeguards Buses 16 and 25, and installation of new bus ties between Buses 15 and 25 and Buses 16 and 26.

d.

Treadle modification on 4KV Buses 15 and 16. This modification allows the respective bus source breakers to be racked out to the test / disconnect position.

In this position, the breaker stabs are disconnected from the bus bars while the breaker control circuit still functions.

To perform the treadle modification safely on the IRY source breakers to Bus 15 and 16, the licensee had to secure offsite power to these breakers by opening the IR Auxiliary Transformer output breakers.

With the 01 emergency diesel generator out of service due to the loop A cooling water piping replacement and IR not available, the licensee entered a condition where only two power sources were available to Bus 15 (CT. ll and.

the bus tie from 4KV Bus 25).

To maintain defense in depth for key safety functions, specifically decay heat removal, inventory control, power availability, reactivity control, and containment integrity, the licensee developed a shutdown safety assessment. The shutdown safety assessment provided a status indication of the availability of the systems, structures, and components needed to support the various key safety functions.

This status indication is in the form of color coding (green, yellow, orange, and red).

An orange condition indicates that the minimum redundant equipment is available to support the key safety function.

Planned entry into an orange condition requires a contingency plan and review by the onsite review committee.

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With only two sources available-to Bus 15,-the licensee entered an

orange condition of power availability. =The inspectors verified

that the licensee developed an adequate contingency procedure to restore power to Bus 15 in the ever.t that-the remaining two-a sources were lost. The inspectors concluded that the _ licensee's scheduling and control of work for the Bus 15 and 16 treadle

modification reflected an appropriate sensitivity to managing shutdown risk.

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Disconnection and reconnection of CT-11 and CT-12 feeder cables, i

The licensee also entered a planned orange condition _ for power availability after it discovered that the 13.8 kV CT-11 and CT-12-feeder cables were intermixed over the Loop B Cooling Water header

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between the screenhouse and the turbine building. The cables had to be deenergir.ed to move them.

The project was well-planned and a contingency plan was developed and properly reviewed, f.

Unit 1 Steam Generator Eddy Current Testing.

The inspectors reviewed the results of the inservice inspection of No.11 and

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No. 12 steam generators. Twenty percent of the tubesheet region in No. 11 steam generator was inspected using,the motorized rotating pancake coil (MRPC) probe. -One tube was plugged for

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thinning at the cold leg tube support plate.

l One hundred percent.of the tubesheet region in No. 12 steam generator was examined using the MRPC probe. This examination identified 178 defective tubes requiring repair.- Twenty-.of these tubes were plugged, and the remaining-158 tubes were repaired by-installing welded tubesheet-sleeves.

In_ addition, one previously sleeved tube was plugged due to pin hole leaks in the lower sleeve weld identified during the steam generator leak-test.

The major cause of tube degradation in No. 12 steam generator is secondary.

side intergranular attack and-stress corrosion cracking.

The results of the inspection of No.12_ steam generator were classified as Category C-3 since more than one percent of the inspected tubes were defective. The licensee discussed this-situation in a conference call-with Region. III-and NRR.

This discussion was followed with a letter report to tho' NRC.

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g.

Overhaul of Unit 1 and Unit 2 high pressure turbines.

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Unit I an ' Unit 2 bleed steam piping replacement.

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Installation and transfer of Unit-1 and Unit 2 4KV safeguards bus control s.

This-included transfer of Bus 16 controls from the old

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control room G panel to the temporary control room G panel,_

installation of new Bus 25 and 26 controls _ in the temporary' G.

panel, disconnection of Bus 15 and old Bus 25 and 26 controls from the-old-G panel, removal of the old G-panel, installation of. the new G panel, transfer of Bus 16, new Bus 25, and. new Bus 26-controls from the temporary G panel to the new G panel, and installation of Bus 15 controls in the new G panel.

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Removal and replacement of Unit 2 moisture separator reheater tube bundles.

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Unit 1 and Unit 2 reactor coolant system fill and vent.

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Bus 210 disconnection.

On November 23, 1992, a Station Blackout Project (SBO) electrician working on 480V Safeguards Bus 210 shorted a tool to ground from the load side of Breaker 218.

The electrician and another electrician working with him did not know that the load side of Breaker 218 was energized.

After this event was reported to the control room, all work was stopped on safeguards 480V busses. The inspectors observed the licensee's critique of this event.

The electricians stated that they had tested Gus 210 to verify that it was de-energized, but that they did not test the cable from Breaker 218 to Motor Control Center (MCC) 111.

This was the cable the electricians were attempting to disconnect, as directed by a step in the work request that they were using.

The isolation used for the work was prepared based on a schedule that called for the cable to be disconnected from MCC ITl before work was to be started on Bus 210.

However, the Bus 210 work was started before the MCC ITl work was done.

MCC ITl was energized from another breaker (it could also be energized from Breaker 218), so the cable from Breaker 218 to MCC ITl was energized.

The critique was thorough and focused on identifying corrective actions.

Following the critique, the licensee also stopped work on 4160V Safeguards Buses 15, 25, and 26.

Work was resumed on each bus following an independent review and verification of the isolations.

The SB0 electricians were reminded of their responsibility to verify the status of circuits they are working on by testing.

Later, the licensee began preparation of permanent signs to be placed inside electrical cubicles that have alternate feeds.

The signs warn workers that the load sides of breakers may be energized even though the breaker is open.

The licensee's Error Reduction Task Force will also perform an investigation of this event.

MCC ITl was temporarily taken out of service following this event, de-energizing safeguards equipment.

The inspectors verified that the licensee's evaluation of the effects of the de-energized equipment was adequate, m.

Repair of control valve (CV) 31236, Residual Heat Removal (RHR)_

Heat Exchanger No. 12 Outlet Finw Control Valve.

After a broken key was found on a similar butterfly valve (CV 31239), the licensee removed the actuator arm and inspected the key on CV 31236.

The key anchors the actuator arm to the valve stem.

The key was satisfactory and the arm was reinstalled.

On December 11, 1992, control room operators observed that this valve was not operating proper y.

Maintenance and engineering personnel concluded that the key had broken as a result of interferences created when the arm was replaced after the key inspection.

The interferences were eliminated, and the valve was returned to service.

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i On December 15, 1992, the key failed again.

The valve was

removed and disassembled.

The valve stem bushings were slightly

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deformed so tnat the valve disc was allowed to make contact with the valve body when the valve was closed. Oncr the disc was in-l contact with the valve bof,. further movement

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could lead to key failure.

