Text

Insp Rept 50-341/93-04 on 930119-0309.Violations Noted. Major Areas Inspected:Operational Safety Verification,Onsite Event Followup,Current Matl Condition,Housekeeping & Plant Cleanliness of Backlog & Radiological Controls
	ML20035A612
Person / Time
Site:	Fermi
Issue date:	03/16/1993
From:	Phillips M; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:	;
Shared Package
ML20035A603	List: ML20035A602; ML20035A610; ML20035A612;
References
	50-341-93-04, 50-341-93-4, NUDOCS 9303290080
	Download: ML20035A612 (79)
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U.S. NUCLEAR REGULATORY COMMISSION

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REGION III

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Report No. 50-341/93004 (DRP)

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Docket No. 50-341-

License No. NPF-43

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Licensee: Detroit Edison Company

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2000 Second Avenue

Detroit, MI 48226

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Facility Name:

Fermi 2

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Inspection At:

Fermi Site, Newport, Michigan

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Inspection Conducted: January 19 through March 9, 1993

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Inspectors:

W. J. Kropp

K. Riemer

R.

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Approved B .

M. P. Phillips, Chief

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Reactor Projects Section 2B

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Inspection Summary

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Inspection from January 19 throuah March 9.1993

(Report No. 50341/93034 (DRP))

Areas Inspected:

Routine, unannounced safety inspection by the resident

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inspectors of action on previous inspection findings; operational safety

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verification; onsite event followup; current material condition; housekeeping

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and plant cleanliness; radiological controls; security; LERs; maintenance

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activities; assessment of backlog; surveillance activities; High Pressure

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Coolant Injection drain pot isolation valves; reliability of High Pressure

Coolant Injection; Information Notices; degraded control amplifier; RWCU check

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valve failure; and report review.

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Results:

Within the fourteen areas inspected, one violation that pertained

to untimely notification of an ESF actuation (paragraph 3.b.) and one non-

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cited violation were identified.

Four Unresolved items were identified that

pertained to independent verifications (paragraph 3.a), lifting of' leads

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(paragraph 5.a), the reliability of HPCI (paragraph 6.b), and the licensee's

review of Information Notices (paragraph 6.c).

In addition, one inspection

followup item was identified that pertained to the work authorization process

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(paragraph 5.a).

The following is a summary of the licensee's perfor ance

during this inspection period:

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Plant Operations

The licensee's performance in this area was good. The operators' response to

a degraded flow amplifier was excellent.

The operators' response to the plant

shutdown on February 10 and the plant trip on February 19 was good. However,

operators did not adequately isolate three _ control rod drive hydraulic control-

units prior to manually shutting down the reactor which resulted in an

uncontaminated spill of approximately 50 gallons to the Reactor Building

floor. Problems were also noted with independent verifications during the

implementation of an abnormal lineup sheet (ALS). Overall, material condition

of the plant was good. Material conditions of the control room ventilation

(Divisions I and II) systems, station batteries, and Division II 4160 KV

switchgear rooms were excellent. However, the material condition of CTG 11-1

was not commensurate with other areas of the plant.

Maintenance and Surveillance

During this inspection period, the licensee's performance in this area was

mixed. The team work exhibited between maintenance, operations, radiation

protection, engineering and other licensee organizations during the

maintenance outage to repair a condenser tube leak and in response to the

degraded HPCI controller was excellent. However, concerns were identified

with work planning for other maintenance activities.

In addition, errors in

the performance of routine maintenance activities on the circulating water

system resulted in a plant trip.

Enaineerina and Technical Support

The licensee's performance in this area was excellent.

The onsite reviews

conducted for assessment of the unit restart after a maintenance outage and

for the scram on February 19, 1993, were thorough. Also, the system engineer

and Inservice Inspection and Testing Group's decision to place a Reactor Water

Cleanup check valve on an increased testing frequency was conservative.

Safety Assessment /Ouality Verification

Overall, the licensee's performance in this area was mixed.

Five of the

licensee event reports (LER) were reviewed without any problems noted.

However, concerns were identified with the licensee's review of two

information Notices.

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DETAILS

1.

Persons Contacted

Detroit Edison Company

D. Bergmooser, Technical Engineering

J. Conen, Senior Engineer, Plant Safety

R. Eberhardt, Superintendent, Radiation Protection

- P. Fessler, Director, Technical Manager

- D. Gipson, Vice President, Nuclear Operations

J. Green, Superintendent, ISC

L. Goans,' Nuclear Security

E. Hare, Senior Compliance Engineer, Licensing

R. Henson, Operations

K. Howard, Mechanical and Civil Engineering, Supervisor

J. Korte, Director, Nuclear Security

A. Kowalczuk, Maintenance Superintendent

R. Mathews, Maintenance

- R. McKeon, Plant Manager, Nuclear Production

- W. Miller, Director, Nuclear Licensing

R. Newkirk, Supervisor, Licensing

D. Ockerman, Nuclear Training

W. Orser, Senior Vice President, Nuclear Operations

J. Plona, Superintendent, Operations

D. Roe, Production Quality Assurance

- R Russell, Outage Manager

L. Schuerman, Plant Engineering

A. Settles, Nuclear Licensing

- R. Stafford, Nuclear Assurance Manager

F. Svetkovich, Superintendent, Radwaste

R. Szkotnicki, Supervisor, Production Quality Assurance

- J. Tibai, Compliance, Licensing

W. Tucker, Superintendent, Technical Engineering

Nuclear Reaulatory Commission

E. Greenman, Director, Division of Reactor Projects

- W. Kropp, Senior Resident Inspector, Fermi

T. Martin, Director, Division of Reactor Safety

M. Phillips, Section Chief, Section 2B

- K. Riemer, Resident Inspector, Fermi

R. Twigg, Reactor Engineer

Denotes those attending the exit interview conducted on March 9, 1993.

Denotes those attending the management meeting held March 8, 1993.

The inspectors also had discussions with other licensee employees,

including members of the technical and engineering staffs, reactor and-

auxiliary operators, shift supervisors, electrical, mechanical and

instrument maintenance personnel, and contract security personnel.

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2.

Action on Previous inspection Findinos (92701)

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a.

(Closed) Inspection Followuo Item (341/92021-02(DRP)):

Licensee's

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investigation of the overflow of a phase separator tank in the

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Reactor Water Cleanup System. The inspectors reviewed the

licensee's Human Performance Enhancement System (HPES) Report

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92010.

The HPES report identified several corrective actions

that, upon effective implementation, should preclude similar

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overflows. The corrective actions included giving special

consideration to any major evolutions during shift turnover;

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revising alarm response procedures; revising operating procedures

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to recommend continuous communications between plant personnel

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involved in backwashing a RWCU demineralizer and taking

appropriate actions to evaluate the G33-F153A valve failure. The

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inspectors considered the HPES to be thorough with no concerns

identified. This matter is considered closed.

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b.

(Closed) Inspection Followup item (341/92017-06(DRP)): The use of

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a minimum battery voltage of 235 volts four hours after the

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initiation of a design base accident to determine the minimum

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voltage seen by valve, E4150-F008. The' inspectors reviewed the

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revised calculation (DC-4943) that used a minimum voltage of

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approximately 227 volts. The inspectors have no further concerns

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and this matter is considered closed.

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c.

(Closed) Open item (341/89201-06(DRP)): Resolution of Human

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Engineering Deficiencies (HED).

The licensee had previously

completed and closed priority I and priority II HEDs.

The

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inspectors ascertained through interviews with licensee personnel,

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reviews of licensee records and documentation, and selective

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examinations of HED closure files that all priority III HEDs have

now been completed. The inspectors have no further concerns in

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this area. This item is considered closed.

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d.

(Closed) Open item (341/90013-08(DRP)):

Design modification to

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enhance the use of HPCI and RCIC for reactor pressure control.

The licensee has initiated an Engineering Design Package (EDP

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11655) to enhance the HPCI test return valve E41-F0ll. The

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inspector verified, through reviews of licensee paperwork and

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interviews of licensee personnel, that the station intends to

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upsize the motor operator on valve E41-F0ll.

The licensee

informed the inspector that the change will provide sufficient

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thrust to overcome full pump shutoff head differential pressure at

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the valve. The licensee provided the inspector with documentation

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showing the EDP to be in the five year plan. The licensee has

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tentatively scheduled the EDP to be performed during the next

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refueling outage. The inspectors have no further concerns in this

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area.

