ML20198A764

Insp Rept 50-482/97-22 on 971102-1213.Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20198A764
Person / Time
Site:	Wolf Creek
Issue date:	12/29/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20198A725	List: ML20198A720 ML20198A751 ML20198A764
References
50-482-97-22, NUDOCS 9801060079
Download: ML20198A764 (19)

See also: IR 05000482/1997022

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ENCLOSURE 2 l

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o U.S1 NUCLEAR REGULATORY COMMISSION j

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' REGION IV  : l

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Docket No.: _ 50-482-  ;

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L License No.: NPF 42 '

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.~ Report No.: -50-482/97-22'

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' Licensee: L Wolf Creek Nuclear Operating Corporation _  !

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Facility: - Wolf Creek Generating Station -

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Location: 1550 Oxen Lane, NE s

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~ Burlington, Kansas -

. y Dates:.  ! November 2 through December 13,1997

' inspectors; ' " J; F. Ringwald, Senior. Resident inspector e

B. A. Smalldridge, Resident inspector

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--Approved By:-

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W, D. Johnson, Chief, Reactor Project Branch B

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l' ATTACHMENT: SupplementalInformation  !

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EXECUTIVE SQM_lMflY

Wolf Creek Generating Station

NRC Inspection Report 50-482/97-22

Operations

- Safe and controlled plant evolutions were effectively sur.corted by consistent use of

three-way communication, positive operator control of plant operations, and appropriate

operator management of the control room at the controls area. On one instance,

operators allowed themselves to become involved in separute activities, such that for

approximately 1 minute, no operators were monitoring the control boards.

(Section 01.1).

- The shift supervisor made an adequate, but inadequately documented, operability

determination when a fuel oil transfer pump flow failed to meet a surveillance test

acceptance criterion (Section 01.2).

- Operators' control of the approach to and operation at midloop was well controlled.

However, licensee preparations for ruidloop operation had weaknesses in several areas

that collectively reduced the safety niargin (Section O1.3).

+ More than 20 of approximately 35 action request tags hanging on the control boards

were associated with work packages that were complete (Section O2.1).

• The inspectors noted an error indicating that the posttrip review was not thorough. The

posttrip review failed to identify that the initial 10 CFR 50.72 report contained an

inaccurate reason for the start of the motor-driven auxiliary feedwater pumps

(Section 04.1).

Maintenance

- The performance of the turbine-driven auxiliary feedwater pump improved markedly

following Refueling Outage 9 (Section M2.1).

• The inspectors and the licensee identified numerous instances where maintensrce

workers failed to remove action request tags from components as required during the

work package completion and closeout (Section M2.1).

• While the licensee properly identified and corrected the cause of the reactor trip on

November 29,1997, at the end of the inspection period, the licensee had not yet

understood the phenomena that caused the intermediate range nuclear instrument

spiking, and had, therefore, not implemented any corrective actions to prevent resetting

compensating voltage back to the range that caused the spiking (Section M2.2).

• Licensee management demonstrated appropriate control of maintenance activities by

issuing stop work orders immediately following the discovery of significant maintenance

iss;. s in order to identify and implement immediate corrective actions. This

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demonstrated that worker and plant safety was more important to licensee mariagers

than outage schedule progress (Section MS.1).

Enaineerino

. Licensee troubleshooting activities for General Electric Magne-Blast breakers following

repeated breaker failures exhibited significant weaknesses, most notably in the area of

preservation of as-found data. Desoite these weaknesses, the licensee provided

adequate assurance that the breakers were operable, following the completion of

corrective actions. The licensee's preventive maintenance generally followed the vendor

recommendations, with the exception of breaker overhaul interval. The licensee

performed as found testing which indicated that the breakers continued to meet the

vendor recommended time response requirements for new or recently overhauled

breakers (Section E2.1).

PlanLSuppad

• The training and emergency plan staff conducted an unscheduled, unannounced

emergency plan drill using an innovative technique that exercised management control,

management decision making, and other aspects of the emergency plan that normal!y do

not get exercised as effectively during typical emergency pian training scenarios

(Section PS.1).