Key failure allows the valve to fail i

in a position other than its safety feetion position. The

inspectors discussed the key failure with licensee engineering

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personnel and observed the licensee's onsite review committee discussion of corrective actions on December 18, 1992.

The Itcensee manufactured new 410 stainless steel bushings and

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reassembled the valve.

There is one CV in the outlet of each RHR heat exchanger.

The safety function of the valyc is to remain

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open during an accident, and the normal position of the valve is open.

The licensee concluded that bushinge. in the other three valves would not-deform enough to allow key failure before the

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next refueling outage for each unit.

Tha licensee is planning to replace the bushings and keys on the valves at a ten-year i

frequency as part of a schedeled preventive maintenance activity.

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1he inspectors verified that the licensee established administrative controls on the valves to prevent them from being closed far enough fcr the disc to contact the valve body in case

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the bushings do deform enough to allos such contact.

The licensee also evaluated similar valves in other tystems to verify that a similar failure would not have any impact on plant safety.

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licensen has not completed its evaluation of this maintenance activity.

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Transfer of-180 Volt motor control centers and safeguards equipment from the old 4160 Volt Buses 25 and 26 to new Buses 25 and 26.

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Repair of defective heat tracing for the Auxiliary fcedwater (AfW).

recirculation piping path to the condensate storage tanks.

During_

the Unit 2 Integrated Safety injection Test, No. 21 AFV Pump overheated because water in the piping was frozen.- This occurred because the redundant heat tracing circuit was teken out of service when the normal heat tracing circuit was already out of

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service. 1his was caused by inadequate communications between

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operations.and-systems engineering. The inspectors verified that the licensee had a plan in place for corrective _ actions,' including verification that the-AFW pump had not been damaged.

The heat

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tracing is not safety-related.

No violations, deviations, unresolved or inspection followup items were identified.

3.

Sittveillance 137700. 61726)

The inspectors reviewed' Technical Specification required surveillance e

testing as descrlhed'below. and verified that testing was performed in accordance with adequate p..cedures, test. instrumentation was-

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calibrated, and Limiting Conditions for Operation were met.

The inspectors f urther verified that the removal and restoration of affected components were properl accomplished test re;ults conformed with s

lechnical Specifications and procedure requirements, test results were reviewed by personnel other than the individual d h tting the test, and deficiencies identified during the testing were properly reviewed and resolved by. appropriate management personnel, portions of the following test sctivities were observed or reviewed:

a.

SP 1083, Unit 1 Integrated Safety injection Test.

The Technical Specifications require that at least once each 18 months the licensee must simulate a loss-of-offsite power in conjunction with a safety injection (SI) signal and verify de-energization and load shedding of the emergency (sofogu>.ds) buses followed by automatic starting and loadin, of the associated emergency diesel generator (EDG).

This surveillance test is referred to as the integrated 51 test.

The incpectors reviewed the results of this test.

The licensee identified that some test acceptance criteria were

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not satisfied, preoperational testing of the D1 and D2 EDGs was performed in cccordance with Safety Guide 9.

Some of the requiren nts of this safety guide were addressed in tests performed -on a prototype diesel.

Safety Guide 9 states that at no time during the loading sequence should the voltage decrease to less than 75 percent of nominal, and voltage should be restored to within 10 percent of nominal in less than 40 percent of each load se aente time interval.

Section 8.4.2 of the Updated Safety s

Anal,'is Report (USAR) states that " prototype tests and subsequent alculations indicate that the first in-rush seen by the diesel when starting both the safety injection pump and the nonrejected loads that are ccanected to the diesel bus can cause the voltage to decrease in excess of the 75 percent of nominai as stated in Safety Guide 9.

This voltage dip is restored to normal within a maximum of 2 seconds.

Since the voltage dip occurs on the first step of load ;pplication to the diesel generator, the safety related loads still start as required when the excitation returns to normal, for this reason it is felt that this exception to Safety Guide 9 does not degrade the reliability of the safety features of the plant."

Test data for SP 1083 indicated that the initial voltage dip en the first step of load application for the 01 and D2 EDGs decreased to an expected value of approximately 67 percent of 1cminal, but did not return to normal within the required 2 seconds 3s stated in the US/R.

The lowest voltage occurred approximately 0.3 seconds af ter closure of the diesel generator output breaker and returned to within 10 percent of nominal in

"

approximately 2,25 seconds (45 percent of the load sequence interval).

This exceeded the voltage restoration criteria specified in Safety Guide 9 (40 percent of the load sequence interval).

'

e t,

_. _ - - _ _ -. _ _ - - _. _ - _ - -.. _ _ - - _ _ _ _ _ _ _. _ _. - - _ _ _ - - - - -.

-_

. - _ _ _ _ _ - _ _. _. _ - _ _ _ _ _ _ - - _. _ _ - - _ _ _ - _ _ _ _ _ - _ _ _ _. - - - _ _ _ -

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_

.

The licensee concluded that the manner in which the integrated Si test was performed resulted in the failure to meet test acceptance criteria, llistorically, the licensee had simulated a loss-of-offsite power by manually opening the safeguards bus main supply breaker.

By using this simulation method, the licensee did not challenge the undervoltage (UV) logic circuitry to automatically de-energize the safeguards bus in response to a UV condition.

This is more fully discussed in NRC Inspection Report 50-282/92015(DRP); 50-306/92015(DRP).

In response to this t

identified testing deficiency, the itcensee revised the manner in which the integrated Si test is performed.

As part of the test setup for a particular unit, each of the two 4160 volt safeguards buses are energized from the other unit's safeguards bus through the corresponding tie breaker, i.e. Unit I safeguards Buses 15 and 16 are energized from Unit 2 safeguards Buses 25 and 26, respectively.

Both safeguards bus source breakers from offsite (lRY and C1 11 in the case of Unit 1) are racked out to the test / disconnect position.

The test is then initiated with a manual SI signal.

This results in tripping of the associated bus tie breakers (de-energizing the bus) an'i the subsequent closing and opening of each bus source breaker from offsite (no power is provided to the bus since the breakers are in the test / disconnect position).

When the associated diesel has reached rated speed and voltage, the diesel output breaker shuts, energizing the safeguards bus.

While this method of performing the integrated Si test demonstrates the proper functioning of the UV logic circuitry in automatically de-energizing the safeguards bus in response to a UV condition, it results in an increased time from EDG start to diesel output breaker closure.