This item is considered closed,

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3.

Plant Operations

Fermi 2 operated at power levels up to 98 percent until February 10,

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1993, when the unit was shut down to repair a condenser tube leak. The

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condenser tube leak resulted in chlorides greater than .2 ppm and

conductivity greater than 1.0 micrombos per centimeter. The leaking

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condenser tube was plugged and the unit was returned to service on

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February 13, 1993, at.7:10 p.m. (EST). The unit operated at power

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levels up to 98 percent until February 19, 1993, when a turbine

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trip / reactor trip occurred due to high condenser pressure. The results

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of the licensee's post reactor trip investigation are documented in

paragraph 3.b of this report.

The unit was returned to service at

4:46 a.m. on February 21, 1993, and has operated at power levels up to

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98 percent.

a.

Doerational Safety Verification

(71707)

The inspectors verified that the facility was being operated in

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conformance with the license and regulatory requirements, and that

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the licensee's management control system was effective in ensuring

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safe operation of the plant.

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On a sampling basis, the inspectors verified proper control room

staffing and coordination of plant activities; verified operator

adherence with procedures and technical specifications; monitored

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control room indications for abnormalities; verified that

electrical power was available; and observed the frequency of

plant and control room visits by station management.

The

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inspectors reviewed applicable logs and conducted discussions with

control room operators throughout the inspection period.

The

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inspectors observed a number of control room shift turnovers.

The

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turnovers were conducted in a professional manner and included log

reviews, panel walkdowns, discussions of maintenance and

surveillance activities in progress or planned, and associated LCO

time restraints, as applicable. The inspectors had the following

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observations:

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On January 27, an operator performing outside rounds

discovered that the air compressor control switch for

Emergency Diesel Generator (EDG) 13 was in the "off" (vice

" auto") position.

The air compressor keeps the EDG starting

system air receivers charged to the required Technical

Specifications (TS) pressure of greater than or equal to 215

psig.

When the Nuclear Power Plant Operator (NPP0)

discovered the compressor switch in the "off" position with

air receiver pressure at 205 psig, he notified the control

room of the situation and the control room operators

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declared EDG-13 inoperable. The NPPO placed the air

compressor in service by placing the control switch in auto.

Air receiver pressure returned to the required TS level

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within approximately seven minutes.

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The low air receiver pressure alarm was not received in the

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control room due because the alarm setpoint is 195 psig (20

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psig lower than the TS required pressure). The licensee had

addressed this issue in the past, and stated that the

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purpose of the alarm was to alert operators of a

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catastrophic failure in the EDG air system and not a slow

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degradation. The EDG air receiver pressure has been

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verified to be above IS limits on every shift by NPP0s.

The

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shiftily check of the EDG air receiver pressure was to

identify a slow degradation of air pressure similar to the

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air compressor being "off."

The inspectors could not

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identify any regulatory requirement to require the EDG low

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air pressure alarm to actuate above the TS limit. The

inspectors have no further concerns with the alarm setpoint.

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The licensee determined that the switch was inadvertently

bumped to the "off" position by a plant cleaner who was

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working in the area at the time. A deviation event report

(DER) was written to address this situation.

During the controlled shutdown on February 10, the

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operations department isolated and tagged out three control

rod hydraulic control units (HCU) in accordance with a-

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reactor engineering standing order.

Per the abnormal

lineup sheet (ALS), the accumulator drain valves were left

open. As a result, the manual reactor scram established a

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vent path from the control rod drive (CRD) cooling line to

the reactor building. Approximately 50 gallons of water

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were lost from the CRD system and spilled to the Reactor

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Building floor. Radiation protection personnel determined

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that the water was not contaminated.

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During the inspector's subsequent investigation of the

event, a review of the ALS used for the evolution determined

that the independent verificatior (IV) was performed almost

four hours after the event occurred.

The inspectors

questioned the adequacy of performing IVs after the

performance of an evolution that initiates the ALS. This is

considered an Unresolved Item pending further review by the

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Resident Inspectors (341/93004-01(DRP)).

On February 17, 1993, during a panel walkdown in the main

control room, the Nuclear Shift Supervisor (NSS) observed

that the High Pressure Coolant Injection System Controller

was at approximately 93 percent demand rather than 100

percent demand. The licensee took immediate steps to assess

operability of HPCI which is discussed in paragraph 6.b of

this report. The inspectors considered the NSS observation

of the status of the HPCI controller during a panel walkdown

as excellent. Also, the inspectors considered the station's

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response to the degraded HPCI controller to be excellent as

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evidenced by the teamwork between operations, maintenance,.

and engineering.

b.

Onsite Event Follow-up (93702)

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During the inspection period, the licensee experienced several

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events, some of which required prompt notification of the NRC

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pursuant to 10 CFR 50.72.

The inspectors pursued the events

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onsite with licensee and/or other NRC officials.

In each case,

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the inspectors verified that any required notification was correct

and timely.

The inspectors also verified that the licensee

initiated prompt and appropriate actions.

The specific events

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were as follows.

On January 6, 1993, while performing modifications-on the

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plant simulator, technicians encountered problems during the

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installation of a pressure recorder (" Division 2 Drywell and

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Torus Pressure"). The technicians determined that the

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recorder did not meet the purchase order description for

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simulator application.

Subsequent investigation by the

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licensee found that the recorder intended for the simulator

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had been installed in the main control room on September 25,

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1992, during the third refuel outage. The recorder intended

for the simulator was removed from the main control room and

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a proper recorder was installed on January 7,1993. The

licensee also found that the installed main control ronm

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Division I recorder had an internal label identifying it as

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the Division 2 recorder. The licensee changed engineering

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documents to reflect the correct serial number for both

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recorders and new nameplates were ordered.

The licensee's engineering analysis concluded that although

the simulator recorder installed in the main control room

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was functional, it could not be seismically qualified

through analytical methods.

Thus, on January 19, 1993, it

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was concluded that the recorder could not be considered

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operable when the plant entered Mode 2 (startup) following

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the third refuel outage on November 4, 1992.

This recorder

is required to be operable per Technical Specification 3.3.7.5 in Modes 1 and 2 (power operation and startup).

Had

a seismic event occurred, it is assumed that this recorder

would have failed.

(There were no seismic events near the

site during the time period that the non-qualified recorder

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was installed). There are no automatic actions that are

initiated by this recorder.

Data provided by the recorder

is utilized by operators when implementing portions of the

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Emergency Operating Procedures.

The recorder installed in

Division 1, which monitors the same parameters, was

seismically qualified and available.

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The recorder was inoperable for greater than seven days and

a violation of Technical Specification 3.3.7.5 occurred. The

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safety significance of the violation was minimal in that

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there was no seismic event during this time, and the

recorder in the other division was operable. The licensee

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instituted a comprehensive set of corrective actions that

the inspectors believe will adequately address the root

cause of the event. The corrective actions performed by the

licensee included the following:

verified that other

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recorders replaced in the main control room during refueling

outages (RFOs) 2 and 3 were the correct type; updated and

revised procedures to purchase items, to control material

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for EDPs, to perform receipt inspections, and to verify work

in the field; committed to discussing the event and lessons

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learned during the upcoming training cycles; and committed

to having the QA department review several QA level 1

installations performed by the modification group during the

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third refuel outage.

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Since inspector review determined the situation was of

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minimal safety significance, and in reviewing 10 CFR 2,

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Appendix C, the criteria specified in Section VII.B.1 of the

Enforcement Policy was met to allow exercising of

enforcement discretion, a Notice of Violation will not be

issued on this matter.

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On January 22, the number 3 High Pressure Turbine Control

Valve failed closed. Operators received an APRM upscale

alarm (power rose from 98 percent to approximately 107

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percent) and the bypass valves momentarily opened.

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operators commenced a power reduction to 90 percent power by

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reducing recirculation flow. A loss of the heater drains

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system occurred because of the power reduction which in turn

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caused a runback of the reactor recirculation pumps.

Power

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decreased to approximately 69 percent and core flow

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decreased to approximately 50 percent.

The operators

verified that the reactor did not operate in the instability

region and monitored the reactor for power oscillations.

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The cause of the valve failure was determined to be a loss

of oil from the associated unitized actuator (UA).

The

mounting clamp for the oil accumulator had broken and the UA

manifold mounting bolts had sheared.