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Report Details -

Summarv of Plant Status-

The licensee operated the plant in a refueling mode at the beginning of the inspection period,

with all fuel assemblies in the spent fuel pool. On November 27,1997, operators achieved

critical reactor operations and performed low power physics testing satisfactorily. On

November 29,1997, the reactor tripped because of intermedit,te range nuclear instrumentation

spikingi . Operators restarted the plant on November 28,1997, and reached essentially -

- 100 percent power on December 5,1997, where they operated through the end of the report

' period,

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01 Conduct of Operations

01.1 Control Room ObsgIyalions

a. inspection Scooe (71707) .

Inspectors observed control room operations on a daily basis throughout the inspection

period.

b. Observations and Findinas

Throughout the inspection period, the inspectors observed consistent use of three-way

communications between control room operators during the conduct of Refueling

Outage 9 and restart operations. The inspectors noted that during operator briefings,

operations supervision and management stressed safety and positive control of plant i

operations rather than schedule performance. The inspectors determined that this  !

contributed to safe and controlled operations, including nonroutine outage and restart

evolutions such as midloop operations, plant heatup, and reactor startup.

On November 12,1997, the inspectors identified that all three reactor operators and the

supervising operator were simultaneously engaged in activities that prevented them from

devoting their attention to monitoring the control boards for approximately 1 minute.

Adequate communication between operators would have ensured that at least one

operator retained the responsibility for moniioring the control boardsi inspectors noted

that control room operators properly communicated the transfer of responsibility for ,

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control board monitoring when they exited the controls area of the control room.

Operators also maintained a similar level of diligence during shift turnover, where they

consistently ensured that one operator on the crew was responsible for the plant that he

had no tumover duties, and focused on plant monitoring, while the remaining members

of the crew conducted turnover. However, operators have not consistently exhibited this

same level of care when the operators remained at the controls, but engaged in operator  !

activities that took their attention away from the control boards.

On November 27,1997, the inspectors observed the initial approach to criticality

following Refueling Outage 9. During this time, a management brief for physics {

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acceptance testing was also presented to control room operators. Control room

operators were attentive and responsive to annunciators and changing plant conditions

during the evolution, effectively demonstrating their plant knowledge and operating skill

in prioritizing activities. The control room staff properly controlled access to the controls

area. Only those activities that did not interfere with the reactor orsrator's ability to

monitor the control boards were authorized. - This prevented testing personnel from

interfering with the operators' ability to carefully control the approach to criticality.

c. Conclusions

Safe and controlled plant evolutions were effectively supported by consistent use of

three way communication, positive operator control of plant operations, and appropriate

operator management of the control room at the controls area. On one instance,

operators allowed themselves to become involved in separate activities such that for

approximately 1 minute, no operators were monitoring the control boards.

01.2 Inadeouatelv Documented Ooerability Evaluation

a. Insoection Scone (71707)

The inspectors reviewed one documented Technical Specification operability screening

checklist during the inspection period,

b. Observations and Findinas

On November 18,1997, the shift supervisor completed a Technical Specification

operability screening checklist to document an operability determination performed on

the Emergency Die.sel Generator B fuel oil transfer pump. During surveillance testing,

the pump flow was 40.6 gallons per minute, while the procedure required a minimum flow

of 40.9 gallons per minute. The shift supervisor determined that the observed pump flow

rate of 40.6 gallons per minute was well above the design limit of 15 gallons per minute.

The shift supervisor acknowledged that the test results indicated some pump

degradation but failed to address any bound on the degradation. No assurance was

offered in the documented operabilit) determination that the degradation would not

continue at a rate that would prevent the pump from meeting the design requirements

prior to the next test.

The inspectors reviewed the test data and concluded that the 0.3 gallons per minute

degradation was negligible in that it was within the accLracy of the tes device and

showed no indication of rapid deterioration. Consequently, the inspectors determined

that while the documentation of the operability determination was inadequate, the

operability decision made by the shift supervisor v.as appropriate.

c. Conclusions

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The shift supervisor made an adequate, but inadequately documented, operability

determination when a fuel oil transfer pump flow failed to meet a surveillance test

acceptance criterion.