This allows the voltage regulator to stabilize voltage fluctuations such that the EDG is at rated nominal voltage when the output breaker shuts, in contrast, the previous testing method resulted in the output breaker closing when the EDG voltage was higher than nominal due to the overexcited condition of the voltage regulator.

This higher initial voltage at output breaker closure would result in a shorter time for the generator voltage to recover following load application, e

a in evaluating the significance of this issue, the licensee teferred to Regulatory Guide 1.9, " Selection, Design, and Qualification of Diesel-Generator Units as Standby (Onsite)

Electrical Power Systems at Nuclear Power Plants," which addresses an acceptable method for complying with General Design Criterion 17 of Appendix A to 10 CFR Part 50.

In discussing load-accepting capabilities of the diesel generator, Regulatory Guide 1.9 states that voltage should be restored to within 10 percent of nominal within 60 percent of each load requence time interval.

SP 1083 test results would have been acceptable if this standard were used.

The inspectors noted that the licensee has no commitment to follow Regulatory Guide 1.9.

.__

_ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _

. _ _ _

. _ _ _ _ _ _ _ _

,

.

'

The licensee performed a 10 CFR 50.59 evaluation and determined that this issue did not involve an unreviewed safety question.

.

The inspectors reviewed the 50.59 evaluation and participated in a l

conference call betwes. NRR, Region 11_!, and the licensee to

discuss the licensee's conclusions.

The inspectors were satisfied

,

with the licensce's resolution of this issue..

o.

SP 2083, Unit 2 Integrated Safety injection Test.. The inspectors observed the performance of this test on January 4, 1993, from the

,

control room, the emergency diesel generator (EDG) rooms, the auxiliary feedwater pump (AfWP) rooms and-the 4160V switchgear

rooms.

The inspectors also reviewed the results of this test..

,

During the test, operators in the AFWP rooms observed high temperatures on the motor driven AfWP.

The AFWP was stopped and.

'

the licensee began investigating the cause of the high temperatures.

This initial results of this investigation are-discussed in paragraph 2.0. of this report.

The pump is required for the integrated Si test.

Although the test appeared to be satisfactory, it was run a second time because some EDG

,

performance data was not recorded.

During the second test.the licensee aligned the No. 121 motor-driven cooling water pump so-that it started and was loaded onto a diesel-powered bus.

The second test also appeared to be satisfactory.

Since this test was

completed on the last day of the inspection period the inspectors

'

did not evaluate the licensee's review of the test, c.

Unit 2 Train A and B Sequencer Testing.

,

d.

Electric Hydrogen Recombiners resistance to ground test.. During a.

review of Technical Specification (TS). required testing for the hydrogen recombiners, the licensee identified a potential violation of TS 4.4.1.

TS 4.4.1 requires that the operability of

each hydrogen recombiner train be demonstrated (1) at least once per six months by. verifying during a recombiner system functional test that.the minimum heater sheath temperature increases to greater than or equal' to 700 degrees Fahrenheit' within.90 minutes, and (2) at least once per 18 months by performing a resistance to

'

ground test following the above required functional test.

The i

licensee performs the resistance to ground test during a refueling

'

outage.

This does not coincide with the six month functional

.

check.

The licensee could not identify any-technical basis for

. performing the resistance to ground test within a certain time frame following the functional test.

The licensee discussed this issue with the inspectors.

Based on

'

discussion with technical reviewers in the Plant Systems Branch in-NRR, the inspectors enneluded that there was no technical basis for performing the resistance to ground check within a certain time fo? W ing the functional test. However, the~ inspectors concludeu that the intent of TS 4.4.1 as written,'.was to perform the resistance to ground test shortly following the functional test, and therefore the licensee was in. violation of TS 4.4.l.

,

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.

This violation will not be subject to enforcement action because

the licensee's efforts in identifying and correcting -the violation

'

met the criteria specified in Section Vll.B.2 of the " General Statement of policy and Procedures for NRC Enforcement Actions,"

'

(Enforcement policy, 10 CFR Part 2, Appendix C).

l e.

Unit 2 Containment Integrated Leak Rate Test.

,

One non-cited viol _ation was identified.

No deviations, unresolved, or inspection followup items were identified.

4.

En91neid1L4_and. Technical.Amport 1111001 a.

[yAn11pn of Foreian Ob.iect in Reador Vessel The licensee identified that during the assembly of a Westinghouse Sample Insertion 1001 for inserting a vessel sample into one of the two Unit I sample holes located in the lower internals flange at the edge of the reactor vessel, a 5/16 inch nut was potentially dropped into the reactor vessel.

The licensee discovered that a

nut was missing from one of the cable clamps on the insertion tool's rigging.

The rigging is a piece of equipment-used to

,

transport the disassembled tool from the staging area, just inside the Unit 1 maintenance airlock, to the assembly fixture bolted to the Manipulator crane.

The licensee discovered that the nut was missing after the insertion tool had been assembled and used.

The

'

licensee performed an analysis to evaluate the consequences of having a nut in the bottom of the reactor vessel for the next fuel cycle.

The 20 year inservice inspection'of the reactor vessel is scheduled for the next Unit 1 outage.

The licensee concluded that the nut would remain intact and would not corrode enough in one cycle to pass through the bottom nozzle of a fuel assembly.

The inspectors reviewed the licensee's analysis and concluded it was adequate and that there was no unreviewed safety question, b.

Stlam Generator Thermal Sleeves The licensee removed and replaced portions of feedwater (FW)

piping upstream of the FW nozzle on each steam generator for both units.

The purpose was to quantify the amount ofiFW nozzle, thermal sleeve erosion that has occurred over the life of the 31 ant and evaluate the structural integrity of the FW nozzles aased upon the inspection findings.

Other nuclear plants have experienced substantial outer diameter thermal sleeve erosion.

This condition results in increased FW leakage flow around the thermal sleeve, raising a concern that thermal stresses: induced.

due to the injection of cold auxiliary feedwater (AFW) during an accident, testing, or hot standby conditions could accelerate cracking in'the.FW nozzles.

!

The inspectors observed work in the field, including FW pipe removal, examination of the thermal sleeves, and FW piping

'

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.

-.

.

. - _ _ ___ _ _ __ _ _ _ _ _ _ _ _

- _ _ _

_ _ - _ _ _ _ _ _ _ _-

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.

,

replacement.

The inspectors reviewed results of the licensee's

inspection and its safety evaluation regarding structural-integrity of the FW nozzles, with consideration of current and

,

predicted thermal sleeve erosion.