Oil escaped from the

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resulting gap between the accumulator mounting block and the

manifold. The licensee's failure analysis indicated that

the bolts failed due to high cycle fatigue.

During the licensee's walkdown of the unitized actuator

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room, it was discovered that the mounting clamps on two

other turbine control valves were also broken.

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licensee's immediate corrective action included replacing

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the broken accumulator mounting straps, verifying the proper

torque on the manifold mounting bolts and performing

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shiftily checks of the unitized actuators.

Further licensee

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investigation determined that the Number 3 HP Turbine

Control Valve UA was one of seven replaced during the last

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refuel outage. The Number 3 UA was also one-of four that

was sent offsite to be reworked. The licensee's long term

corrective actions included replacing the mounting straps

with a sturdier design and inspecting the remaining mounting

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bolts.

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On February 10, 1993, the unit was shut down to repair a

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condenser tube leak. The leak resulted in elevated chloride

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levels and conductivity.

The leaking condenser tube was

located in the southeast quadrant of the condenser along the

condense- wall.

The leaking tube was plugged along with

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other tubes in the area along the condenser wall as a

precautionary measure by the licensee.

The licensee also

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inspected the steam side of the condenser for any debris

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that could have caused the tube leak.

No anomalies were

identified.

The unit was returned to service on February

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13, 1993.

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On February 19, 1993, at 9:02 p.m. (EST), a reactor trip

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occurred when the turbine tripped due to high condenser

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pressure. The high condenser pressure resulted from the

loss of two of four circulating water pumps during routine

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preventive maintenance activities.

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Prior to the event, Circulating Water (CW) Pump No. 3 had

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been taken out of service to perform a functional check of a

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relay in the 4160 kV breaker cubicle associated with that

pump.

The 4160 kV breaker was located on Bus 69J that

supplied power to CW pumps Hos. 1, 2, and 3 and to the motor

control center for their associated discharge valves. The

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electrician performing the routine preventive maintenance

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placed test equipment across the wrong relay which caused

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the feeder breaker to Bus 69J to trip. As a result, power

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was lost to CW pumps Nos. I and 2 and their respective

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discharge valves. With the loss of power, the discharge

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valves stayed open allowing flow from the operating CW pumps

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(Nos. 4 and 5) to be diverted through the now idle CW pumps

1 and #2. The resultant decrease in circulating water flow

to the condenser allowed condenser pressure to increase to

the turbine trip / reactor trip setpoint. All safety related

equipment functioned as required.

However, the 4160 kV

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breaker for the No. 2 CW pump did not trip as expected on

undervoltage when the Bus 69J feeder breaker tripped. As a

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result, the permissive logic to allow the closure of the

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alternate feeder breaker to Bus 69J could not be met.

The

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licensee's investigation identified that the undervoltage

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relays associated with Bus 69J were damaged as a result

of the event. The relays were replaced and the licensee

commenced a reactor start up at 5:43 p.m. (EST),

February 20, 1993. The unit was synchronized to the grid

at 4:46 a.m. (EST) on February 21, 1993.

On February 25,1993, at 4:58 p.m. (EST), valve T49F468,

Drywell Pneumatic Primary Containment Outboard Isolation

valve, closed. During a shiftily inspection, circuit 31

power indicating light on panel Hil-P870 was found

extinguished. During replacement of the light bulb, the

bulb lens f ailed and resulted in an electrical short. Two

fuses blew, one of which resulted in a loss of power to the

solenoid for valve T49F468. The licensee concluded that no

ESF actuation had occurred since no ESF logic was actuated

Therefore, the event was not deemed reportable per the

requirements of 10 CFR 50.72 (b)(2)(ii). The inspectors

reviewed the event and determined that the fuse blowing

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caused an ESF actuation. Also, Chapter 6 of the Updated

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Final Safety Analysis identified valve T49F468 as an ESF

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valva. After discussions with the resident staff and Region

111 management, the licensee notified the NRC in accordance

with the requirements of 10 CFR 50.72 (b)(2)(ii). The

notification to the NRC was made on February 26 at

4:37 p.m. (EST).

The failure to notify the NRC of an ESF

actuation within four hours is considered a violation of

10 CFR 50.72 (b)(2)(ii) (341/93004-02(DRP)).

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c.

Current Material Condition (71707)

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The inspectors performed general plant as well as selected system

and component walkdowns to assess the general and specific

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material condition of the plant, to verify that work requests had

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been initiated for identified equipment problems, and to evaluate

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housekeeping. Walkdowns included an assessment of the buildings,

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components, and systems for proper identification and tagging,

accessibility, fire and security door integrity, scaffolding,

radiological controls, and any unusual conditions.

Unusual

conditions included but were not limited to water, oil, or other

liquids on the floor or equipment; indications of leakage through

ceiling, walls or floors; loose insulation; corrosion; excessive

noise; unusual temperatures; and abnormal ventilation and

lighting.

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During the inspection period, the inspectors performed walkdowns

of several plant areas with plant management. The areas included

the Control Room Ventilation (CRV) (Divisions I and II), Station-

Batteries (Divisions I and II), Division 11 4160 KV Switchgear and

Combustion Gas Turbine (CGT) 11-1.

Overall, the material

conditions of the CRV systems, station batteries and the Division

II 4160 KV switchgear rooms appeared to be excellent based on the

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walkdowns. However, the material condition of CTG-ll-1 was not

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commensurate with other areas of the plant. No significant

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concerns were identified, but several deficiencies were

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identified. These deficiencies included several burnt out breaker

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indicator lights and one defective breaker position light socket

for breaker 88 MG. Also, several lights were noted as missing in

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CTG 11-1 cubicles. The licensee took appropriate action to

correct the deficiencies,

d.

Housekeepino and Plant Cleanliness

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The inspectors monitored the status of housekeeping and plant

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cleanliness for fire protection and protection of safety-related

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equipment from intrusion of foreign matter._ Overall, the

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housekeeping in most areas of the plant toured by the inspectors

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was excellent, However, the housekeeping in the CTG 11-1 area was

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considered satisfactory and requires increased management

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attention.

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e.

Radioloaical Controls (71707)

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The inspectors verified that personnel were following health

physics procedures for dosimetry, protective clothing, frisking,

posting, etc., and randomly examined radiation protection

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instrumentation for use, operability, and calibration.

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f.

Security

(71707)

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Each week during routine activities or tours, the inspectors

monitored the licensee's security program to ensure that observed

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actions were Laing implemented according to the approved security

plan. The inspectors noted that persons within the protected area

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displayed proper photo-identification badges, and those

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individuals requiring escorts were properly escorted.

Additionally, the inspectors also observed that personnel and

packages entering the protected area were searched by appropriate

equipment or by hand.

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One violation was identified.

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4.

Safety Assessment /0uality Verification (40500 and 92700)

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a.

Licensee Event Renort (LER) Follow-un (92700)

Through direct observations, discussions with licensee personnel,

and review of records, the following event reports were reviewed

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to determine that reportability requirements were fulfilled, that

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immediate corrective action was accomplished, and that corrective

action to prevent recurrence had been or would be accomplished in

accordance with Technical Specifications (TS):

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(Closed) LER (341/91003) Supplement 1:

Flow switches for the Exo-

Sensor Hydrogen /0xygen Monitoring System could contain Teflon lead

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wire insulation rather than Tefzel lead wire insulation. Teflon

was not qualified for the postulated radiation environment

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encountered following a design basis loss of coolant accident.

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Inspection by the licensee determined that Division II of the

Primary Containment Atmosphere Monitoring System (PCAMS) had flow

switches with the Teflon lead wire insulators. To repair the

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affected flow switch a Raychem heat shrink sleeving was applied

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over the Teflon insulated lead wires.

However, during the review

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of draft LER 91-003, a question was raised whether the heat shrink

I

sleeving of the wire insulation was applied completely up to the

!

reed switch. The repaired switch was subsequently replaced'and

j

inspected. The inspection determined that the heat shrink had not

l

been applied to the lead wires up to the reed switch located under

'

the flow switch cover. The root cause for not applying the heat

shrink up to the reed switch was identified as inadequate work

j

instructions. The inspectors reviewed the licensee's corrective

actions with no concerns identified.

This LER is considered

!

closed.

(Closed) LER (341/91005) Supplement 1:

Of the 233 valves tested,

27 including three main steam isolation valves (MSIV) exceeded the

l

administrative allowable leakage rates and the combined leakage

i

exceeded the limits of the Technical Specifications.

