ML20202D940

Insp Repts 50-295/97-22 & 50-304/97-22 on 970830-1010. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20202D940
Person / Time
Site:	Zion  File:ZionSolutions icon.png
Issue date:	11/28/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20202D918	List: ML20202D914 ML20202D929 ML20202D940
References
50-295-97-22, 50-304-97-22, NUDOCS 9712050192
Download: ML20202D940 (23)

See also: IR 05000295/1997022

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U. S. NUCLEAR REGULATORY COMMISSION

REGIONlil

Docket Nos:

50-295, 50-304

License Nos:

DPR-39, DPR 48

Report Nos:

50-295/97022(DRP); 50-304'07042(DRP)

Licensee:

Commonwealth Edison Company

Facility:

Zion Nuclear Plant, Units 1 and 2

Location:

101 Shiloh Boulevard

Zion,IL 60099

Dates:

August 30 through October 10,1997

Inspectors:

E. Cobey, Acting Senior Resident inspector

D. Calhoun, Resident inspector

J. Yesinowski, Illinois Department of

Nuclear Safety (IDNS) Inspector

Approved by:

Anton Vegel, Acting Chief

Reactor Projects Branch 2

9712050192 971128

PDR

ADOCK 05000295

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EXECUTIVE SUMMARY

Zion Nuclear Plant, Units 1 and 2

NRC inspection Report No. 50-295/97022(DRP); 50-304/97022(DRP)

This inspection included aspects of licensee operations, maintenance, engineering, and plant

support. The report covers a six week period of inspection activities by the resident staff.

During this inspection period, the inspectors noted some improvement in the operators'

implementation of the Zion Operations Department Standards. This was most evident in the

operators' response to the unexpected loss of instrument bus 213. However, the inspectors also

noted that the implementation of the out-of-service program remained problematic and that

operators continue to be challenged by inappropriate procedural guidance.

Operations

A violation was identifieo involving three examples of deficiencies in the implementation

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of the out-of-service program (Section 01.1).

The inspectors identified that tha pre-job briefing for the autostart inhibit circuitry testing

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was effective. However, the inspectors alto concluded that the evolution was not

consistently controlled by the Unit Supervisor from the control room and that the

operators were repeatedly challenged by the inconsistent use of three-way

communications by the supporting engineering and maintenance personnel. In addition,

a violation was identified for the failure to provide appropriate guidance to test the

autostart inhibit circuitry for the OC component cooling water pump (Section 01.2).

The inspectors concluded that the operators' response to the loss of instrument bus 213

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was appropriate and effective; however, the event recovery was delayed by tne

unavailability of the auxiliary power to the instrument bus due to a lack of priority on the

retum to service of equipment following maintenance activities. In addition, a violation

was identified for the failure to provide appropriate guidance for operator response to a

loss of instrument bus 213 event (Section 01.3).

Maintenance

The inspectors determined that an inadvertent engineered safety feature actuation

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resulted from inappropriate work practices during a maintenance activity (Section M1.1).

A violation was identified pertaining to the establishment of the nuclear instrumentation

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powe range rate trip setpoint greater than that allowed by the Technical Specification

Limiting Safety System Setting, in addition, a violation was identified involving the failure

to maintain the minimum number of operable power range rate trip channels or compiv

with the Technical Specification Action Statements. Of particular concem was the failure

of the licensee to identify these deficiencies without prompting by the inspectors

(Section M8.2).

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Plant Syp19d

The inspectors concluded that the licensee inappropriately secured the compensatory

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measures for a degraded vital area barrier (Section 81.1).

The inspectors concluded that on two occasions security officers were inattentive to their

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duties while at an assigned security post (Section St.2).

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Resort Details

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Summary of Plard Status

During this inspection period, the licensee maintained Unit 1 in a defueled condition and Unit 2 in

a cold shutdown, depressurized cor dition pending completion of restart actions delmented in the

Zion Recovery Plan.

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1. Operations

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Conduct of Operations

01.1

Out-of-Service (OOS) Pronram implementation Problems

a.

lDspection Scope (71707 and 62707)

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The inspectors reviewed the circumstances surrounding four events involving

OOS program implementation problems. The inspectors interviewed operations and

engineering personnel and reviewed applicable documentation and procedures, including

Zion Adm;nistrative Procedure 300-06, "Out of Service Process," Revision 15.

b.

Observations and Findinos

During this inspection period, the inspectors noted four examples of deficiencies in the

licensee's implementation of the OOS program. As previously documented in

NRC Inspection Report No. 50-295/96020; 50-304/96020, 50-295/96017; 50-304/96017,

and 50-295/96014; 50-304/96014, the im?iemontation of the OOS program continues to

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be an area of concom. Specifically;

OOS on the OA Fire Pumo Imoroperty Cleared

On September 10,1997, following the clearance of OOS No. 970009297 on the QA iire

pump, an operator identified that the expected indication for the OA fire pump was not

available in the control room. The licensee subsequently determined that while clearing

the OOS, a non-licensed operator incorrectly retumed the 0A fire pump breaker to

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service, in that, the control power knife switch had not been closed as required. The

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non-licensed operator's failure to close the control power knife switch also resulted in the

shunt trip circuit being disabled, which would have prevented the pump from tripping on

an engineered safety feature load shed during an undervoltage condition. Consequently,

during an undervoltage condition, the OA fire pump would have immediately loaded onto -

the 1 A emergency diesel generator (EDG) At the end of this inspection period, the

licensee's investigation was still in progress.

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Zion Administrative Procedure 300-06,"Out of Service Process," Revision 15,

Appendix B. " Lifting OOS Techniques," spedfied, in part, that equipment be retumed to

service in accordance with the applicable system operating instruction (SOI). Step 5.2.9

- of sol-63N, "480V Breaker Racking Operations," Revision 4, specifiaf, in part,' that the

control power knife switch be closed. The failure to close the control power knife switch

during the retum to service of the OA fire pump breaker as required by SOI-63N,

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step 5.2.9, is considered an example of a violation of TS_6.2.1.a (No. 60-295/97022-01a;

50-304/97022-01a), as described in the attached Notice.