O1.3 Midlooo Ooerations

a. Insoection Scone (71707)

The inspectors reviewed the licensee's preparation for and entry into midhop operations.

b. Observations and Findings

On November 12,1997, operators drained the reactor vessel to midloop operations to

remove steam generator nozzle dams and to perform o'.her work. The inspectors

reviewed the licensee's preparation for, approach to, and operation while at midloop.

The operators' approach to and operation at midloop was appropriately cautious and

controlled. However, the inspectors identified several concerns in the preparation for

midloop operations.

The inspectors questioned the licensee's hot leg vent. Licensee Procedure GEN 00-008,

• Reduced Inventory Operations," Revision 5, Section 5.15, required a hot leg vent area

greater than 17.46 square inches, which would be provided by removing one pressurizer

safety valve. The inspectors questioned wnether the foreign material entry cover

obstructed the pressurizer safety valve flange enough to preclude the existence of an

adequate vent path. The licensee initially believed that the foreign material cover

prevented the flange from providing an adequate vent path, and responded by cutting the

tape on the foreign material exclusion cover so the cover would be pushed completely off

of the flange by pressure well below the 20 psig rating of the nozzle dams. The

inspectors determined that this provided an adequate vent path. Subsequently, the

licensee evaluated their foreign material exclusion cover installation and determined that

they met the minimum hot leg vent requirement. Since the licensee's determination of

the adequacy of this hot leg vent was in response to the inspectors' questions and

occurred after operators began draining to midloop, the inspectors considered this a

weakness in the preparations for midloop operations. In response to these concerns, the

plant manager directed maintenance and operations personnel to work with engineering

personnel to obtain foreign material exclusion covers prior to the next refueling outage

that provide an adequate vent path and adequate foreign material exclusion protection.

The inspectors questioned the in-core thermocouple installation used to monitor in-core

temperatures. Procedure GEN 00-008. Section 5.17, required at least two in-core

thermocouples to be operable prior to draining to midloop conditions. Instrumentation

and control technicians plugged in one group of thermocouples which provided more

than 10 operable thermocouples. However, the technicians did not inform operators

which thermocouples were operable, operators did not ask which thermocouples were

operable, and Procedure GEN 00-008 did not require operators to identify which

thermocouples were connected and verified operable. When the inspectors asked the

operators which thermocouples were operable, the operators relied on the plant

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computer display to identify which thermocouple signal flags showed good data. As a

backupfoperators also verified that the core cooling monitoring panel provided indication -

of operable thermocouples, and technicians demonstrated the ability to monitor >

' thermocouple output locally using a bridge _ However, operators relied on the presence

of apparently valid data to identify an operable thermocouple channel on the core cooling  ;

monitoring panel. The outage shift manager did not see this as a problem and took no *

action to provide increased assurance that the operators were certain which

thermocouples were operable. Subsequent to the midloop evolution, the plant manager

directed instrumentation and controls personnel to establish a program to identify the .

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thermocouples that they connect, and provide the list of operable thermocouples to

operators as part of the formal preparations for midloop operation.

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Procedure GEN 00-008, Section 5.4.1, required either two operable diesel generators

and one operable offsite power circuit, or one operable diesel generator and two

operable offsite power circuits, with two operable residual heat remova! pumps. While

= operators met the procedural requirements, both residual heat removal pumps were

powered from a single offsite power circuit such that a single component tailure in the

one offsite power circuit would have caused the loss of both residual heat removal

pumps. The licensee acknowledged this issue and stated that they would evaluate

whether it would be practical to provide two operable offsite power circuits during future

midloop operations.

The inspectors noted that the licensee kept both personnel access hatches open while at

midloop. Procedure GEN 00 008 Section 5.16, required operators to station parsonnel

at the containment personnel access hatch whose sole purpose was to close the hatch

prior to the onset of core boiling if decay heat removal were lost. The inspectors asked

the operators to contact this person assigned the duty cf closing the hatch and learned

that this function had been assigned to the containment coordinator, a person with many

functions in addition to that of closing the hatch. The shift supervisor could not contact

the containment coordinator. After approximately 20 minutes, the shift supervisor

contacted the backup containment coordinator in the cafeteria. While tne backup

containment coordinator may have been able to get from the cafeteria to access control,

log onto an radiation work permit, don protective clothing, and shut the hatch within

10 minutes, the inspectors determined that this could not be assured. Since the

procedure required a person to be stationed at the hatch with no other duties but to shut

the hatch should it be needed, this is a violation of Technical Specification 6.8.1.1.a.