The

l

s

containment isolation valves that exceeded the individual

,

administrative allowable leakage rates were repaired or reworked.

!

.These valves were subsequently retested.

In addition, the three

l

-

MISIVs that failed LLRTs were successfully modified using the

l

,

manufacturers' latest design modification. The inspectors

l

,

considered this LER closed.

l

(Closed) LER (341/93001): .High pressure coolant injection (HPCI)

inoperable due to failed relay.

The normally energized "HPCI

l

a

"

turbine exhaust valve open" relay was found deenergized. The root

cause of the failure of the relay has been preliminarily

identified as continuous operation and long service of a crimped

!

connection between the single-strand coil wire and multi-strand

{

6

!

lead wire.

A contributing cause was the omission of the relay

j

from the Agastat PM program, which would have ensured chsge out

'

.

!

of this relay prior to failure.

This relay had been incorrectly

l

identified as normally deenergized during evaluation for inclusion

i

d

in the original Agastat PM program to implement Information Notice

i

!

(IN) 84-20. The failure of this relay identified in this LER

,

'

j

(open coil lead wire) differed from the mechanism of failure

!

described in IN 84-20. The relay has been placed on the Agastat

PM program (replacement every 4.5 years), and the licensee has

4

included a review of IN 84-20 population of relays to ensure all

safety system Agastat relays have been identified. This LER is

"

considered closed.

l

,

i

12

j

i

. _

,

.

,

.

.,

. - _ .

. -

-

_-

.. . . - .

.

.-

1

'

!

(Closed) LER (341/93002): On January 14, 1993, the high pressure

i

coolant injection (HPCI) failed to start on a simulated auto

injection signal during the performance of surveillance 24.202.01,

l

"HPCI Pump Time Response and Operability Test at 1025 psi."

The

'

cause was identified as a loss of supply voltage to the governor

<

control system due to a failed voltage dropping resistor. The

!

licensee's failure analysis report stated that the resistor showed

[

evidence of overheating which appeared to contribute with time to

r

i

the melting and opening of the resistance wire within the

!

j

resistor. Since the reactor core isolation cooling (RCIC) system

l

was a similar design, the resistor in the RCIC governor control

!

<

'

was checked for integrity. However, to ensure availability, the

!

resistor was replaced during a system outage in February 1993.

I

Also, the licensee has formed a team to review and identify

l

electronic and electrical components that were susceptible to

!

1

thermal aging.

l

i

(Closed) LER (341/93003): Technical Specification required

j

recorder discovered not to be qualified.

The inspectors reviewed

i

,

i

the licensee's corrective actions (reference paragraph 3.b) with

l

'

no concerns identified. This LER is considered closed.

,

.

t

i

In addition to the foregoing, the inspector reviewed the

5

j

licensee's Deviation Event Reports (DER) generated during the

i

inspection period. This was done in an effort to monitor the

l

conditions related to plant or personnel performance, potential

.i

trends, etc.

Deviation Event Reports were also reviewed to ensure.

i

that they were generated appropriately and dispositioned in a

l

'

manner consistent with the applicable procedures.

t

,

f

No violations or deviations were identified.

i

5.

Maintenance / Surveillance (62703 & 61726)

l

t

a.

Maintenance Activities (62703)

[

t

h

Routinely, station maintenance activities were observed and/or

[

i

reviewed to ascertain that they were conducted in accordance with

i

j

approved procedures, regulatory guides and industry codes or

l

standards, and in conformance with technical specifications.

t

.

j

The following items were also considered during this review:

l

j

limiting conditions for operation were met while components or

l

systems were removed from service; approvals were obtained prior

!

'

to initiating the work; functional testing and/or calibrations

'

.

were performed prior to returning components or systems to

!

service; quality control records were maintained; and activities

l

'

were accomplished by qualified personnel.

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t

.

4

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,

-

13

!

,

f

.

-.

-

. - . - .

_

..--

_

-

.

- -

!-

t

,

i

Portions of the following maintenance activities were observed and

reviewed:

000Z923690

Replacement of EPA Breaker

o

P503920611

Rebuild Valves, Check Af ter Filter,

,

Prefilter, 0-Rings and Descant

'

000Z930331

Replace HPCI Pump Discharge Pressure Gauge

Whide witnessing work pertaining to Work Request (WR) 000Z923690,

the inspectors had the following concerns:

The lifting of leads to remove the Electrical Protection

Assembly (EPA) Breaker for reactor protection motor

j

generator set "B" was not performed in accordance with

',

procedure MAI-03. The WR required that determination

(determ) and retermination of leads would be per procedure

l

MAI-03, Attachment 1.

The inspector noted that eight leads

.

were determed and recorded on the Interim Alteration

l

Checklist. When the determ of the leads was independently

.

verified, two leads for the shunt trip were not yet

t

-

determed.

The independent verifier for the first eight

'

leads determed proceeded to determ the two shunt leads.

j

When the inspector reviewed the Interim Alteration Checklist

.

several minutes later, the initials for determing the two

!

shunt leads were not the person who did the determ but

'

t

rather the individual who determed the first eight leads.

The inspectors noted the discrepancy to the individuals

!

involved. The Interim Alteration Checklist was then revised

'

!

to show the correct individual who determed the shunt leads.

-

Since neither the inspectors nor the licensee have

'

,

identified similar lifted lead problems, this matter is

(

considered an Unresolved Item pending further NRC review

(341/93004-03(DRP)).

1

Work Request (WR) 00Z923690 issued to install a new EPA

l

breaker was marked N/A (not applicable) for a Abnormal

Lineup Sheet (ALS) and applicability for an LCO (Limiting

i

Condition of Operation). The ALS was the station's method

~

for protection of plant personnel and equipment while

working on plant systems and equipment. ALS 93-0195 was

'

issued to take the installed EPA breaker out of service

prior to installing the new EPA breaker. The LC0 block

>

'

identifies the impact on Technical Specification (TS)

requirements.

Further review by the inspectors determined

s

that the work authorizations was approved for work on

February 10, 1993.

The new EPA breaker was installed on

February 17, 1993. The blocks for ALS and LCO were both

j

marked N/A on February 10, 1993, because the WR required a

!

bench test of the new EPA breaker prior to installation.

,

The bench testing of the new EPA breaker performed on

'

February 10 did not require an ALS or the initiation of an

j

,

14

I

-

.

-

.

-

.

LCO. Therefore, when work authorization was obtained on

.

February 10 to perform the bench testing, the ALS and LCO

l

blocks were marked N/A on the WR. However, to retain

,

control of the work activity in the field when the installed

EPA would be removed and replaced with the new bench tested

EPA breaker, the Nuclear Shift Supervisor (NSS), who signed

the WR on February 10, added a step to the WR that required

.

r

the maintenance personnel to contact the NSS prior to

,

replacing the EPA breaker. An ALS was initiated on

'

-

February 17, 1993 prior to the start of the in plant work.

During the review of the ALS, the Control Room Nuclear

'

Supervising Operator identified the need for an LCO.

Based

on this method of work authorization not being defined in

the station's administrative procedures, this matter is

i

considered an Inspection Followup Item (341/93004-04(DRP)).

l

The inspectors had the following observation pertaining to work

!

planning:

l

The system outage for the standby feedwater system (SBFW)

!

commenced on January 31, and a Technical Specification (TS)

l

LCO was entered when the system was taken out of service to

'l

perform maintenance.

In preparation for WR N820911104, the

'

SBFW discharge header was drained and the discharge header

relief valve was removed.

When maintenance personnel

!

attempted to install the new relief valve in the line, they

[

discovered that the replacement relief valve was physically

j

-

too tall to fit in place.

The PM was deferred and the

'

original relief valve was reinstalled in the line.

This

l

deferral could have been avoided by better planning

evaluation of the replacement valve.

The system outage for Division I of the Noninterruptible Air

Supply (NI AS) System commenced on March 4, and a Technical

j

Specification (TS) LCO was entered in support of the

-

'

maintenance outage. The system was taken out of service,

and the LCO entered without the correct parts initially

being ready for Work Request (WR) P503920611.

Even though an LC0 was entered for other work during the SBFW and

NIAS system outages and the above observations may not have

resulted in increased SBFW or NIAS outage times, the inspectors

were concerned with the lack of effective work planning for the

outages. These observations and concerns are similar to an item

documented in Inspection Report 341/92021 (reference Unresolved

Item 341/92021-04(DRP)).