The inspection results indicated that the thermal sleeves had.

[

experienced a significant amount of outer diameter erosion.

The t

'

resultant annular gap provides a path for leakage flow bet,4een 3-and 9 percent of FW flow to each steam generator. The licensca t

evaluated the effects this leakage flow would have on the thermal performance of the steam generators, effects the cylindrical jet of leakage flow has on the feed ring and other components,

potential water hammer effects, and the potential for FW nozzle

,

cracking.

!

'

With regard to the first three items, the licensee ccocluded that the effects of increased leakage flow are negligible.

With regard to nozzle cracking, the licensee performed nondestructive examination of the " knuckle" regions of the nozzles.

No-i indications of cracking were identified; however, the licensee performed a fracture mechanics analysis to evaluate the effects of.

postulated cracks present in areas unreachable for inspection.

The analysis concluded that if cracks were to initiate, given_a conservative amount of nozzle by ass flow, nozzio intogrity would a

,

be maintained through at least 11e next three operating cycles for Unit 1 and Unit 2.

This assumes an " average" period-of AFW operations during each cycle and a conservative amount of continuing thermal sleeve erosion, r

The inspectors had no further questions concerning the. licensee's safety evaluation regarding structural integrity of the FW.

,

nozzles.

t c.

Incore Instrumentation Tube Wear The inspectors reviewed _the itcensee's safety evaluation, " Bottom-Mounted Instrumentation Flux Thimble Wear," and observed portions

of Unit I seal table work in containment.

The safety e /aluation

-

documented the licensee's review of new acceptance criteria for -

t thimble tube thinning,.an--issue discussed-in NRC Bulletin 88-09;

'

Historically, the. licensee used conservative acceptance criteria for_ eddy current examination (ECT) of-its thimble tubes; repositioning tubes at 40 percent wall loss and capping kubes at

,

50 percent wall loss.

The new acceptance criteria are: based on data from a recent Westinghouse-0wners Group (WOG)Lstudy that recommended an 80 percent wall loss acceptance criteriont The

-

licensee's safety evaluation, approved by the onsite safety review committee,. adopted less conservative acceptance criteria than that'

!

historically used, but more conservative than the WOG recommendation.

The new criteria require repositioning at.60

,

percent wall loss and capping at 80 percent wall loss.

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i Based upon the onsite safety review committee's approval of this f

safety evaluation and the results of the Unit 1 ECT,- the licensee was able to reclaim three thimble tubes for use which had been a

previously capped per the old capping criterion.

The inspectors had no further questions concerning the itcensee's

,

thimble wear evaluation, i

No violations, deviations, unresolved or inspection followup items were identified.

5.

Radioloaical Controls (717071 a.

Emeroen.cv Medical Response

'

On December 30, 1992, the inspectors observed the licensee's response to a non-work related, medical emergency in the auxiliary building. An emergency medical response team was dispatched to i

the location where a plant electrician became ill, The-inspectors

,

observed emergency medical technicians (EMTs)-respond to the site,.

administer first-aid, and prepare the patient for transport out of the plant to an ambulance.

Radiation protection (RP) technicians-

,

also responded to ensure that the patient, EMis, and equipment

,

were not contaminated prior to departure from the auxiliary ouilding. The patient was transported via ambulance to a hos) ital in Red Wing, MN.

The inspectors noted that the response of tie

-

EMis and RP technicians to this medical emergency was excellent.

'

b.

laak Discharae Before Aqproval

On December 7. 1992, the licensee released the liquid contents of the wrong aerated drains treatment (ADT) monitor tank.

The licensee intended to discharge two ADT tanks, but only one tank had been sampled and approved for release. This event is discussed in NRC Inspection Report 50-282/92032; 50-306/92032 (ORSS).

No violations, deviations, unresolved, or inspection followup items were

identified.

6.

Refuelino (60705. 607101 The inspectors observed refueling activities as described below to ascertain if controls had been implemented for the conduct of refueling operations and for establishing and maintaining control of plant conditions in accordance with-Technical Specifications and approved procedures.

The inspectors observed four operating crews conduct the core reload for

Unit 1.

Prior to the dual-unit outage, the licensee had installed a-modification to the manipulator crane controls. During refueling; the licensee experienced some minor mechanical / electrical problems with the

.

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- - _ - _ _ _ - _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _

!

manipulator crano.

The inspectors observed that as each problem arose, i

the licensee suspended fuel handling operations and adequately resolved

!

the problem before recomnencing fuel handling.

l During the core reload, the securing strap broke on a pair of binoculars.

f being used by one of the refueling operators, causing the binoculars to -

fall into the refueling cavity and settle on the reactor vessel core plate. While one of the operators was attempting to retrieve the

.

binoculars, he inadvertently knocked off his safety glasses into the-i refueling cavity.

The inspectors-observed the o>erators retrieve both

,

the binoculars and safety glasses and verified t1at each item was still I

intact, flo violations, deviations, unresolved or inspection followup items were identified.

7.

Licensee followun on Previously_ identified items (92701. 927q?1

'

a.

ICloadi Violat10n_202/1@04-Olj Failure to properly log an

!

opening in the auxiliary building special ventilation-zone (ABSVZ).

On January 17, 1990, and february 15, 1990, the installation and l

removal of the eddy current cable connection flange created an i

opening in the ABSVZ that was not administrative 1y controlled by t

logging the size, location, time, and date that the opening was opened or closed. The eddy current cabic connection flange is installed at the containment pressurization penetration.

This was

)

in violation of Technical Specification 3.6.E.2 and Operations-Procedure 054, " Control of Openings in the ABSVZ Boundary "

The inspectors verified that the licensee completed the following corrective actions:

-

Revised' Operating' Procedure D61, " Containment Penetration Outage Preparation and Outage Restoration Procedure," to clearly identify the requirements _for logging openings.

-

Established Operating Procedure D61.1, " Installation and Removal of Steam Generator Services Cables at Containment

.

Penetrations," to clearly identify work steps and a

requirements associated with the installation and removal of l

the cables, l

Placed information tags on the containment pressurization

-

penet_ ration blank flanges stating the logging requiremen_ts, h

1his violation is closed, b.

(Closed) Unreso_].ved item 50-282/92015-01: 50-306/92015-01:

Failure to perform safeguards Bus 16 testing within the allowed -

Technical Specification (TS) surveillance interval.

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________-_______-__-__ _____ _ _ _ _ _ _ _ _ _ _ __ _ _ _

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.

!