(50-482/9722-01). The shift supervisor immediately stationed a person at the

containment hatch in accordance with the procedure.

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c. Conclusions:

Operators' control of the approach to and operation at midloop was well controlled.

However, licensee preparations for midloop operation had weaknesses in several areas

that collectively reduced the safety margin.

02_ Operational Status of Facilities and Equipment

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02.1 O' utdated Control Board Action Reauest Taas ,

ac insoection Scooe (71707) t

. The inspectors questioned control room operators about the status of approximately .

35 action request tags hanging on the control boards near the end of Refueling ,

Outage 9.

b. Observations and Findina_ g

On November 10,1997, the inspectors questioned control room operators about the

status of approximately 35 action request tags hanging on control boards in the control

room. Many of these tags were over 6 months old, and during a review of the control

boards tags with an operator, the inspectors noted that the operator's knowledge of the

status of tho action request tags hanging on the control board was not current. The

- operator was surprised to find that many of the tags were still hanging when the operator

remembered that the werk had been completed. Following the review with the

inspectors, operators identified and removed more than 20 action request tags from the

control boards associated with work packages that were completed. Section M2.1 of this

report addresses action request tag removalin more detail.

c. - Conclusion

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More than 20 of approximately 35 action request tags hanging on the control boards

were associated with work packages that were completed. This situation couid

potentially be confusing to the operators.

04 Operator Knowledge and Performance

04.1 Posttrio Review Deficiency

a. Insoection Scooe (93702)

The inspectors reviewed the postreactor trip review data package after the designated

senior reactor operator signed the package recommending plant restart.

b. Observations and Findinas 1

On November 29,1997, the reactor tripped during plant restart following Refueling

Outage 9. The circumstances of the trip are described in Section M2.2 of this report.

After operators completed the posttrip review, the inspectors reviewed the data package

and found _that the initial 10 CFR 50.72 report of the reactor trip provided an incorrect

reason for the start of the motor-driven auxiliary feedwater pumps. The initial report

stated that the pumps started on low steam generator level of 23.5 percent. The ,

instrument recorder strip charts showed that steam generator levels never trended to or

below 23.5 percent. The plant sequence of events computer printout showed that the

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motor-driven auxiliary feedwater pumps started immediately after the' main feedwater

1 pumps tripped, an action expected on a reactor trip as 'a result of the feedwater isolation -

! generated by the Signal P4 with lowm T below 564*F. The licensee revised the! j{

10 CFR 50,72 report to correct the error. .j

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LThe inspectors also identified several other minor inconsistencies in the posttrip review - "

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- package. While none of the' inconsistencies represented significant missed or incorrect

L information, they collectively suggested that the posttrip review may not have been -

- conducted with the degree of attention to detail necessary to identify these

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. . Procedure AP 20-002, " Post-Trip Review," Revision 0, Section 6.6.1, requires the shift -

supervisor or appointed senior reactor operator to ensure that the event _is properly .

evaluated and analyzed. This review is to include a determination of whether all major. ,

e safety-related and other important equipment involved in the trip operated as anticipated i

or expected The failure of the appointed senior reactor operator to identify this data  !

package error related to the operation of safety-related equipment is a violation of .  :

10 CFR Part 50, Appendix B, Criterion V (50-482/9722-02). ]

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c. Conclusions - ,

- After the responsible senior reactor operator signed the posttrip review form

recommending restart, indicating that the posttrip review was complete, the inspectors

noted an error indicating that the posttrip review was not thorough. The posttrip review

failed to identify that the initial 10 CFR 50.72 report contained an inaccurate reason for

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the stant of the motor-driven auxiliary feedwater pumps,

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11. Maintenance - -

- M1 ' Conduct of Maintenance

M1.1. General Comments on Maintenance Activities

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a. insoection Scone (62707)

The' inspectors observed all or portions of the following work activities:

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'WP 123428, Task i Replace SGL 158 filters