Independent Vertfication identified an improperty Huna OOS Card

On September 29,1997, during independent verification of OOS No. 970009648 on the

2B EDG train *A" starting air system, a non-licensed operator identified that the OOS card

for the 'A' starting air compressor local control switch was on the wrong switch. The

licensee subsequently determined that the local control switch for the "A" starting air

compressor had been repositioned to the "OFF" position, as required. However, the

non licensed operator mistakenly hung the card on the 2B east fuel oil transfer pump

local control switch. As a result, the licensee immediately corrected the error and initiated

problem identification form (PIF) Z1997-01972. Tha 28 EDG was operable throughout

this occurrence sincc the train *B' starting air system was operable.

Improperty Positioned OOS Valve identified While Clearina the OOS

On October 2,1997, while clearing OOS No. 970009345, a non-licensed operator

idantified that the 1 A EDG train 'A' main starting air check valve test tap isolation valve,

il>G0169, was capped and open. However, the OOS position for 1DG0169 was

uncapped and open. The licensee subsequently determined that the OOS had initially

been hung correctly since the starting air header had successfully been depressurized via

this vent path. As a result, the licensee completed clearing the OOS, retumed the

1 A EDG to service, and initiated PIF Z1997 02045. At the end of this inspection period,

the licensee'= investigation was still in progress. The failure to maintain 1DG0169, in the

position required by OOS No. 970009345 is considered an example of a violation of

TS 6.2.1.a (No.50-295/97022-01b; 50-304/97022-01b), as described in the attached

Notice.

Besidual Heat Removal (RHR) Valve Not in the Reauired OOS Position Resulted in a

Three Percent Decrease in Pressurizer t.evel

On October 10,1997, while attempting to depressurize the 2B RHR train during the

performance of periodic test (PT) 2C-CSD ST, "RHR System CIV [ Containment isolation

Valve) Stroke Timing in Mode 5," the operators noted that the 2B RHR train did not

depressurize as expected. The operators also identified that while attempting to

depressurize the 2B RHR train, pressurizer level dropped approximately 3 percent

(360 gallons); as a result, the operators stopped the test. The licensee subsequently

determined that the 28 RHR heat exchanger bypass valve,2RH87268, was 2/3 of a tum

open. However, OOS No. 970007778, which isolated the 2B RHR train from the

operating 2A RHR train, required 2RH8726B to be in the closed position. Subsequently,

the licensee closed 2RH8726B and successfully depressurized the 2B RHR train. The

failure to place and maintain 2RH8726B in the position required by OOS No. 970007778

is considered an example of a violation of TS 6.2.1.a (No 50-295/97022-01c:

50-304/97022-01c), as described in the attached Notice.

c.

Conclusion

The inspectors concluded that although each OOS error had minimal safety

consequence, the entrs collectively indicated that the licensee's implementation of the

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OOS program remained problematic. Although the violation examples were licensee-

identified or self-disclosing, a violation is being cited since this is a repetitive issue.

01.2 Autostart Inhibit Circuitry Testina Failure due to en inadeauste Operatino Special

Procedure

a.

Inspection Scope f71707 and 61726)

The inspectors observed the pre-job briefing and performance of Operating Special

Procedure (OSP)97-039, West of Autostart inhibit Circuitry for Bus 149 Pumps,"

Revision 0, interviewed operators and maintenance personnel, and reviewed applicable

documentation,

b.

Observations and Findinas

On September 19,1997, C.e licensee conducted a pre-job briefing for the performance of

OSP 97-039. The inspectors noted that the Nuclear Station Operators (NSOs)

participating in the pre-job briefing exhibited a questioning attitude. For example, the

NSOs questioned the applicability of step 1.9.2, which required a jumper to have been

installed only if the steam generetor lo-lo level relays were deenergized, in response to

the question, the licensee suspended the briefing while an NSO determined the state of

the relays. The NSOs also qt.estioned the electrical maintenance technicians supporting

the evolution on the appropriateness of utilizing jumpers with alligator clips, which had

been identified as a contributing cause for the inadvertent engineered safety faature

(ESF) actuation on September 2,1997 (See Section M1.1). However, the technicians

convinced the NSOs that tne use of this type of jumper was appropriate for this evolution.

Following the completion of the pre-job briefing, the licensee initiated OSP 97-039.

During the performance of step 1,10, which installed a jumper to simulate a component

cooling water (CC) low header pressure autostart signal to the OC CC pump, the electrical

maintenance technician knocked off the jumper previously installed in step 1.9.2.

Fortuitously, the dislodged jumper did not contact any other component prior to being

restrained by the technician. The inspectors identified that the technician dislodged the

jumper due to the use of jumpers with alligator type clips and the technician having

reduced manual dexterity as a result of using low voltage rubber gloves with leather

protector outer gloves. The inspectors subsequently determined that the electrical

maintenance technicians had been made hware of the Ocumstances surrounding the

inadvertent ESF actuation on September 2,1997, during a maintenance shop meeting.

However, at the time of this event, the licensee's investigation lato the inadvertent

ESF actuation had not been completed; and as a result, the licensee's corrective actions

had not been developed and implemented.

During performance of OSP 97-039, Section 2," Component ActuationNerification," the

OC CC pump breaker did not close automatically as expected in step 2.6. As a result, the

operators stopped the testing and restored equipment to normal configuration. The

licensee determined that the procedure would not work as written, in that, the closure

signal for the OC CC pump breaker was being inhibited by the manual actuation of ralay

SX1 in accordance with step 2,1. On September 20,1997, the licensee revised

OSP 97-039 and successfully completed the evolution.

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The licensee also identified 15at the technical review of the procedure was conducted by

an individual who contributed to writing the procedure. Consequently, the reviewer did

not recognize the deficiency in the procedure. As a result of this occurrence, the licensee

initiated PlF Z1997-01896. The failure of OSP 97-039 to provide appropriate guidance to

test the autostart inhibit circuitry for the OC CC pump is considered an example of a

violat:on of 10 CFR cart 50, Appendix B, Criterion V (No.50 295/97022 02a;

50 304/97022-02a), as described in the attached Notice.