The inspectors will continue to observe

and track the licensee's work planning practices under the above

referenced unresolved item.

'

.

15

.

i

b.

Assessment of Backloa

j

To assess the material condition of the high pressure coolant

'

injection (HPCI) system, the inspectors requested a listing of the

!

open corrective work requests (WR) that pertained to HPCI. The

inspectors reviewed the list, dated January 8, 1993, and

i

identified that there was no apparent outstanding WRs affecting

HPCI operability. The inspectors did identify two WRs 007B880511

i

and 008D900423 that pertained to the HPCI drain pot isolation

valves, E4150-F028 and E4150-F029. Work Request 007B880511 issued

on valve E4150-F028 for dual indication (open/close) and WR

008D900423 was issued on valve E4150-F029 because valve would not

stroke fully closed. The inspectors reviewed the history of these

'

valves which is further discussed in paragraph 6.a of this report.

c.

Surveillance Activities (61726)

During the inspection period, the inspectors observed technical

,

specification required surveillance testing and verified that

!

testing was performed in accordance with adequate procedures, that

_'

test instrumentation was calibrated, that results conformed with

technical specifications and procedure requirements and were

reviewed, and that any deficiencies identified during the testing

>

were properly resolved.

The inspectors also witnessed portions of or reviewed the

following surveillances:

23.107.01

Standby Feedwater System

24.107.03

SBFW Pump and Valve Operability and Lineup

l

Verification Test

'

24.207.008 EECW Pump and Valve Operability Test

24.324.001 Combustion Turbine Generator II Unit I Monthly

Operability Check

24.707.01

Reactor Water Cleanup Valve Operability

43.401.206 Local Leak Rate Testing on Personnel Access

Hatch

,

On March 4, 1993, at 9:20 a.m. (EST), the licensee identified that

l

the Electrical Protection Assemblies (EPA) breakers for the

'

reactor protection system have not been adequately tested to

comply with Technical Specification (TS) 4.8.4.4.

The test

j

procedure that had been used to perform the channel functional

'

,

test did not verify that the EPA breakers would trip on simulated

undervoltage (UV), underfrequency (UF), and overvoltage (OV)

'

signals.

Channel functional tests of the EPA breakers were

,

required by TS 4.8.4.4.

Preliminary indications are that this

condition has existed since 1989. As a result, the plant entered

.

TS 3.0.3.

The tests are required to be performed every eighteen

!

months or each time the plant is shut down for greater than 24

i

hours if a test hasn't been performed within the previous six

16

i

t

i

!

- -

-

_

. _ -

.!

i

!

. months. The licensee initiated immediate steps to perform

[

channel functional tests that verified that the EPA breakers would

i

trip on UV, UF, and OV. The tests were completed at 11:15 a.m.

'!

4

(EST) on March 4, 1993. The EPA breakers were than declared

i

'

operable and the plant exited TS 3.03.

The licensee identified

this condition when investigating concerns raised by the resident

staff during the witnessing of maintenance activities on the EPA

!

breakers.

The inspectors will review this matter when the

!

applicable Licensee Event Report is issued.

!

No violations or deviations were identified.

!

6.

Engineerina & Technical Support (37700)

j

a.

Hiah Pressure Coolant In_iection (HPCI) Drain Pot Isolation Valves

i

During the review of the maintenance backlog for HPCI, the

inspectors identified two work requests (WR) 007B880511 and

008D900423 that pertained to problems with valves E4150-F028 and

!

E4150-F029. These valves, normally open when HPCI was in standby,

!

receive a close signal upon HPCI initiation to isolate the HPCI

l

drain pot from the main condenser.

The problem with the valves

i

was the inconsistent ability of the valves to close under system-

pressure to isolate the HPCI steam supply line from the main

condenser via the drain pot.

Deviation Report (DER) 89-0286

identified that valves E4150-F028 and E4150-F029 were installed

'

with flow under-the-vent configuration -instead of the original

'

j .

design which was for flow-over-the vent.

Therefore, there was not

sufficient force from the valves actuator to consistently close

the valve under system pressure. The inspectors reviewed the

e

licensee's assessment for HPCI operability documented in DER 89-

j)

0286 and Safety Evaluation 89-0226 (Revision 0 and 1). The

assessment discussed the affect of valves E4150-F028 and E4150-

l

F029 not closing during a HPCI initiation. The assessment stated

that HPCI operability was not affected because the steam lost

through the valves to the main condenser was insignificant

l

compared to the steam available to the HPCI turbine. Any flow

j

through the 1" drain line would be significantly restricted by a-

t

notched globe valve in the line. Also, the potential release path

through the valves to the main condenser does not affect HPCI

!

operability, because this steam release would be similar to an

!

instrument line break and any release during an accident would be

bounded by the main steam line break accident. At this time, the

l

inspectors have no concerns with the issue.

j

b.

Reliability of Hiah Pressure Coolant in.iection (HPCI)

!

The inspectors were concerned with the recent failures of

i

subcomponents in the HPCI system.

Two of the failures resulted in

-

inoperability of the HPCI system. The following degraded

conditions have recently occurred on HPCI:

l

'

!

l

17

l

l

6

i

-

m

,

$

e

On January 4,1993, a relay failed in the HPCI logic that

I

!

would have prevented the HPCI Steam Admission Valve (E41-

I

F00ll) from opening electrically by either a manual or

automatic demand.

>

e

On January 14, 1993, the HPCI system failed to start during

[

a surveillance. The cause was a failed voltage dropping

.

'

resistor in the governor control circuit. The failed

resistor affected the governor control circuit either in the

manual or automatic demand mode.

!

On January 14, 1993, after tripping the HPCI Turbine, the

Auxiliary Oil Pump properly auto started. However, after

the turbine stopped, the Nuclear Operating Supervisor

,

observed that the Auxiliary Oil Pump was not running.

'

Investigation determined that contacts that were on the

"run" position of the Coordinated Motor Control (CMC) . switch

had high resistance.

After cycling the CMC switch between

,

off/ reset and run, the Auxiliary Dil Pump started.

Even

though the "run" position of the CMC switch was not required

to be functional to declare HPCI operable, the licensee has

initiated preventative maintenance activities to cycle the

Auxiliary Oil Pump CMC Switch to ensure contacts were wiped

clean of any oxide buildup that could result in high

resistance across the contacts.

On February 17, 1993, during a panel walkdown in the main

control room, the Nuclear Shift Supervisor observed that the

HPCI flow controller was at approximately 93 percent demand

with the controller in automatic rather than 100 percent.

The 100 percent demand was equivalent to approximately 5200

gallons power minute.

The licensee's investigation

determined that 93 percent demand in automatic would still

provide sufficient flow for HPCI to continue to be declared

operable. The cause of the reduction demand was degradation

of the control amplifier output.

The licensee placed the

controller in manual and replaced the control amplifier.

The controller was then placed back in automatic.

The licensee's Individual Plant Examination (IPE) identified the

HPCI system as an important system in maintaining a low core

damage frequency. The IPE further states that controlling

maintenance and testing unavailability of HPCI is an important

risk management measure.

Based on the above problems, the

reliability of the HPCI system is considered an Unresolved Item

(341/93004-05(DRP)).

c.

Information Notices (IN)

During the inspection period, the inspectors reviewed the

licensee's assessment of two ins. One IN (90-51) was reviewed

18

_ _ _ _ _ _ _ .

.

- - - .

,d

J

e

i

during the review of Licensee Event Report 341/93002 that

f

pertained to failed resistors in governor control systems. The

!

other (IN 92-50) was reviewed during the inspector's review of

closed Deviation Event Reports (DER).

Information Notices are NRC

i

documents distributed to license holders that contain information

i

on possible generic issues. The ins are not considered NRC

requirements; therefore, the licensee is not required to initiate

specific action or provide to the NRC any written response. The

!

inspectors identified the following concerns in the review of the

licensee's assessment of IN 90-51 and IN 92-50-

l

Information Notice (IN) 90-51 identified industry problems

l

with voltage dropping resistors used in governor control

l

systems.

Information Notice 90-51 identified not only

i

problems with resistors in a specific governor control

i

system (Woodward Type 2301) used in emergency diesel

l

generators but also failures of voltage dropping resistors

(

in HPCI and RCIC in 1982, 1983, and 1984.

Information

!