- WP 124631, Task 6 Manipulator crane gripper troubleshooting '

STN AC-007l Task 11_-- Main turbine overspeed trip test

J SYS AL-124, Revision 4 Venting turbine-driven auxiliary feedwater pump oil ,

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The inspectors found no concems with the maintenance observed. -

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- c? Conclusions' ,

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<The inspectors concluded that the maintenance activities were being performed as

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M1.2 General Comments on Surveillance Activities

-- a; Insoection Scone (62707) -

- The' inspectors. observed all or portions of the following surveillance activities,

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STS AL.104, Revision 6 Turbine-driven auxiliary feedwater pump engineered safety - d

features response time test

'STS BB 011 Revision 16

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, Reactor coolant system pressurizer heatup cooldown;

surveillance

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. STS 1C-6158, Revision 15 Slave Relay Test K615 Train 8 safety injection

STS KJ-0158, Revision 6 . Manual / Auto poststart, synchronization and loading of - ,

' Emergency Diesel Generator NE02

STS RE.012. Revision 7 - Quadrant power tilt ratio determination

b.- Observations and Findinos .

, Except as noted in Section' M2.1, the inspectors found no concerns with the surveillances

observed.

- c. Conclusions

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- Except as noted in Section M2.1, the inspectors concluded that the r,urveillance activities

' were being performed as required. .

- M2 Maintenance and Material Condition of Facilities and Equipmertt

M2.1 Review of Material Condition Durino Plant Tours

- a. Insoection Scooe (617261-

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During this inspectior, period, routine plant tours were conducted to evaluate plant '  ;

material condition.

- b. Observations and Findinos

In saneral, where equipment deficiencies eWed, the deficiencies had been identified for

corrective action;; The following exceptions were idenbfied:

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. Following the inspectors' identification of the issue described in Section 02.1'of

- this report, the shift supervisor directed operators to review all action request tags

hanging in the auxiliary building. Operators found that work was statused as '

complete for 25 of the 67 action request tags reviewed. Procedure AP 16C-002,

• Work Controls," Revision 5, Section 6.7.1.2, requires the worker to remove the

action request tag from the field. The failure of the workers to remove the action

request tags is a violation of Technical Specification 6.8.1.a. This failure

constitutes a violation of minor significance and is being treated as a noncited

violation, consistent with Section IV of the NRC Enforcement Policy

'(50-482/9722-03).

However, because of the number of instances, the inspectors considered it

worthy of increased management attention and of discussion in this report.

Following the identification of this issue, the plant manager directed maintenance

management personnel to address each failure to remove the action request tag

with each responsible maintenance worker.

.- One of the valves operators identified with an action request tag and a closed

work package was Valve EJ V0054, Residual Heat Removal Train A containment

penetration test connection isolation valve. The action request had been dated

May 20,1997, and documented boric acid on the valve packing. The associated

. work package had been completed, but the maintenance worker failed to remove

the action request tag. The inspectors noted additional boric acid on the valve

packing and concluded that the packing continued to leak. The licensee

evaluated the valve condition and determined that the leakage was negligible

since the boric acid was orly on the valve packing and did not have the

appearance of an active leak. The NRC Architect / Engineering inspection

separately questioned emergency core cooling system leakage and will

address the significance of the valve packing leak in NRC Inspection

Report 50-482/97-201.

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. During a routine tour of the essential service water pump rooms, the inspectors

noted that Valves EF V0093 and -V0094, essential service water pump discharge

train cross tie valves, had significant corrosion on the valve bodies. The extent of

the corrosion was such that the surface of the body had a " spongy * texture.

Maintenance, quality control, and engineering personnel evaluated the corrosion

and concluded that it did not affect the integrity of the valve body. Engineering

personnel also stated that the plant painting and preservation, that had occurred

in the auxiliary feedwater, emergency diesel and emergency core cooling pump

rooms, was also planned for the essential service water pump rooms and was

scheduled to occur during 1998.