While observing the performance of OSP 97-039, the inspectors identified that the NSOs

conducting the testing in the bus 149 switchgear room satisf actorily controlled the

evolution. However, the NSos were repeatedly challenged by the inconsistent use of

three-way communication by the system engineer and maintenance technicians

supporting the evolution. Specifically, the system engineer and m%)ntenance technidens

did not consistently repeat back the direction that they had received to ensure that their

understanding was correct prior to implementing the direction without prompting by the

NGOs.

In addition, the inspectors noted that at times the evolutiou was not controlled by the

Unit Supervisor from the cmtrol rocm. Specificalty, when the temporary jumper was

dislodged, the NSos in tN. switchgear room directed the rnalntenance technicians to

remove the installed jumpers prior to receiving authorization from the control room.

Furthermore, following the fallute of the OC CC pump breaker to close automatically, the

system engineer, with concurrence from the NSOs, directed the maintenance technicians

to perform continuity checks on the installed jumpers without evaluating the possible

romifications of the troubleshooting or receiving authorization from the control room.

Upon the completion of the continuity checks, the NSos stopped the troubleshooting

activities and coordinated with the control room to restort. the plant equipment from the

failed test.

c.

Qqo.clusions

The inspectors concluded that the pre-job briefing effectively prepared the operating shift

to perform OSP 97 039. The Inspectors also enneluded that the NSOs exhibited a

questioning attitude during the briefing; however with respect to the use of temporary

jumpers with alligator clips, the NSos missed an opportunity to ensure that actions were

implemented whicii could have prevented the jumper from being dislodged during the

evolution. In addition, the inspectors concluded that the evolution was not consistently

controlled by the Unit Suoervisor from the control room and that the NSos were

repeatediv challenged by the inconsistent use of three-way communications by the

system engineer and maintenance technicians supporting the evolution. The inspectors

also concluded that OSP 97-039 was inadequate, in that, the procedural steps were not

sequericed in a manner which allowed the successful testing of the au'ostart inhibit

circuitry for tha OC CC pump. As documented in NRC Inspection Report

No. 50 295/97013; 50 304/97013, 50 295/97012, and 50-295/97002; 50-304/97002, the

failure to provide operating procedures that contain guidance appropriate to the

circumstances remains problematic (See also Section 01.3). Although the violation

example was self-disclosing, it is being cited since this is a repetitive issue.

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01.3 Lgss of Electdcal Power to Instrument Bus 213

a.

Inspection Scope f71707 and 37651)

The inspectors reviewed th6 eircumstances surroune.;ing the loss of instrument bus 213

on September 22,1997. The inspectors interviewed operators, reviewed Abnormal

Operating Procedure (AOP) 8.1, ' Loss of instrument Bus,' Revision 19(G), and the

electdcal circuitry associated with the bode acid transfer pumps and the RHR minimum

flow valve, and evaluated the licensee's root ca'tse investigation and subsequent

corrective actions,

b.

Observations and Findinos

On September 22,1997, the control room received numerous unexpected annunciators

and equipment actuations due to the loss of electdcal power to instrument bus 213.

Based on the inspectors' review of the circumstances surrounding this event, the

inspectors determined that the operators' response to the event was app opdate and

eff9ctive. Specifically:

The operators quickly and correctly diagnosed the failure and entered the

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appropriate AOP.

The operetors recognized the expected increase in charging flow when the

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charging flow control valve,2FCV-VC121, failed to 20 percent open. The

operators also recognized the potential for a positive reactivity addition when the

bonc acid trcnsfer pump failed to start as expected on the volume control tank

(VCT) automatic make-up, which resulted in pure water being added to the VCT.

In response, the operators appropriately switched the charging pump suction to

the refueling water storage tank to provide a borated water supply to the charging

pumps.

The operators recognized th4, expected increase in RHR flow when the

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2A RHR heat exchanger outlet valve,2HCV RH606, and the 2A RHR heat

exchanger bypass valve,2HCV-RH618, both failed open. As a result, the

operatort mor,itored the decreasing reactor coolant system temperature

throughout the event.

The operators identified that the 2A RHR pump minimum flow valve,

2MOV-RH610, unexpectedly cycled continuously throughout the event. As a

result, the operators monitored the RHR pump ampurage to ensure that the pump

was not operati g in a runout condition.

The inspectors also noted that the recovery from the loss of the instmment bus was

delayed appmximately 15 minutes due to the auxiliary power feed for the instrument t,us

being tagged OOS. The maintenance on this component had been completed

approximately 16 days earlier, however, the OOS had not been cleared due to a lack of

priority on retuming equipment to servicu in a timely manner followir.g the completion of

maintenance activities.

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The licensee subsequently revealed that the boric acid transfer pump and the

2A RHR pump minimum flow valve operated as designed for a loss of

instrument bus 213. The boric acid transfer pump did not start since the Unit 2 boric wd

tank level instrument, which was powered from instrument bus 213 and failed low on a

loss of power, provided a pump start inhibit signal to prevent pump damact due to low

tank level. The 2A RHR pump minimum flow valve cycled continuousY throughout the

event since both the open and closed flow contact circuits in the valve positioning

circuitry were powered from Instrument bus 213, coupled with the seat in arrangement of

the position circuitry. Consequently, the valve received a continuous open demand as

soon as the valve went full clos,ed, and a closed demand as soon as the valve went full

open. In both of these cases, AOP 8.1 did not identify the equipment response to a loss

of power to instrument bus 213 or direct appropriate follow-up actions. The failure of

AOP 8.1 to provide appropriate guidance for operator response to a loss of instrument

bus 213 event is considered an example of a violation of 10 CFR Part 50, Appendix B,

Criterion V (No. 50 295/97022-02b; 50-304/97022 02b), as described in the attached

Notice.

In response to this event, the licensee's planned or (ompleted long terrn corrective

actions included the following:

The licensee identified that an intemal DC fuse was blown in inverter 213 (the

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normal power feed to instrument bus 213); however, engineering pomernel were

unable to determine the ca ,se of the blo nn fuse. As a result, system engineering

personnelinitiated engineering request No. 9503202 to evaluate a hardware

upgrade to the control circuits of the instrument inverters.