-

Notice 90-51 stated that power supply circuitry employing

voltage dropping resistors may be used in governor control

l

systems other than Woodward Type 2301. The evaluation of IN

l

90-51 was documented in Deviation Report 90-0507.

The DER

was closed based on IN 90-0507 not being applicable because

'

d

there were no Woodward Type 2301 in use at the station. The

!

'

DER never assessed the application of voltage dropping

!

resistors in other than Woodward Type 2301 governor control

'

systems.

The inspectors were concerned that the review of

5

IN 90-51 did not consider other applications of voltage

i

dropping resistors in governor control systems other than

i

Woodward Type 2301.

l

IN 92-50 was not adequately assessed pertaining to cracking

,

of valves found in the condensate return lines of an

i

.

emergency condenser system. The IN discussed the possible

l

cause of thermal fatigue induced by thermal stratification

I

and cycling on the valves. The licensee' assessment stated

'

.

that the problem does not pertain to Fermi 2 because there

'

is no emergency condenser in use at Fermi 2.

The assessment

did not appear to consider that the cause of the cracking

1

could be applicable to system valves at fermi 2 which could

also be subjected to similar thermo stratification and

cycling as seen on the emergency condensers.

The inspectors were concerned with the narrow approach taken by

'

the licensee in Information Notice reviews for applicability at

"

fermi 2.

The review of ins for applicability at fermi 2 is

,

considered an Unresolved Item pending further review by the NRC

(341/93004-06(DRP)).

.

1

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19

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-_

_

__

_

__

_ _ _ _

_

.

l

.

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d.

Deoraded Control Amplifier

The-inspectors reviewed the licensee's assessment of a~ degraded

!

control amplifier found in the HPCI flow controller during a Main

Control Room panel walkdown. The assessment was performed in a

j

timely manner with excellent. teamwork evident between operations,

-I

maintenance, and the engineering organizations. The technical

-l

'

l

evaluation was sound and thorough. The conclusions reached and

l

the actions taken to maintain operability of the HPCI system was

L

well documented and technically sound. The replacement of the

,

l

degraded control amplifier allowed the HPCI system to be returned

!

i

to an optimum condition in a timely manner.

l

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I

l

e.

Failure of Reactor Water Cleanup (RWCU) Check Valve

]

On January 19, during the performance of the quarterly Reactor

Water Cleanup (RWCU) valve operability test, valve G33-F120 (RWCU

i

to feedwater check valve) failed to show full closed indication in

!

l

the control room. Operators declared the valve inoperable and

l

performed the appropriate actions of the applicable Technical

,

l

Specification Action Statement. A retest of the valve, witnessed

j

both locally and in the control room, was performed, and the

i

second attempt also failed.

Engineering personnel were contacted,

~

and the valve solenoid was exercised several times. Subsequent-

j

third and fourth testing of the valve, witnessed by operators and

l

engineering personnel, was performed satisfactorily. The valve

i

!

was declared operable and Operations Department personnel wrote a

(

deviation event report (DER) to document the problems with the

'

valve.

The inspectors interviewed licensee engineering personnel and

i

reviewed the evaluation and documentation associated with the

valve. The inspectors had no concerns with the licensee's

I

technical evaluation of the problem. Additionally, engineering

l

personnel took conservative action by placing the valve on an

increased frequency testing schedule. No further problems have

been noted with the valve. The inspectors will follow the item

during the routine review of the licensee's DER disposition.

No violations or deviations were identified.

7.

Report review

During the inspection period, the inspector reviewed the licensee's

monthly performance report for December 1992 and January 1993. The

inspector confirmed that the information provided met the requirements

of Technical Specification 6.9.1.6 and Regulatory Guide 1.16.

No violations or deviations were identified.

20

1

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. -

.

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8.

Inspection Followup Items

j

Inspection followup items are matters which have been discussed with the

!

licensee, which will be reviewed by the inspector, and which involve

!

some action on the part of the NRC or licensee or both. The Inspection

Followup Item disclosed during the inspection is discussed in paragraph

5.a.

9.

Unresolved items

-i

Unresolved items are matters about which more information is required in

1

order to ascertain whether they are acceptable items, violations, or

!

deviations. Unresolved items disclosed during the~ inspection are

i

discussed in paragraph 3.a, 5.a. 6.b, and 6.c.

10.

Meetinos and Other Activities

l

i

a.

Manacement Meetinas (30702)

[

On March 8,1993, the licensee and NRC management (denoted in

paragraph 1) met in the NRC Region 111 office for a periodic

management meeting. Topics discussed included: plant status;

I

reportability ~ calls; the third refueling outage; the staffing

transition plan; and process reengineering efforts.

The slides

{

used by the licensee during the meeting are attached.

,

t

b.

Exit Interview (30703)

1

The inspectors met with the licensee representatives denoted in

.!

paragraph I during the inspection period and at the conclusion of

!

the inspection on March 9, 1993.' The inspectors summarized the

i

scope and results of the inspection and discussed.the likely

content of this inspection report. The licensee acknowledged the

information and did net indicate that any of the information

disclosed during the inspection could be considered proprietary in

!

nature.

Attachment: As stated

!

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21

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Attachments

__

_

--

_

T

1

SALP

The NRC noted continued overall improvement at Fermi 2

[

in 1992 and gave the plant its best assessment "1.43" since

!

the plant began operating in 1985.

!

f

-

.--m

. , _._ . _ _

m...---

- ~ . . --

..-m.-.-

.~....,,s.

,

.

. . . - - - _ - . ,

-.,-,

- _ ...-_ ,-... ~,..-. ......--. .--...

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

...,-,...

.

- - -

.

. - - .

-

Refueling

q

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1

l

Completed RFO3 safely and under budget despite an

expanded work scope and the expanded schedule. At less

than 57 days, RFO3 was the third shortest refueling outage for

any BWR in the country in 1992.

- - _ -

Lost-Time Accic ents

YTD Average = 0.094

0.5

Tay;et = 0

Fermi's lost-work day

incidence rate of 0.09

was much better than

OA

the all<lectric utilities

average of 0.61 in 1991.

c

g

1993's Lost-Time

5

0.3

r

Accident rate = 0.

B

~p

4

k

0.2

-O-

YI D ^vn.

'O

g,3

_

0

y i y i y i y

i

y , v i y

i y

i

y ,

.y

i v i y

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Lost-time accident rate involves the number of instances per 200,000

manhours worked. Contractors are not included.

l

!

_

. .

.

_

, - _ .

,

..-

-_-

.

-

. -. _ _ -

_

. - - - _ .

.

- - _ .

-

_

--

- ..

.

-

,

.

4

l

Co. ective Rac iation Exoosure - Annua.

YTD = 229.3

!

240

M

Fermi's col lcctive radiation

gg

~

exposure in 1992 was 229.0

_

'

-

-p

manRem. It was low enough

200

to rank the plant second

y

nationally among UWRs over

180

//

the last three-year period.

g

140

1993's Collective Radiation

!

-

[

Exposure goal = less than

g

120

50 manRem.

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100

-

'/

80

.

60

-

40

-

3

Actual

~

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'

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3[7- Cum. Target

,

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T

-

Jan

Feb

Mar

Apr May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Annual collective radiation exposure is the total exterc.al whole be

dose received by all on-site personnel during the year as measured by

the thermoluminescent dosimeter (TLD).

-

- -

. . - . -

_

-

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

--

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

8

i

Net Caaacity Factor - Annual

YTD Average = 79%

110

Target: Min = 78%

Despite a refueling outa);c

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g

@

-

--

-

which lasted 7 days long;cr

than scheduled and a week-

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90 -

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M

long outage in December,

~

Fermi 2 registered a net

M~~

-

capacity factor of 79%.

70 --

-

1993's Capacity Factor

y

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goal = 94%

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Feb Mar

Apr May

Jun

Jul

Aug Sep

Oct

Nov

Dec

,

Net Capacity Factor monitors the progress in attaining high Fermi 2

energy production reliability. Capacity factors calculated using NRC

Gray Book MDC value of 1060 MWe.

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SIGNIFICANT PLANT EVOLUTIONS

'

SINCE RF03

i

-

Novernber 18, 1992:

Loss of Feedwater Resulting in a

Manual Reactor Scram

,

!

j

,

Decernber 1,1992:

Extraction Steaun Line to #4 Heater

.