.

The licensee had not tested the undervoltage (UV) tripping

.,

function of the safeguards bus source breakers within the allowed surveillance test interval of 18 months plus 25 percent.

The

licensee identified this testing deficiency during an operational

experience assessment of an event reported by another utility.

On

,

August 11, 1992, the NRC issued a license amendment providing for a one-time extension of the surveillance test interval for periodic testing of the source breaker UV trip feature of the

automatic voltage restoration function of the 4KV safeguards

!

buses.

This amendment allowed the licensee to defer performance of the required testing until completion of the electrical system upgrade modifications for the station blackout project during the dual-unit outage.

This item was considered unresolved pending

review and evaluation of the licensee's corrective actions described in LER 282/92009.

-;

The licensee replaced the source breaker UV relays during the dual-unit outage.

As a result, the original relays were not

.

tested to verify.perability.

There was no evidence that the original relays u>uld not perform their intended function.

The-

,

inspectors revitaed the results of the integrated safety injection

'

test for Unit I and verified that the undervoltage triaping t

function for safeguards Buses 15 and 16 was tested.

Tie-failure

,

to perform safecuards Bus 16 testing within the allowed surveillance interval is considered a violation of TS 4.6.A.3.b.l.

i This violation will not be subject to enforcement action because

"

the licensee's efforts in identifying and correcting the violation met the criteria specified in Section Vll.D.2 of the " General

Statement of Policy and Procedures for.NRC Enforcement Actions,"

(Enforcement Policy, 10 CFR Part 2, Appendix C).

This item is closed,

c.

(Closed) Unresolved item 50-282/92021-01: 50-306/92021-01:

Failure to test _ check dampers for the steam exclusion system.

'

This failure was identified by the licensee's design basis reconstitution effort and was reported by LER 282/92010.

The LER stated that some of the dampers were " sticky." The inspectors discussed this item with the system engineer who checked the dampers.

She stated that only one of the dampers.was sticky-enough for her to consider that it might be inoperabic.

This test

-

is subjective ~as there is no measuring tool to measure the amount

'

of force necessary to__ operate the damper._ lt is likely that the-damper would have closed at least part way, limiting the amount of

_

steam that could affect safety-related equipment.. Therefore this condition was of_ minor safety significance.

Corrective action was initiated.to ensure that the damper test procedure includes the

,

check dampers. _ Corrective ' action was already i_n place to review

'

TS test requirements to ensure that all testing is done properly.

-i failure to test the. check dampers was a violation of TS 4.8.C.

-This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation

,

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. _ _ _, _... _ _ _..

..

_

...

-

_

.

_ _ _ _ _ _ _ _ _. _ _ _.

.

,

met the criteria specified in Section Vll.D.2 of the " General Statement of Policy and Procedures for NRC Enforcement Actions,"

(Enforcement Policy, 10 CFR Part 2, Appendix C).

This item is closed, two non-cited violations were identified.

No deviations, unresolved, or inspection followup items were identified.

8.

LicarmtEverit RenorLILIlq_Lellswjt{M700. 92701. _37700)

LClosed) lER 282M QOjl2:

Automatic start of a component cooling i

a.

water (CC) pump due to momentary low pressure during surveillance test.

This automatic start occurred when the operator did not hold the pump contrcl switch in the off position long enough for aressure oscillations to subside.

The inspectors verified that t1e licensee installed a warning label between the pump control switches and had made procedural changes to prevent pump starts during this surveillance test and during other CC pump operations, lhis LER is clused.

b.

1 Closed) LER 212/90014: Auto-start of one train of control room special ventilation due to inadequate work instructions.

The auto-start was caused when the chlorine monitors were deenergized.

Since the time of this event, the requirement for chlorine mon! tors has been deleted f rom the TS by a license amendment.

The monitors are now bypassed and, therefore, cannot cause auto-starts of the control room special ventilation system.

This event was discussed in Inspection Report 50-282/90014; 50-306/90014 and a non-cited violation was issued.

Several short term and long term corrective actions were discussed in the inspection report.

In addition, the licensee's LER identified another long term corrective action.

The long term corrective actions identified in the inspection report and LER included improvements in the niethod and timeliness of updating load lists during the modification process.

The inspectors concluded that the licensee's use of a computer to provide for more timely updating of plant data files (including load lists) with changes caused by modifications, was an improvernent over the previous method for updating plant data.

The inspectors verified that Administrative Control Directive SACD 4.5, " Plant Component Data files," requires that tipdate Forms be completed as soon as final "as-built" data is available, and that Corporate Nuclear Administrative Work Instruction NlAW1 5.1.16

" Turnover for Operation," includes a signoff on the Turnover

-

Checklist indicating that required drawings and data files have been updated.

This LER is closed.

l

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_ _ _ _ _ - _

____

_ _ _ _ _ __ _ _ _ -- _ _ _.

1

.

,

i c.

(Closed) LER 282/91002._ kvision 1: Auto-start of control room

-

special ventilation system due to spike on newly installed radiation monitor.

The licensee had originally reported in LER 282/91002 that the radiation monitor had spiked because it had not been subjected to a 100-hour burn-in" test by the manufacturer. The original LER

was closed based on review of the corrective actions described in

!

that LER.

After that report was submitted, the monitor manufacturer completed its investigation of the spurious high

,

radiation alarm spike and-identified the cause of the problem to be an improper program on the firmware associated the alarm

-

function.

The licensee submitted Revision 1 to the LER based on

the new information received from the manufacturer.

The

manufacturer corrected the firmware problem, and the licensee

'

performed a quality assurance audit of the manufacturer.

As a-result of findings identified during the audit, the manufacturer

!

was removed from the licensee's qualified supplier list until the findings were resolved.

This LER is closed based on the new corrective actions described in the revised LER and the earlier review of the applicable corrective actions described in the original LER.

d.

L(loieJLLG_ zed].@l: Auto-start of auxiliary building special

ventilation system due to unknown cause.

The No. 121 Auxiliary Building Special Ventilation System (ABSVS)

started after a downscale failure of Radiation Monitor 2R-37.

The

!

monitor is designed to start the ABSVS when it detects high

'

radiation.

There was no evidence of high radiation, and a thorough investigation of the operation of the monitor _ revealed no -

reason for the downscale failure. The downscale failure was an isolated event and did not appear to be related to the_snftware-probitms identified in other similar radiation monitors (see LER 282/91002 discussion above).

Due to the minor safety' significance of this event, no further inspection is warranted.