Operators evaluated the adequacy of AOP 8.1 utilizing various simulator

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scenarios. As a result, the operations department personnel plan to revise

AOP 8.1 to recognize and provide appropriate follow-up actions for the loss of

boric acid transfer pumps and for the continuous cycling of the RHR pump

minimum flow valve during a loss of instrument bus 213 event. In addition, while

conducting these simulator scenarios, the licencee determined that the simulator

incorrectly modeled the aivallability of the boric acid transfer pumps during this

event; consequently, the licensee plans to correct the simulator modeling.

Design engineering personnel initiated engineering request No. WO6286 to

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determine whether a design change is needed to the RHR minimum flow valve

control circuitry.

The Shift Operations Supervisor plans to establish an operations department

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policy to require that auxiliary power be verified available prior to allowing tork on

or in the instrument inverter cabinets.

The operating procedures group personnel plan to provide an additional section to

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the licensed operator tumover check sheets to list the irnportant equipment that is

unavailable in order to heighten the operators' awareness to this equipment.

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Conclusions

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The inspectors concluded that the operators' response to the loss of lastrument bus 213

was g#: and efiscove. The inspectors also concluded that the event recovery

was delayed by the unavailability of the auxiliary power to the instrument bus due to a

lack of priority on the retum to service of equipmerd following maintenance activities, in

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addition, the inspectors concluded that AOP 8.1 was dancient, in that, the procedure did

not recognize that a posieve reactivity addition would have ocouned due to the boric acid

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transfer pump autostari signal 1 eing inhibited or that the residual heat removal pump

minimum flow valves would have cycled continuously, due to the loss of .

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instmmerd bus 213. As documented in NRC inspection Report No. 50 295/97013;

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50-304/97013; 50-295/97012, and 50 295/fe7002; 50-304/97002, the failure to provioe

opwating procedures that contain guidance appropriate to the circumstances remains

F 'wi (See Also Section 01.2). Although tne violation example was self<hseiosing,

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it is be,ng cited since this la a repet'tive issue.

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Miscellaneous Operations leaues

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08.1 50.54m Performanoe Indicators

a.

inspection Scope (71707)

The inspectors reviewed the development of selected 50.54(f) performance 'ndscators

and interviewed operations, maintenance, and radiation protection personnel.

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b.

Observations and Findinns

The inspectors reviewed the following performance indicators:

C7 Percent Contaminated Floor Somoe

The licensee developed performance indicator C7, percent contaminated floor space,

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based on the percentage of the plant floor space that was contaminated

> 1000 dpm/100 cm , exclutting high radiation areas with infrequent access, inaccessible

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areas, vaults, pits, and area, routinely used for contaminated work. Throughout 1997,

the licensee lowered the percent of contaminated floor space consistent with the

established work down curve. At the end of September 1997, the goal for this

performmoe indicator was 3.18 percent, while the actual contaminated floor space was

3.20 percent. The inspectors noted that, while the percent contaminated floor space

- Indicator was approximately 3.20 percent, an additional 14.03 percent of floor space was

contaminated and excluded from the indicator in accordance with the definition. Some

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examples of areas that were contaminated and excluded from this indicator incduded the

volume control tack rooms, the horizontal and vertical pipe chases, the hold up tank

rooms, the maintenai.co caves, and the fuel pool areas. In addition, the inspedors noteo

that the containment buildings were contaminated and were not considered I.i the

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development of this indicator,

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C9 Per 91 Rework

The licensee developed performance indicator C9, percent rework, based on the

performance of any maintenance task which resulted in a loss of time or money within a

12-month period. However, the inspectors noted that the licensee only counted

corrective maintonat 4 items in assessing rework and that rework on preventive

maintenance, surveillance, repair /retum to stores, and modification activities were not

considered during the development of this indicator. Throughout 1997, the licensee had

lowered the percent rework from approximatet,r 10 percent to less than 3 percent, items

identified as rework were primarily captured by two processes, the integrated reporting

program and the rework focus report. The effativeness of the integrated reporting

program was dependent on the event screening committee to identify each item that as

rework. The inspectors also noted that the rework performance indicator manager

depended on the individual maintenance department's concurrence on each iter 1 that

was identified as rework.

C17 Overtime Hours

The performance indicator C17, overtime hours, was developed based on the number of

paid overtime hours for Zion Station employees through grade 11. The inspectors noted

that this indicator did not account for the overtime hours worked by senior management

or contractor personnel working at Zion Station. The action threshold for thir indicator

was met when the station's actual overtime hours worked plus the projected usage for

the year exceeded the goal by more than 10 percent. However, the action threshold was

for the entire station and did not apply for any single department, such as operations. For

example, operations' projected overtime for the period of January through June 1997 was

29,830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br />. However, actual paid overtime was 43,367 hours0.00425 days <br />0.102 hours <br />6.068122e-4 weeks <br />1.396435e-4 months <br /> (45.38 percent above

projected); yet, this performance indicator did not provide any indication that there was a

problem with the excessive use of overtime. In addition, the inspectors noted that this

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indicator was financially oriented and was not an indication of safety performance.

c.

Conclusions

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The insptetors concluded that the performance indicators C7, percent cortminated floor

space, and C9, percent rework, indicated that the licensee's performance in these areas

was improving; however, due to the limited scope of the definitions utilized to develop

these indicators, the inspectors questioned the absolute numbers represented in these

indicators, in addition, the inspectors concluded that the performance indicator C17,

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overtime hours, did not provide any meaningful indication of licensee safety performance.

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Conduct of Maintenance

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M1.1 Dislodned Temocrary Jumor Resulted in an inadvertent ESF Actuation

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insooction Scope (62707)

The inspectors reviewed the circumstances surrounding the %edvertent E8F aduation on

September 2,1997. The inspedors interviewed maintenance personnel, reviewed the

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applicable work instructions, and evaluated the licensee's root cause investigation and

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subsee9ent corrective actions.

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b.