Failure

<

.

i

.

i

,

<

February 10, 1993:

Condenser Tube Leak Causes Plant

'

Shutdown

i

!

a

.;

l

!,

i

February 19, 1993:

Loss of Circulating Water Systent

'

Causes Plant Shutdown

.

!

i-

!

'

i

l-

.

-

.

._

. _ . _ - .

_

__

- . -

,

i

l

,

I

i

I

!

4

LOSS OF FEEDWATER RESU'LTING

IN A MANUAL REACTOR SCRAM

i

l

-

Occurred:

November 18,1992

l

1

i

Cause:

Personnel Error - NPPO inadvertently

i

opened a deminerali7.er influent line.

Condensate pressure inomentarily dropped

j

'

causing the IIeater Feed pumps to shutdown.

!

'

i

Corrective

Action (s):

Procedure Changes Made

j

i

Event Discussed in Operation Training

j

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!

.

.,

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f

d

l

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.

-.

.

,

!

j

.

1

4

EXTRACTION STEAM LINE

,

TO #4 HEATER FAILURE

-

Occurred:

December 1,1992

,

i

Cause:

Improperly Designed

Pipe Support

.

i

?

"

Corrective

Action (s):

Pipe Support Changed

to Saddle Type

.

!

i

'

i

,

l

t

i

.

.-

i

l

,

i

f

i

r

CONDENSER TUBE LEAK

CA_USES PLANT SHUTDOWN

!

Occurred:

February 10, 1993

i

.

Cause:

The tube was struck

by a heavy object that

fell from above.

-

.

Corrective

Action (s):

Leaking Tube

Plugged

,

Susceptible Tubes

Plugged

j

i

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,

J

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i

t

i

.-.

. - .

i

1

LOSS Q.F CIR_CULATING WATER

SXS_ TEM CAUXES PLANT SIIUTDOWN

l

!

Occurred:

February 19,1993

.

Cause:

Personnel Error - Electrician

inadvertently activated 4160 VAC

-

bus 69J trip relay while working in

.

panel.

!

3

Corrective

Better Labelling in Bus 69J

i

Action (s):

t

Discuss Event in Maintenance

,

I

j

Training

I

i

!

s

. ..

HPCI SYSTEM

,

LER 93-001

Occurred:

January 4,1993

Cause:

Relay E4100M092 Failed

Key Corrective

Actions (s):

Replaced Relay; PM Event Established

!

LER 93-002

Occurred:

January 14, 1993

Cause:

Failed Dropping Resistor

,

Key Corrective

Actions (s):

Replaced dropping resistor. Establish

team to evaluate electronic /clectrical

components.

DER 93-0100

Occurred:

February 17, 1993

i

Cause:

Failed Control Amplifier

,

!

Corrective

Action (s):

Control Amplifier Was Replaced

l

)

!

PLANT STATUS

.

Currently Operating at:

98 %

Year-to-Date Capacity Factor:

91.5 %

1992 Capacity Factor Was:

79 %

Year-to-Date Radiation Exposure:

7.331 m' Rem

au

1992 Radiation Exposure:

229.3 man-rem

,

!

i

,

i

. . .

-

..

.-

._- - ,

l

R portability Calls

e

1

~j

,

!

Sequence of Events

!

2/25/93 at ~ 1700 Hrs

STA replaces light bulb / fuse blows. Plant impact

.

includes:

,

'

c

i

Div 2 EECW auto and manual initiate

[

pushbutton start features inop

i

Div 2 Drywell Pneumatics (a PCIV) isolates

!

EECW Manually initiated

$

Reportability investigated including Primary

'f

Containment isolation Valve and HPCI'

!

2/26/93 at ~1140 Hrs

!

Conference call with NRC Riti and Fermi licensing

'

regarding reportability of T49 valve closure

i

',

1637

Notification made

t

'

Lessons Learned

i

,

!

,

Individuals under mistaken impression regarding non valid ESF component

!

actuations

A complicated issue was not communicated effectively or in a timely manner

,

I

,

'

After hours ineffective communication with duty officer vs effectiva

communication when most resources are present

i

',

Corrective Actions

i

I

Will report unplanned ESF component actuations

i

!

Reiterate / reinforce policy regarding reporting when in doubt

~

Will make every effort to comraunicate significant problems when resources are

available to ensure a complete understanding

.

Revise procedure

.

J

I

l

Will not use dratt guidance

1

'

LER team root cause investigation continuing

f'!

'

l

!

i

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P

.I

ia

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d

I

-. - --

.

-

. . - -

-

- -

.,

,

. - .

RF03 GOAL SUMMARY

GOAL

ACTUAL

SYNCHRONIZE MAIN GENERATOR

SYNCHRONIZE IN 56 DAYS,

IN 52 DAYS

13 HOURS AND 29 MINUTES

-

MINIMlZE RADIATION EXPOSURE

RADIATION EXPOSURE WAS

TO 160 MAN REM

182.708 MAN REM

NO LOST TIME ACCIDENTS

LESS THAN 25 RECORDABLE

9 RECORDABLE INDUSTRIAL

INDUSTRIAL SAFETY INJURIES

SAFETY INJURIES

KEEP O&M EXPENDITURES UNDER

O&M EXPENDITURES WERE

$24 MILLION

$22.1 MILLION

CONTROL OVERTIME LESS THAN

OVERTIME WAS 34.5%

40% FOR SITE

.

- .

-.

.

-

. .

- . - . . .

.

_

- .

.-

- -.

..-. ...

.

-_

_

t

RF03 GOAL SUMMARY

GOAL

ACTUAL

NO LER'S FROM PERSONNEL

3 LER'S FROM PERSONNEL

ERRORS

-

NO NRC VIOLATIONS OF LEVEL 4

THERE WERE NO LEVEL 4

OR HIGHER DURING OUTAGE

OR HIGHER VIOLATIONS

.

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MAJOR RF03 WORK ITEMS

MODIFICATIONS AND SETPOINT CHANGES

i

l

SUPPORTING POWER UPRATE PROJECT

'

INSTALLATION OF AN EIGHTH CONDENSATE

FILTER DEMIN

INSTALLATION OF A TORUS HARDENED VENT

REPLACEMENT OF A MAIN UNIT TRANSFORMER

REPAIR OF STEAM DRYER CRACK

REPLACEMENT OF 160 FT. OF PIPE UNDER

EROSION / CORROSION PROGRAM

COMPLETION OF LEVEL 3 HED MODIFICATIONS

-

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. - .

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.-

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--

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._

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.

REFUEL OUTAGE TASK COMPARISON

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4

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L1197

RF-01

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1981

103 DAYS

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809

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RF-02

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1384

72 DAYS

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114

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757

R F-03

GM

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1227

57 DAYS

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. RF-02/RF-03 COMPLEMENT COMPARISON CONTRACTORS 1400 1200

--- - - - - - 1000 - - - - - - -- - - - - - - - - --- 800 - - - - - 600 - - - - - - - - - - -- - 400

\\ 200 -- - - - ' ' ' ' ' ' ' ' ' ' ' ' ' 0 O 1 2 3 4 5 6 7 8 9 10 11 12 RF-02 1077 1250 1214 1163 110 0 999 929 800 502 371 14 7 R F-03 808 845 776 742 691 508 342 13 8 ' OUTAGE WEEK - RF-02

RF-03 . . - - - - . - - - . . .- ... . . - - . . . . . . - . ..

., , ,

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RF03 LESSONS LEARNED = INSUFFICIENT COORDINATION OF DRYWELL ' ACTIVITIES RESULTED IN HIGHER THAN ANTICIPATED EXPOSURE AND POOR HOUSEKEEPING AND TOOL CONTROL PRACTICES

PROBLEMS WITH OUR WORK CONTROL PROCESS AND LACK

OF EFFECTIVE COMMUNICATION RESULTED IN LERs AND PERSONNEL ERRORS THE HIGH LEVELS TO WHICH MAINTENANCE AND OPERATIONS PERSONNEL WERE MANLOADED AND THE LARGE NUMBER OF ACTIVITIES WHICH NEEDED TO BE COMPLETED DAILY WERE A STRAIN ON THE ORGANIZATION. WE NEED TO BETTER RECONCILE OUR SCOPE TO OUR RESOURCES IN FUTURE OUTAGES BUILDING THE OUTAGE SCHEDULE AROUND OUR SHUTDOWN SAFETY PRINCIPLES HAS RESULTED IN NOT ONLY A MORE SAFE BUT MORE EFFICIENT SCHEDULE .. - . . - - - - . - -- .. . - - - -

. . f* ? REORGAXIZATIOX a 1 AND

RESERUCTERING ~ ' l. 03 XUC~ 3AR G3XHATION i l '\\ . . . _ . . . .--- . , - . .