This LER is

- I closed.

e.

(Onen) LER 282/91004, Failure of redundant heat trace circuits as a result of electrical fault.

On May 9,1991, an outplant nperator was hanging a realacement identification tag on a valve.

To reach the valve, tie operator.

stepped on an insulated and heat traced section of safety injection piping. When the operator stepped off-the pipe, he smelled and observed smoke emitting from beneath-the pipe insulation.

The licensee determined that the operator had stepped on steel

-

banding used.to attach a heat trace junction box to the pipe.

This caused the free end of the banding to penetrate the heat-

trace cable insulation initiating a ground and causing an-arcing-L

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fault.

During the root cause investigation, the licensee determined that a second ground had to be present for a fault path l

to exist.

Therefore, the operator's actions alone could not have

'

caused the short.

A continuity check identified a second ground

.

on a control switch for Unit 2 heat trace circuit ET-69R.

It was

!

not determined how long the ground on ET-69R had existed, it was installed in 1985 and no work had been performed on it since.

.,

The inspectors verified that the licensee had completed the

following corrective actions:

{

I performed megger and continuity checks and voltage tests of

-

associated equipment.

No problems were identified.

(WR R3092-HT-Q)

Tested heat trace circuit breakers.

No problems were

-

identified. (WR R3402-EB-Q)

Inspected the affected piping for surface defects such as

-

arc strikes.

Affected areas were buffed and liquid penetrant tested. No indications were identified.

(WR R3221-St-Q)

Evaluated the need for instructio;. fo* climbing on heat

-

traced piping.

It was determined that current plant safety practices discourage the use of pipes and other apparatus as-ladders.. However,-the valve which required tagging was located such that it was impractical to use ladders or scaffolding to reach it.

Since this.is an isolated case, the licensee determined no further instructions are required.

This LER will remain open until the inspectors can evaluate completion of the following licensee corrective actions:

-

Evaluate a change to Technical Specifications to clarify the'-

heat trace requirements and basis.-

Evaluate the need for a ground detection system or a

-

periodic ground detection test.

f.

10lp_stfd) LER 282ML01Q: Design basis reconstitution effort identified that surveillance requirements were not being applied to steam exclusion check dampers.

This LER is closed based on the discussion in paragraph 7.c.

-

g.

1 Closed) lER ES2/92012. Revision 1: Auto-start of-01 Diesel Generator due to failure to use operating procedure.

This LER revision added a word that was missing from the original LER.

The corrective action was unchanged.

This LER is-closed-

l J

._ __ _ _ _ _ _ _.- _ _ _. _ _ _ _ _, _

___

.

!

l

.

based on the discussion of the original LER in inspection Report

50-282/92021; 50-306/90021.

!

h.

10pfn) LER 281]J1015: Auto-start of both diesel cooling water pumps due to error in modification procedure.

,

On November 5, 1992, modification work was being performed on the

Unit I control room f panel.

Instrumentation was being removed

.

from the old f panel in preparation for installation of a new

!

panel.

Leads were being disconnected from the circulating / cooling water intake bay level-indicator circuit.

Disconnection of one of two leads resulted in a low intake bay level indication and

-

subsecuent trip of No. 11 motor-driven cooling water pump.

This

caused both diesel-driven cooling water pumps to automatically

start on low cooling water header pressure.

No. 21 motor-driven

cooling water pump was subsequently started and the diesel-driven aumps were returned to standby.

The event was apparently caused

)y inadequate preparation and review of the work package for

>

removing the level indicator from the control room f panel.

The licensee's corrective action for this event, as addressed in the LER, was to emphasize to all engineering and technical staff personnel the need for completeness and accuracy in the generation of modification installation work packages.

The inspectors will evaluate the adequacy of this corrective action in a future inspection.

i.

1[lgid) LER 306/1QQQZ:

Unit 2 reactor trip during startup caused by a failed reactor protection relay.

This event was caused by a failed Westinghouse NBFD relay.

The

.

'

inspectors verified that the licensee replaced the NBfD relays in the reactor protection system with NBfD-NR relays. There have been no additional reactor trips caused by failed relays.

This LER is closed.

J.

1[lpled) LER 306/90.QM: Automatic start of a turbine-driven auxiliary feedwater pump due to personnel oversight in. performing unit shutdown procedure.

On September 10, 1990, Unit 2 was in hot shutdown, in preparation for a refueling outage.

Steam generator level control was being

transferred from the main feedwater (MfW) system to the auxiliary

'

feedwater (AFW)_ system per the normal shutdown procedure.

An-

automatic start of the turbine-driven AfW pump; occurred when,

"

during the transfer, the operator failed to change the selector-switch.for the turbine-driven AfW pump from the AUTO to the

_

SilVTDOWN AU10 position prior to taking the last MfW pump out of service.

Once both MfW pumps were out of service a "both MfW pumps tripped" automatic start signal started the turbine-driven AfW pump.

The root cause was operator error in not following the-procedure.

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for corrective action the licensee required all operations personnel to review the LER.

The inspectors verified that this action was completed on March 21, 1991.

A non-cited violation was issued for this event in inspection report 306/90014.

This LER is closed.

k.

(Closed) LER 306/90393: Auto-start of No. 22 Component Cooling Water (CC) pump while switching residual heat removal pumps.

This auto-start was caused by low suction pressure that occurs in certain equipment configurations.

The inspectors verified that procedure changes had been made to prevent auto starts while switching resic'ual heat removal pumps.

This LER is closed.

1.

(Closed) LER 306/90010:

Train "A" of safeguards inadvertently put in test.

This event occurred when the door to the safeguards cabinet was closed. A box of indicating light bulbs was stored on a shelf _ in the cabinet door. The box was high enough so that when the door was closed, the box pushed the test push button.

The inspectors verified that bulbs were no longer stored in the doors and that the licensee had installed permanent signs indicating that storage in the doors was not allowed.

This LER is closed, m.

10.lned) LER 306/90911:

Both auxiliary feedwater pumps (AFWP) put in shutdown auto for AMSAC test.

While performing.preoperational testing.of the Anticipated Transient Without Scram Mitigating System Actuating Circuitry (AMSAC), the licensee placed both AFWP control switches in the

" shutdown auto" position to prevent unnecessary starts of the AFWPs during the AMSAC test.