Qhtervationsindfindinas

On September 2,1997, in support of the 2C accumulator level transmitter modification,

E22 2-97 264, instrument maintenance technicians installed temporary jumpers tc

maltdain power to the 2A s'.eam generator wide range level indication, in socordance with

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Work Package No. 970060620-01. During the installation of th6 second temporary

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jumper, the technician dislodged the first jumper which momentarily contaded an

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adjacent terminal en the terminal board and caused a short circuit. This short resulted in

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a voltage per*urt>ation on instrument bus 212, which onused an ESF actuation. The

squipment that actuated included trips of all Eagle 21 bistables from rocks 8,9, and 10,

,

with the exception of those that were " energize to trip" or in a tripped condition before the

j

event, auto-start of the 08 and OC CC pumps, auto closure of the containment air sample

-

iniw isolation valve,2FCV-PR248, and a falso high alarm condition on the 2A residual

,

l

heat removal cubicle radiation monitor,2Rl-PR03. The licensee subsequently stopped

i

the work, restored the plard systems and equipmerd, and init;ated an investigation into

the event, in addition, the licensee made a four hour non-emergency report in

!

accordance with 10 CFR Part 50.72.

The licensee's investigation determined that the cause of the event was the use of

I

jumpers with alligator type dips, which do not positively attach, and the technician having

,

reduced manual dexterity as a result of using low voltage rubber gloves with leather

protector outer gloves in a confined area. The licensee implemented interim corrective

,

actions prior to recommencing the work activity on September 4,1997. These actions

included protecting the terminal strip and adjacent areas to prevent the possibility of a

short, and the use of insulated jumpers and non-rated ' surgical" gloves instead of low

voltage gloves to improve the technicians manual dexterity. In addition, the licensee's

immediate corrective actions included briefing each of the maintenance departments on

'

the event.

On Octobsr 9,1997, the maintenance department established a policy on the use of

temporaryjumpers. This policy included: (1) maintenance department head approval

'

prior to the installation of tempoJ.ry jumpers into an energized cabinet; (2) the use of

insulated jumpers when voltage is less than 480 volts instead of low voltage gloves

,

(" surgical * gbves optional); (3) protecting the terminal strip and agacent areas to prevent

the possibility of a short; and (4) briefing operations prior to jumper installation to discuss

,

the ramifications of a dotadM Jumper or short circuit,

i

12

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=

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-

- . .

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c.

Conclusiong

The inspectors concluded that the inadvertent ESF actuation was caused by the use of

temporary jumpers with alligator type clips and reduced manual dexterity due to the use

of low voltage gloves in a confined space.

M8

Miscellaneous Maintenance issues

M8.1 [Qoen) Licensee Event Report (LER 50-304/97001h Unit 2 Instrument Bus Perturbation

Caused by a Short Circuit Occuning During 2C Accumulator Level Transmitter

Modification installation Resulted in Engineered Safety Feature Actuation (See

Section M1.1)

While reviewing this LER, the inspectors identified that the CC phase B containment

isolation valve 2MOV-CC685 did not fait close as expeded; however, the LER state.t hat

all systems functioned as design and no anomalies were noted during the event. The

inspectors raised this apparent discrepany to the licensee's attention; and as a result,

the licensee initiated PIFZ1997-02259 to address this issue. This LER will remain open

pending the licensee's resolution of this apparent discrepancy.

MB.2 (Closed) Unresolved item 50-295/97016-09: 50-304/97016-09: Non-Conservative Power

Range Rate Trip Setpoint Tolerances

On July 15,1997, the licensee identified that the instrument maintenance procedure

acceptance criteria for the nuclear instrumentation power range rate trip setpotr' #as not

conservative. Specifically, instrument maintenance procedures N-41 throut'

44,

" Power Range Nuclear Instrumentation," required that the power range rat.

, be

calibrated to trip at 5 percent of rated flux in 2 seconds with an allowable to,e ance of +1

percent. However, TS Limited Safety System Setting (LSSS), Section 2.1.1.C. required

that the trip be set at less than or equal to 5 percent of rated . lux in 2 seconds. As a

result, the licensee reported this issue to the NRC in accordance with 10 CFR Part 50.72.

During follow-up inspection, the i..spectors noted that on August 21,1997, the licensee

downgraded this issue from one that required a licensee event report in accordance with

10 CFR Part 50.73. The licensee's justification for this downgrade was that a search of

instrument calibrations back to 1995 did not identify any examples where the *as left"

setpoints exceeded the LSSS and that a review of this issue in 1995 did not identify any

previous examples where the LSSS had been exceeded.

On September 19,1997, in response to the inspectors' questions and requests for

documentation, the licensee identified that on May 16,1994, the nuclear instrumentation

power range rate trip setpoint for channel 2N-43 had been set 'as loft" at 5.1 percent In

addition, prior to the next calibration of channel 2N-43, the licensee removed channel

2N 41 from service for calibration on August 1,1994, which resulted in only 2 operable

channels being available for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and 28 minutes. However, TS Table 3.1-1 requires

a minimum of 3 operable channels, except that for channel testing, calibration, or

maintenance the minimum number of channels may be reduced by 1 for a maximum of

2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; otherwise, the unit should be in hot shutdown withh 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

13

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____- ___ ____ _ _ - _ - - _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - _ -

_ _ _ _ _ _ . _ _ _

- -__

-

_ _ . _ _ _ _ _ _ _

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!

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,

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,

While reviewing the cabbration documentation previoush reviewed by the licensee, the

(

,

inspectors identWlod a second example where the nuclear instrumentation power range

l

rate trip setpoint was set 'as left* greater than the L888. SpeclRosly, on

l

February 6,1993, channel 2N 42 was rst *as left" at 5.6 percent. In addition, prior to the

>

next onlibration of channel 2N-42, the licensee removed chantni 2N-41 from service for

j'

calibration on April 26,1993, which resuhvi in ony 2 operable channels being available

j

for 9 hows and 15 minutes. The inspectors also identined that the l6censee was missing

and had not reviswed the data from approximately 35 power range calibration

j

procedures. The licensee subsequenth located each of the calibration procedures,

l

except 2N-42 which was completed on May 13,1994. The subsequerd review of these

=

procedures did not identify any additional instances where the power range rate trip was

i

t

set greater than the L888,

'

TS 3.1.1 states that the setpoints for the reactor protection system are presented in

- !

Table 3.1 1. Table 3.1 1 spoolnes, in part, that the power range rate trip setpoint be

5 percent of rato6 neutron flux /2 seconds. In addition, the setpoints are to be *

estat:lished tolerances for instrument channel and setpoint errors as speciAed in

-

" Zion N888 [ Nuclear Steam Suppy System] 8etpoint Evaluation, Protection System

,

Channels, Eagle 21 Version," but, the instruments shall not os set to exceed a L888.