. > t ., MISSION STATEMENT ! ! s !, Reorganize and restructure Nuclear Generation to facilitate best-in-class organizational effectiveness, right skilling; increase supervisory span of control and improve , communication within the organization. i r i ! 4 _.--_--_..._-.-___._,---.v. -- - -- ,.n . -- --.

s

v - , - - , --

. . - . . _ . . - . . la e n - J r Wt e . . . n i S Fa d ' - l, T n - - a . R - s l s a - O e n c r - F o e . F r t p x 4, s e . r s - e i h h s T t r t e o s d N h _ n e mo t . E s o o u . is M d m r f s . e . s s a o E r h t f r g G . a n s t - h a n - A i c n h o t n n s - N o a y s t e . l A i i p l t l a i . d l t M z e u e . - in v w - r e a e e l g h i R r v - r t o o o e O n n r i . d . e a / I e s d N n d e y e i i E a n d . t t i b a s u S O MV S i t - - -

- . - . _ . - . . ( i- . I ii' ' I> ! 1

. 4 .t i WHY Do WE XEED TO RESTRUCTURE? To achieve long-standing business plan goals - To right skill - To irnprove communication -

j To increase span of control

. I To reduce costs

To obtain competitive strength - To prepare for de-regulation -

.

- 1 - - -- -- - - . . . . ..

. l .. PRIOR TO STARTING STAFFING TRANSITION ' '! '

Voluntary Separation Offer (VSO)

l

Volunteer for Skills Reserve

, ! l Approval based on skills needed

k ' j- . - - . .

, '! . l' ' CVERVIEW OF DGHT SKILLING SELECTION [?ROCESS 1 i

Develop position summary incorporating:

Core skills - UFSAR requirements - - Training qualifications Job specific skills -

Candidate identification

. I' Candidate selection

Review of candidate selection by:

Review board - EEO Legal Selection process . Nuclear Generation Management Team - I t ( . - - . . . .. ,. - .. - . .-- - - .--... - . - .. .

_. . . l N..3W SAMPLE STRUCTURES . _ ! OLD NEW OLD NEW i i

'

Manager Manager General Director Manager ' Superintendent Superintendent Director Director Asst. Superintendent General Supervisor General Supervisor General Supervisor Supervisor Supervisor - .' i Supervisor Supervisor Employe Employe Employe Employe .. . - - - - * m a - - - - w -T->m-m +4vww*ewwa d E-w-4' M P-- 9 "1 re -- 4' -- ws* s*-6- T.m wW1T ' e--* W P- 9- a e a e

-

4 mis e

'-W-7"-M+--

tw w w '

STAFFING TRANSITION SCHEDULE s Organization Completion Date , I Technical 3/19/93 Production 4/23/93 Other - Quality Assurance ' ,, - Training $ 5/21/93 ' - Nuclear Assurance 4 'e . . -, - . . - .. - ~ - . . . - . , ,

. _ - _ . _. . . .. . - __ _ _ _ . _ _ . . _ _ _ _ _ _ _ _ _ _ . . -- - l- Nuclear Generation . , Oraanization b=*e*e . a President March 1993 mumenemmuq I i VK:e Pretident Pbc!oor Operatiorn l . I I Drecte, Ront Techricol tbclear Asasonce Drector tbc!aor ironeg Monoger Monoger Manager Fasc. Quotty Assur, 1 { , 4 Suoerciendent - N d. o C W ~ Ront r g - Pbc!eo wty ~ ~ ! Superntencent Superntendent Technico Okectoe , Mcintenance - Encineerco - Mont Sucoort - , l '

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. [3FFORTS To ASSURE A . I SUCCESSFUL PROCESS ! ! , .

Monitoring, evaluating, and updating UFSAR

organization description charts Continual monitoring and updating of Management . . Policy and Directives

Continued update of NRC
Quality Assurance overview

!

! - - - - - - - - - - - -- -- ~~ ~ ~~~ ~ ~ '~~~

. . t . i

. l XUCLEAR QUALITY ASSURANCE OVERSIGHT

l Review of changes to Section 17.2 of UFSAR (QA program) i a Review of position descriptions and qualifications after each layer of .

organization is announced Review of changes to ensure all QA program elements are included - in new organization - , ! Inclusion of effects of reorganization in scheduled audits and - i surveillances Reorganization audit by November,1993 to cover functional areas a . not covered by regularly scheduled audits before then I i . - - -. .--a..--.

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. . 4

4 YOKrrORING OF DAY-TO-DAY Acr1v111Es

Identification of potential vulnerabilities

, Looking for any loss of support for operations

. Looking for QA activities that could be dropped during transition ' . -

Focusing on areas where functions have been reassigned or people

' have left , List of identified potential vulnerabilities being shared with all NQA a . people so all are informed. of types of problems to be sensitive to NQA list will be modified based on feedback

Loss of productivity expected and experienced

. . .__ _._-_-____.____ _ ___ ______. , .... _. _ ---- .._-.-. .--.. _. . ...- - . ..._.-_.-.,_ . ......4 , . _ . _ . . . . , . . . . . . . . . . . . . . - . , . . , _ _ . . . _ _ , , , - , - . . . . , _ , . . . _ , , . . _ , _ . . . . . . . . ~ . , - -

. . . '

! ! Design Modification j 1 Re-Engineering i

i Project o i ! ' t I I I

i ! i

Project Team l .I ! The project team consists of personnel from:

.j Nuclear Engineering

- - i Technical Engineering ( ' Nuclear Quality Assurance ! - t Pacific Nuclear (contractor) - . ! i , -1- l t ! i i . . .. i-

. . .- . _ _ _ . _ . . . _ . . . _ _ _ _ . _ ._ . _ _ . 1 1 i ' s Project Purpose i

! ! Re-Engineer the Design Modification ' Process so that: l J . Design Changes are prepared, reviewed j , and implemented in a quality and cost i effective manner.

i i Regulatory and management control ! requirements are maintained. > ! ! Pedormance measures / goals are

developed.

-

.i ? I . n l . 2- .- . <

Project Scope , , Improve the modification process from

conception through operation. At Fermi, i this includes the following processes . ,

Potential Design Change (PDC)
As-Built Notice (ABN)
Setpoint Change (SPC)
Engineering Design Packages (EDP)

!

Information Resource input to

Modifications Planning .

Modification Implementation Checklist

(MIC) !

Engineering Change Request (ECR)
Change Paper incorporation
Design Verification / Checking

-3-

1 s Project Methodology

-

! i !

Develop "What Is" model.

! . !

Establish performance indicators and

benchmarks.

Re-engineer the process ("What Should

- Be").

Develop implementation action plans.

. ! I r i , i ! 1 -4 .\\

.

Golden Rules of Re-Engineering , i 1. Don't automate bad process.

P I 2. Don't re-engineer a process you don't ' understand. , 3. Each step of the re-engineered process must add value. j i 4. Identify the customer (s).

i

i e il > , I l r r

-5- i

i Observations t Configuration Managment vs. Design i Control i All systems / components treated identically l Drawings Too many with duplicate information , 4 i Prioritization i , Strengthen the budgeting / scheduling interface

l i ! -, -6- l

. . . _ k 1 I . Observations i

. , All plant modifications treated the same l

ECRs 1 . Too many due to minor changes - , Safety Evaluations 1 Too many for "no value" l

6 ? I

-7-

. . - . . .- . - -. - . . . ! Performance Measures

i l Current Vision- Category Avg M-Hrs / Duration Avg M-Hrs / Duration - i ABNs 60 hrs /60 days 40 hrs /40 days l EDPs/ECRs 500 hrs /90 days 300 hrs /60 days i SPCs 100 hrs /21 days 32 hrs /14 days- Safety Eval. 80 hrs /21 days 32 hrs /7 days PDCs 40 hrs / varies 4 hrs /4 days Reduce # of ABNs/EDPs/SEs, etc. - i . -8- 4

r 3 - The Next Steps

!

Develop the re-engineered process

("What Should Be"). Scheduled for completion mid-March 1993

, Develop implementation action plans. l Scheduled for completion March 1993

I !

i . -9- . . }}

ML20035A612

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