This action was required by the preoperational test procedure and was recognized _ as placing Unit 2 in Technical Specification (TS) 3.0.C. because both AFWPs were considered inoperable. TS 3.0.C. allows the licensee one hour to correct a degraded condition not allowed by other provisions of the TS and intentional entry into TS 3.0.C. should be avoided--

without prior notification of the NRC.. Although both AfWPs 'were considered inoperable while the control switches were in shutdown auto, both AFWPs were capable of responding to three of the five_-

automatic start signals. 1he unit was at.three percent power

-

during the testing. The inspectors reviewed a memorandum written by the General Superintendent _of Plant Operations - The.-

memorandum, which stated the requirements for intentional entry-into 15 3.0.C., was sent_to all shift managers and all members.of-the onsite review committee.

This corrective action has been effective in preventing intentional entries into T_S 3.0.C.

A conservati'a interpretation of TS Table 3.5-3 Item 3.c also contributed.

this eve-t, This item lists an action, " hot shutdown," it the-AFWP control switches are in. shutdown auto

i

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.

(taking the main feedwater pump trip start out of service).

No timetable is specified for accomplishing this action.

Since no timetable was specified, the licensee entered 3.0.C.

The licensee i

prepared a Technical Specification Interpretation (TSI) which established a timetable for placing the unit in hot shutdown.

The i

,

licensee also submitted t. TS amendment request to include a

)

'

timetable in the TS.

The inspectors reviewed the TSI.

These

'l corrective actions will climinate the need to enter TS 3.0.C. for.

maintenance and test activities similar to the AMSAC test.

This LER is closed.

n.

10 pen) LER 306/92002 and LER 306/92002. RevisigLl:

Interruption of one train of residual heat removal during a Unit 2 reactor.

coolant system draining operation.

There were numerous licensee corrective actions for this event, including modification of the reactor coolant system-(RCS) to-

minimize the possibility of excessive draining of the RCS.

The

-

inspectors observed work associated with this modification on Unit

'

1.

The modification of Unit 2-is planned for the October 1993 Unit 2 refueling outage. A more tiorough review of this modification is included in Inspection Reports No. 50-282/92020(DRS); 50-306/92020(DRS).

The inspectors will continue to review the licensee's corrective actions in future inspections.

l f d,q1tLLLR 282/92009:

Inadequate testing ~of 4KV safeguards bus

d o.

au.omatic source breaker trip feature identified during operating

'

experience assessment.

This LER is closed based on the discussion in paragraph 7.b.

l No violations, deviations, unresolved or inspection followup items were identified.

9.

Re.gional Initiatives a.

Ventilation System Filter Heaters The inspectors discussed with the licensee an event identified'at

-

the Kewaunee Nuclear Plant involving a plant condition outside the design basis. The licensee for the Kewaunee plant identified two.-

shield building ventilation filter. heater temperature switches

,

.'

that de-energized at a temperature below the design setpoint.

These temperature switches had not been calibrated.

The purpose of the temperature switches'is.to turn-off its associated filter-heater. The heater dries the. incoming air stream to enhance.

.

-

charcoal filter efficiency.

The inspectors questioned the _

.

'

licensee regarding the calibration of filter heater temperature switches contained in various plant ventilation systems.

.

The licensee identified eight safeguards ventilation systems that-contained filter heaters with automatic thermal cutout (ATC0)

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switches.

Switches in the Auxiliary Building Special Ventilation f

System, Spent Fuel Pool Special Ventilation System and the Containment inservice Purge Subsystem have not been calibrated since initial startup.

Switches in the Shield Building

.

Ventilation System had not been calibrated since 1975.- The licensee initiated work requests to calibrate all of the ATC0

.

t switches.

The required setpoint for these switches is 164 degrees Fahrenheit (F). The as found setpoints for seven of the eight

-

A100 switches were within required tolerances.

The as found

setpoint for one switch was 154 degrees F.

The licensee performed a calculation to demonstrate that the associated filter heater would perform its intended function.

Based on this calculation and the as found condition of the other seven ATCO switches, the

licensee concluded that the associated filter heaters were operable.

The inspectors reviewed the results of the itcensee's operability determination and concluded that it was adequate,

,

.0n e Offload Canability Survey b.

In response to a request from the regional office, the inspectors completed a survey to ascertain the licensee's core offload capability.

The inspectors consulted with the licensee's nuclear engineering staff to complete the survey.

The Prairie Island spent fuel storage pool consists of two-l interconnected pools containing 1386 storage-locations.

There is

'

space available in. pool No.1 to insert four additional temporary

,

storage racks to increase the total number of storage locations to 1582; however, this area is the designated storage cask laydown area and must be clear to accommodate loading of spent fuel storage casks.

A full core offload consists.of 121 fuel assemblies.

Currently, there are 119 available storage locations in the pool for spent fuel.

There are some currently empty storage locations which are inaccessible for fuel storage but which could be used to store some of the non-fuel components currently stored in fuel-accessible locations.

Therefero, if two storage locations are made available for fuel assemblies by removing the non-fuel components that are stored in them, a full core offload is-possible without using the temporary' storage racks.

'

The 10 year inservice inspection of Unit 2 is_ scheduled to occur during the October 1993 rafueling outage and will require that the

core be off-loaded.

This will be possible if components in the-pool are shuffled as discussed above. A consequence of refueling,-

>

however, will be the discharge of approxirrately 48 spent fuel

assemblies. At that time, a' full. core offload will not be possible unless the temporary storage racks are used or storage

,

cask loading has commenced as part of the licensee's planned r

independent spent fuel storage installation.

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Cold Weather Prepr ations (71714)

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In conjunction with the requirements of NRC Inspection Procedure 71714,

.

" Cold Weather Preparations," the inspector reviewed the licensee's j

periodic test arocedure (TP) 1637, " Winter Plant Operation," Revision 13

,

and verified tlat it had been comp'leted.

The inspector also toured the i

plant during cold weather to determine the adequacy of the licensee's

,

program.

Tours of the turbine building, auxiliary building, radioactive

!

i waste buildings, and screenhouse revealed temperatures well above

'

freezing with safety-related fluid systems properly heat traced or contained within heated structures.

No violations, deviations, unresolved, or inspection followup items were identified.

.

11.

Mntal_nment Safenuards_ Sump Inspection (717101 l

During tours of Unit 1 and Unit 2 containment buildings -the inspectors i

examined the safeguards sumps to ensure that they were free of debris and that trash screens were in place prior to plant restart.

During the

>

inspection, Unit 1 Sump B was free of debris, but the trash screen was open to f acilitate local leak rate testing of RHR suction isolation valves.

Unit 2 Sump B was free of debris and the trash screen was in

place.