.

- The failure to establish the nucluar instrumentation power rence rate trip setpoint for

1

channels 2N-42 on February 6,1993, and 2N-43 on May 16,1994, as required by

Teble 3.1 1 is considered 3 violation of TS 3.1.1 (50-304/97022 03), as described in the

attached Notice.

,

.

TS 3.1.2 states, in pa,1, that for all on line testing or instrumentation failure, plant

!

operation shall be permitted in accordance with Table 3.1 1. Table 3.1 1 requires for the

power range rate trip, a minimum of three operable channels, except that for channel

testing, calibration, or maintenance the minimum number of channels may be reduced by

one for a maximum of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; otherwise, the unit should be in hot shutdown within 4

hours. The failure to maintain the minimum number of operable power range rate trip

,

channels or place the plant in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> on April 26,1993, and

August 1,1994, as required by Table 3.1 1 is considered a violation of TS 3.1.2

(No. 50 304/97022-04), as described in the attached Notice.

TS 6.5.1.D requires, in part, that calibrations performed to verify surveillance

requirements (Section 4 of the TSs) be retained for at laast five years. TS 4.1.2

'

specifies, in part, that inst!ument dannel calibration requirements for the various reactor

protection instrumentation and logic channals are established in Table 4.1 1. Table 4.1-1

4

requires, in part, that the power range rate trip channels be calibrated quarterty. The

failure to retain the calibration record for the calibration of channel 2N-42 on May 13,

1994, is considered a violation of TS 6.5.1.0 (No. 50-304/9702LO5), This failure

constitutes a violation of minur significance and is being treated as a Non Cited Violation,

consistent with Section IV of the NRC Enforcement Manual.

This unresolved item is closed.

1

14

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lil. Enoineerina

E1

Engineering Support of Facilities and Equipment

E2.1

Containment Thermal Stress Anatvsis May Not B,qund the Main Steam Line Break

(MSLB) Analysis

On September 15,1997, while performing a safety evaluation for a recently re-performed

containment analysis, engineering personnel identified that the MSLB accident resulted in

a higher containment temperature than the lost of coolant accident event. This elevated

temperature could adversely affect the conf einment thermal stress analysis. The

licensee subsequently completed an evaluation of this condition which concluded that the

elevated temperature from the MSLB was bounded by the containment design

parameters. Consequently, the licensee determined that there was minimal safety

significance for this issue. This issue is considered an Unresolved item

(No. 50 295/97022-06; 50-304/97022-06) pe,iding NRC review of the licensee's

e.aluation of the containmerit thermal stress during a MSLB accident.

E2.2

Star'dbv Instrument Air Comoressor_Qaoacity Testina Not Performed

On September 30,1997, while performing modification testing on the north cribhouse

heating ventilation and air conditioning standby instrument air compressor, engineering

personnelidentified that the air compressor, as well as the station's other standby

nstrument air compressors, had not been s.dequately tested. Specifically, the

compressors had not been tested to verify that they could maintain system pressure on a

loss of pressure in the instrument air system. As a result, the Shift Manager declared ali

of the station's standby instrument air compressors inoperable, initiated

PlF Z1997-01997, and initiated the development of a procedure to test the capacity of

each compressor. This isste is considered an Unresolved item (No. 50-295/97022-07;

50-304/97022-07) pending NRC review of the completeJ capacity test results and the

licensee's corrective actions.

E8

Miscellaneous Engineering lasues

E8.1

(Open) Unresolved item 50-295/97019-06: 50-304/970t9-0J6 Review the licensee's

investigation and corrective acuons for the zebra mussel fouling of the service water

(SW) system.

On August 7,1997, the iicensee declared the 1A SW pump inoperable due to not havlag

adequate service water cooling flow to the motor cooler. Following flushing of the cooling

water supply lines, the 1 A SW pump was declared operable on August 21,1997.

On August 23,1997, the licensee identified that the 1 A SW pump again had no cooling

water flow to the motor cooler. As a result, Unit i did not have any operable SW pumps.

With no operable Unit i SW pumps, the SW system was inuperable since the system

was unable to meet the single passive failure criteria. Consequently, the common unit

CC system was also declared inoperable since SW was a necessary support system.

Therefore, the Unit 2 RHR system was also inoperable since the CC system was a

necessary support system. b a result, the licensee entered Technical Specification

15

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-

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-

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1

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l

2

Action Statement 3.3.1.A.5.a for having one operable RHR loop (one reactor coolant

!

L

system loop capable of natural circulation), which required immediate corrective action to

l

retum the inoperable RHR loop to en operable status as soon as possible. In addition,

>

the licensee notined the NRC of this condition in socordance with 10 CFR Part 50.72.

l

Subsequently, on August 23,1997, the licensee restored the 18 SW pump to an operable

t

condition; arW as a result, the SW, CC, and RHR system were declared operable.

,

On August 24,1997, the licensee's investigation identined live zebra mussels, too large

to pass through the SW strainers, in the 1 A 8W pump pre 4ube piping. As a result, the

!

- licensee conducted radiography of the SW pre 4ube piping on both units, which identified

,

zebra mussel blockage in the pre 4ube piping for both the 1 A and 2A SW pumps.

(

Cer.x ;1+,0y, the licensee initiated flushing of the pre 4ube pipirs for both the 1 A and

!'

2A SW pumps. On August 25,1997, the pre 4ube piping for the 2A SW pump was

suooenfuny cleared of zebra mumis. Hower, the fiushing of the 1 A SW pump

pre 4ube piping was not suoosssful in clearing the zebra mussels from the piping.

in addition, the licensee identified that no chlorine (utilized to control zebra mussel

!

4

Infestation) was evident in the 18 and 2A SW strainers and the 1 A,18 and 1C SW pump

motor host exchanger discharge lines. The pre 4ube piping tapped off the downstream

side of the B SW strainer on both units; honos, the Unit 1 pre 4ube piping was not being

'

-

i

chlorinated. The licensee subsequently determined that the failure of the chlorination

system to deliver chlorine to the 18 SW strainer was due to a stuck check valve or an

obstruction in the line; and, the failure to deliver chlorine to the 2A SW strainer was a

mispositioned chemical injection valve, 2CA0416.