However, the inspectors noted that lock bolts for the trash screens were not installed.

The inspectors informed the licensee of this condition, and the licensee stated that during its final

'

containment closure inspection, the sumps would be verified to be free of debris and the trash screens secured in place.

The inspectors i

verified that the trash screens were properly secured during the containment closure _ inspection.

No violations, deviations, unresolved, or inspection followup items were_

_

'

identified.

12.

.information Meg.tinns with local Officialt_(94600)

On August 10, 1992, the Minnesota-Public Utilities Commission (MPUC)

issued a certificate of need for the installation of 17 spent fuel storage casks at the Prairie Island site.

The licensee expects that various groups opposed to the dry cask storage will attempt to have-i legislation introduced in January 1993 to overturn the MPUC decision.

On December 9,1992, approximately 25 metnbers of the Minnesota state

'

legislature visited the Prairie Island site.

The legislators were L

accompanied by representatives from various groups opposed to the dry cask storage, specifically, the Prairie Island Sioux Indian Tribal

'

Council, the Prairie' Island Coalition Against Nuclear Storage, and

-

l Direct Expressions (a marketing and public relations firm).

The NRC

>

Senior Resident inspector attended a brief orientation session where.he was introduced to the group.

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13.

Management Meetina (307021 On December 18, 1992, a meeting between selected licensee and NRC management was conducted in the NRC Region 111 Office, at the licensee's

'

recuest, to discuss organizational changes at both the Prairie Island anc Monticello sites and within the corporate staff.

The licensee

stated that its reorganization is intended to accomplish several goals,

!

These include providing an organization that supports plant operations,

reduces labor costs, eliminates duplicate functions, increases i

empowerment through fewer management positions, increases self-

sufficiency within departments, reduces layers of management, and centralizes construction and engineering functions.

The licensee also discussed resource sharing within its own organization and between other utilities. A copy of the handouts the licensee provided at the meeting is provided as an attachment.

-

i 14.

Safety Audit Committee Meetina (405001 The inspectors attended portions of the licensee's safety Audit

Committee (SAC) meeting on December 4, 1992.

The SAC is the licensee's offsite safety review committee and meets quarterly to discuss plant conditions, events, and items of interest. During this meeting, the

inspectors observed discussions on the Error Reduction Task Force, a

.

pilot effort regarriing site adverse trends analyses, and a status report

,

on the Prairie Island Individual Plant Examination project. -

i The inspectors noted a free flow of information between all parties and e

that the meeting was conducted in a professional manner.

'

No violations, deviations, unresolved, or inspection followup items were identified.

15.

Ba1Agement Interview (71707)

._

,

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The inspectors met with the licensee representatives denoted in paragraph 16 after the conclusion of the report period on January 7, 1993.

The inspectors discussed the purpose and scope of the

!

inspection and the findings.

The inspectors also discussed the likely

information content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.

The licensec did not identify any documents _or processes as proprietary.

,

L 16.

P_ersons Contacted

'

L E. Watzl, General Manager, Prairie Island M. Sellman, P1 ant Manager

_

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K. Albrecht, General Superintendent, Engineering

-

M. Wadley, General Superintendent,.0perations l

G, Lenertz, General Superintendent,. Maintenance l-R. Lindsey, Assistant to the Plant Manager

T. Breene, Superintendent, Nuclear Engineering

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J. Sorenson, Operations Shift Manager i

G. Miller, Superintendent Technical Support l

R. pearson, Superintendent, steam Generator Systems i

M. Reddemann, General Superintendent, Electrical and Instrumentation Systems

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G Rolfson, General Superintendent, Nuclear Projects. Depart. ment

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J. Mcdonald, Superintendent, Site Quality Assurance

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J. Mill, Superintendent, Instrumentation and Controls l

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G. Aandahl, Superintendent, Design Standards

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M. Brossart, Nuclear Engineer

T. Parker, Director, Nuclear Licensing

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E. Eckholt, Nuclear Support Services

J. Leveille. Nuclear Support Services

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M. Dapas, NRC Senior Resident' inspector i

L. Marsh, NRC NRR Project Directorate, 111-1

-

M. Gamberoni. NRC NRR Project Manager

D. Kosloff, NRC Resident inspector

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'iDenotes those present at the management interview of January 7, 1993.

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Quai:y Assurance lesconsiai i:ies 03erational Qua ity Assurance P an (OQA.3)

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Qua ity Control 3rogram

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m Quai":y Assurance

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3as: Organiza": ion

- Qua ity Control (QC) Re3ortec to Site Director

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- QA 9eaortec to Executive V? of 3ower Su a aly, Not 17e N uclear V 3

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Quali~:y Assurance nteg ration Com.oine Quality Functions into One Groua

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m arove N S 3's Sel"-Assessment Ca3a ai ities

-

Improve 03erating E=iciency o"t7e Quality

-

Grou a A

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Quai:y Assurance S:ra:ecy Aucit, Surveillance, anc QC 3rograms

-

Wi' 3e Generatec anc Imalementec By One De3artment Aucit, Surveil ance anc QC 9esu.ts Will 3e Assessec anc Eva;uatec '3y One De3artment

~~1e Quaity Groua Reaorting C7ange

-

Gives Direct Access to N uc ear V?

anc t7e V3's Jeaartment'-eacs

.

Qua L:y Assurance EXDeC~:R: ions 3etter Cost Control Easier Quaity Resource S7aring 3etween

-

Sites 9es 3onsiai ity anc : Accountaaility Given

-

To De3artments Best A' le to Aclieve a

9esu ts

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---

..

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t

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Quai:y Assurance Summary

-

QA's Ro.e Has Ex3ancec

,

.

-

Sef-Assessment Ca3aailities anc Cost E=ectiveness Shou c m arove

,

.

J i

.

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\\SP's =u:ure ni":iatives

,

.

3rocess Re-Engineering

-

lesource S 7aring

-

- Witlin NSP

- With Otler Utilities

.

~ '3roactive legulatory Inter" ace

-

Regulatory issues Process e

.

f ai

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-

-.,

_.

. _, _,

,

.. -..

.

.. _.

v t e Inspection Report - Prairie Island - 1992029
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 \|
1992 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 28(0) 10(0) 20(0) 21(0) 22(0) 24(0) 25(0) 26(0) 27(0) 28(0) 29(0) 30(0) 31(0) 32(0) Security 201(0) Operator Exams Emergency Planning Other

IR 05000282/1992029

Text

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