7

On August 25,1997, the licensee performed PT-11 DG28, *2B Diesel Generator Loading

-

Test." During the performance of this test, the operators noted that the diesel lube oil

temperature was abnormally high (approximately 178 'F), but romshed less than the test

'

soooptance criteria of 180 'F. The diesel lube oil temperature was normally maintained

approximately 172 'F by a temperature control valve. The operators discussed the

elevated temperature with system engineering; however, no actions were taken since the

temperature remained less than the test acceptance criteria. On August 26,1997, the

'

inspectors expressed concem to operations and engineering management, that the

identification of the zebra mussel infestation in the SW pre 4ube piping and the elevated

!

lobe oil temperatures on the 28 EDG could have been related.

On August 27,1997, in response to the inspectors questions, the licensee initiated

.

PlF Z1997-01430 to document the elevated lube oil temperatures identified during testing

on August 25,1997. During the review of this Pif, the Shift Manager concluded that the

-

2B EDG was operable, and that no operability assessment was required. The

Shift Manager's basis for this determination was that the lube oil temperature did not

exceed the acceptance criteria; even though, the EDG loading was greater than that

'

required during accident conditions.

On August 28,1997, the licensee removed the 2B RHR train from service for testing.

l

The inspectors were concemed that in the event of a loss of offslie power with the

2B RHR train OOS for testing; and with the operabi'ity of the 2B EDG ( the emergency

,

power supply for the 2A RHR train) in question due to expected heat exchanger fouling,

L the licensee may not have had an operable RHR train capable of removing decay heat.

'

t

The inspectors again questioned operations and engineering management on the basis

.

16

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of the 28 EDG being considered operable given: (1) the elevated lube oil temperatures

observed on August 25,1997; (2) the identificatiors of zebra mussel infestation in the

r

SW pro-lube piping; and (3) the historical fouling of the 25 EDG heat exchangers.

l

W

j

On September 10,1996, the 28 EDG lube oil temperature trended above the test

l

acceptance criteria of 100 'F. The 28 EDG was declared inoperable and the heat

l

exchangers were inspected. Approximately 28.6 percent of the jacket water heat

'

exchanger tubes and approximately 48.8 percent of the lobe oil heat exchanger

tubes were blocked.

4

!

On January 23,1997, during post maintenance testing, the 28 EDG lube oil

!

• -

!

temperature was approxionately 179 'F. The subsequerd inspections of the heat

exchangers revealed that gfsJ.Tf; 29.6 percent of the jacket water heat

l

exchanger tubes and approximately 53.5 percord of the lube oil heat exchanger

i

tubewere blocked.

!

The design ce'oulation 228-B 009M 165, *EDG Jacket Water Heat Exchanger

Tube Plugging Margin," Revision 0, specified a maximum tube plugging margin of

11.18 percent; and,228-8 009M 186, * EDG Lube oil Cooler Tube Plugging

,

Margin," Revision 0, specified a maximum tube plugging margin of 19.19 percent.

!

'

Engineering management responded that the 28 EDG was operable and not degrLded

since: (1) the EDG had met all of the acceptance critoria during testing on August 25,

,

1997; (2) the previous heat exchanger inspedion on March 28,1997, did not identify

significent fooling; and (3) the design calculation 228 8-009M 166, *EDG Lube Oil Cooler

Tube Plugging Margin," Revision 0, was conservative. On August 29,1997, the

j

28 RHR train was retumed to service.

On September 3,1997, the licensee removed the 2B EDG from service and inspected

I

the heat exchangers. The inspection revealed that approximately 59 petent of both the

Jacket water and the lube oil heat exchanger tubes were blocked. At the end of this

_

!

inspection period, the licensee's investigation was in progress and corrective actions had

not yet been developed and implemented. Th's Untosolved item will roms:in open

pending further NRC review of the licensee's investigation and corrective actions for the

zebra mussel fouling of the SW system, including the licensee's basis for concluding that

,

the 2B EDG was fully operable with significant heat exchanger fouling,

i

.

IV. Plant Support

!

1

.

Si

Conduct of Security and Safeguards Activities

S1.1

Compensatory Measures Not Established For A Dearaded Vital barrier

f

a.

Inspection Scope (71750)

!

The inspectors reviewed the circumstar,ces surrounding the licensee's failure to establish

,

i

compensatory measures for a degraded vital area barrier. The inspectors interviewed

operations and security personnel and reviewed applicable proce(ures and

17

.

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

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documentation including Zion Administrative Procedure 110006, " Security Banies and

Compensatory Measures By Secunty Personnel," Revision 0.

,

. b.

Observations and Findines

l

,

On Septemtm 22,1997, a security wporvisor identified that a vital area border for the

Unit 2 unN auxiliary transformer was degraded without compensatory measures in place,

i

The licensee immediately implemented compensatory measures for the degraded banier

>

'

and reported the event to the NRC in accordance with 10 CFR Pad 73.71.

.

The licensee determined that elodrical maintenance personnel removed the security

l

access sleeve en Septer%er 8,1997, in support of the isolated phase bus duct shorting

strap modification,522 2 96 213. On September 9,1997, maintenance personnel

!

reinstalled the border. However, the banier was not installed in the original configuration,

,

in that, only one of two bolts was fastened on one of two collars. This as left

l

configuration was determined to have been soceptable by a security supervisor and the

responsible maintenance supervisor; and, the associated compensatory measures were .

!

terminated. At some point between September 9 and 22,1997, tne security collar

became unattached.- As a result, on September 22,1997, a pathway from the protected

area to the vital area was created when electrical maintenance personnel removed a

panel inside the vital area that was associated with the bus duct.

I

While reviewing the everd, the inspectors identifled that the security compensatory

checklist did not provide guidance or instrudions for ensuring that barriers were

i.

adequately secured prior to secuting the compensatory measures. This issue is

'

considered an Inspection Follow up item (No. 50 295/97022 06) pending NRC review of

the licensee's completed investigation and conective actions.

c.

Conclusion

The inspectors concluded that the security personnel inappropriately terminated the

compensatory measures for the degraded vital area banier.

81.2

inattentive Secunty Officers

.

a.

Insoection Scope (71750)

.

The inspectors reviewed the circumstances surrounding two security officers who were

inattentive while standing watch. The inspectors interviewed operations and security

personnel and reviewed app lcable procedures and documentation including Zion Station

Approved Security Program (ASP) OP-003, " Attention To Duty,' Revision 5.

b.

Observations and Findinog

On September 23,1997, a security officer identified that another security officer was

.

.

asleep while standing watch at the Unh 2 auxiliary electric equipment room. The security

.

officer had been stationed to control access to the room while the licensee was

conducting an investigation into the loss of instrument bus 213 (See Section 01.3).

On October 7,1997, a security supervisor identified that a security officer was inattentive

18

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while performing duties as a compensatory measure. The security post had been

established as a corrective action to the degraded vital area barrier event on

September 22,1997 f,See Section 81.1). Although the licensee had established the

security post, during the time that the security officer was inattentive, the compensatory

measure was not required since the vital Srea barrier was intact.

In each case, after finding the inattentive security officer, the licensee searched the area,

relieved the security officer from duties, and commenced an investigation. This issue is

corisidered an Inspection Follow-up item (50-304/97022-09), pending NRC review of the

licensee's completed investigation and corrective actions.

c.

Conclusion

The inspectors concluded that the security personnel were inattentive to their assigned

duties.

(

V. Manaaement Meeti_nnt

X1

Exit Meeting Summary

The Inspectors presented the inspection results to members of licensee management at

the conclusion of the inspection on October 10,1997. The licensee acknowledged the

findings pressented. The inspectors asked the licensee whether any materialc examined

during the inspection should be considered proprietary. No proprietary information was

identified.

19

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PARTIAL LIST OF PERSONS CONTACTED

j

Licensee

R. Starkey, Station Manager

D. Bump, Restart Manager

R. Godly, Regulatory Assurance Manager

F. Higgins, Work control Manager

E. Katzman, Radiation Protection Manager

T. Luke, Site Engineering Manager

i

T. O'Connor, Operations hlanager

L Sdwneling, Training Manager

R. Zyduck, Quality and Safety Assessment Manager

K. Dickerson, Executive Assistant to Site VKm President

T. Saksefski, Executive Assistant to Site Vice President

R. Davey, Assistant Site Engineering Manager

R. Landrum, Shift Operating Supervisor

T. Marini, Quality and Safety Assessment AudN Supervisor

G. Ponce, Site Construction Superintendent

M. Bittman, Operations

R. Budowie, Operations

B. Knopper, Operations

M. Mason, Operations

D. Noldin, Operations

C. Stiles, Operations

8. Mehler, Engineering

B. Mammoser, Engineering

D. Beutel, Regulatory Assurance

F. Jones, Regulatory Assurance

L. Holde Nuclear Ucensing

N89

E. Cobey, Acting Senior Resident inspector

D. Calnoun, Resident inspector

IQUE

J. Yesinowski, Resident inspector

.

20

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_ _ _ _

LIST OF INSPECTION PROCEDURES USED

IP 37551

Engineering

IP 61726

Surveillance Observations

IP 62707

Maintenance Observation

IP 71707

P ani Operations

IP 71750

Plant Support Activities

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-295/304-97022-01a

VIO

Failure of non-licensed operator to retum the OA fire pump

to service in accordance with the OOS program

50 295/304 97022-01b

VIO

Failure to maintain an EDG starting air valve in the required

OOS position

50 295/304-97022-01c

VIO

Failure to place and maintain a RHR valve in the required

OOS position

50 295/304-97022-02a

VIO

Failure to provide appropriate guidance for testing the

autostart inhibit circuitry for the DC CC pump

50-295/304 97022-02b

VIO

Failure to provide appropriate guidance for operator

resporm to a loss of instrument bus 213 event

50-304/97022-03

VIO

Failu to stablish nuclearinstrumentation power range

trip setpoint in accordance with tha LSSS

50-304/97022-04

VIO

Failure to maintain the minimum number of operable power

range trip channels or place too unit in hot shutdown in

accordance with TS

50-304/97022-05

NCV Failure to retain calibration records in accordance with TS

50-295/304-97022-06

URI

Review of the licensee's evaluation of the containment

thermal stress during a MSLB accident

50 295/304-97022-07

URI

Review of the standby instrument air compressor capacity

test results and the licensee's corrective actions

50-304/97022-08

IFl

Review the licensee's investigation and corrective actions

for the degraded vital arest banier

50-304/97022-09

IFl

Review the licensee's investigation and corrective actions

for the inattentive security officers

Closed

50-295/304-97016-09

URI

Review of licensee actions to resolve the power range rate

trip tolerance discrepancy

50-304/97022-05

NCV Failure to retain calibration records in accordance with TS

21

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._

Qiscussed

50-304/97001

LER

Unit 2 instrument bus perturbation caused by a short circuit

occurring during 2C accumulator level transmitter

modification instaliation resulted in ESF actuation

50-235/304-97019 %

URI

Review of the licensee's investigation and corrective

actions for the zebra n.ussel fouling of the SW system,

including the licensee's basis for concluding that the 2B

EDG was fully operable with significant heat exchangar

fouling

22

.

.

UST OF ACRONYMS USED

AOP

Abnormal Operating Procedure

CC

Component Cooling Water

CIV

Ch isolation Valve

DRP-

Division of Reactor Pro}ects

EDG

Emerge:wy Diesel Generator

ESF-

Engineered Safety Feature

IDNS

lilinola Department of Nuclear Safety

IFl

inspector Follow-up item

IP

inspection P.ooedure

LER

Ucensee Event Report

LSSS

Umiting safety System Setting

MSLB-

Main Steam Une Break

NCV

Noncited Violation

NRC-

Nuclear Regulatory Commission

NGO

Nuclear Station Operator

OOS

Out-of-Service

OSP

Operating Special Procedure

POR

Public Document Room

PlF

Problem identification Form

PT

Periodic Test

RHR

Residual Heat Removal

8 01_

System Operating instruction

i

SW

Service Water

TS

Technical Specification

URI

Unresolved item

VCT

Volume Control Tank

VIO

Violation

l

l

23

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