-.- The auxiliary feedwater system appeared to be in excellent condition and during

the initial testing of the turbine-driven auxiliary feedwater pump, the inspectors

noted that the pump performed as designed. The speed control and indication

was more consistent and closer to the speed indication using the hand-held

strobe tachometer, than the inspectors had seen previously. All pump

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parameters were well within their design values. The inspectors noted one area

where surface corrosion had formed o.1 auxiliary feedwater piping upstream of

/ Valves AE V0125, and -V0127, auxiliary feedwater to feedwater header check

valves. The pipe coating standard required insulated piping with nominal

temperatures above 350'F to not be coated. The piping downstream of these

check valves met this criterion due to feedwater heating. However, a band of

piping upstream of the check valve did not meet this criterion, yet the coating had

been sandad down to bare metal. Condensation on the cold piping apparently

contributed ;9 the formation of surface corrosion. Maintenance support personnel

removed the ' surface corrosion and painted the piping up to the insulation,

c. Conclusions

The performance of the turbine-driven auxiliary feedwater pump improved markedly

following Refuelirig Outage 9. The inspectors and the licensee identified numerous

instances where maintenance workers failed to remove action request tags from

components as required during the work package completion and closeout.

M2.2 Reactor Trio

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a. Insocction Scooe (93702. 62707)

The inspectors reviewed the licensee's response to a reactor trip.

b. Observations and Findinos

On November 29,1997, the reactor tripped from approximately 7 percent power, due to

spiking on Intermediate Range Nuclear instrument SE NI-35. The reactor protection

system and all safety systems responded as designed, and operators responded

appropriately.

The cause of the intermediate range spiking was determined to be a compensating

voltage setting of -88 Vde, near the vendor recommended maximum setting of -90 Vdc.

At the end of the inspection period, the licensee had not determined why the elevated

detector compensating voltage caused the spiking phenomena. The inspectors will

evaluate this further during the review of the licensee's 10 CFR 50.73 report on this trip.

In response to the trip, technicians adjusted the compensating voltage from -88 Vdc to

-70 Vdc on Channel SE NI-35. Intermediate Range Nuclear instrument SE NI-36 did not

exhibit spiking phenomena, however, the technicians reduced its compensating voltage

from -70 Vdc to -26 Vdc. These adjustments restored the compensating voltage on

Channel SE N135 to the setting used during the previous fuel cycle and adjusted

Channel SE NI-36 to match the indication observed on Channel SE NI-35.

The licensee determined that no transient occurred at the time of the trip and found no

indications of anomalies, either with the reactor or with the instrumentation. The

inspectors reviewed the licensee's nuclear instrumentation setting procedures and

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supporting calculations and found that they were consistent with industry practice. The

inspectors reviewed the licensee's troubleshooting and concluded that the licensee

thoroughly evaluated and found no problems with the intermediate range nuclear

instrumentation.

The inspectors identified one problem with the licensee's posttrip review, as discussed in

Section 04.1 of this report. The inspectors also noted that Technical Specifications

require the intermediate range nuclear instrument reactor trip setpoint to be less than or

equal to 25 percent of rated thermal power, but that operators were not familiar with what

this trip setpoint correlated to with regard to the instrument indicator, While operators

knew that the setpoint was high in the intermediate range, instrumentation and control

technicians did not provide and operators did not ask for the actual instrument reading

that correlated to the trip setpoint. As a result, operators did not have the information

necessary to manually actuate a reactor trip in anticipation of an increasing intermediate

range nuclear instrument trend toward the trip setpoint, as operators are conservatively

trained to do for all other trip setpoints.

c. Conclusions

While the licensee properly identified and corrected the cause of the reactor trip on

November 29,1997, at the end of the inspection period, the licensee had not yet

understood the phenomena that caused the intermediate range nuclear instrument

spiking, and had, therefore, not implemented any corrective actions to prevent resetting

compensating voltage back to the range that caused the spiking.

M6 McIntenance Organization and Administration

M6.1 Manaaement Control of Maintenance Activities

a. insoection Scoce (62707)

The inspectors reviewed management's response to several maintenance problems.

b Observations and Findinos

During Refueling Outage 9, several events prompted significant management concern.

During each of these events, the plant manager issued stop work orders to emphasize to

workers that these events required immediate corrective action.

The first event occurred on October 13,1997, when mechanics closed a work nackage

to replace a radwaste filter without replacing the shield plug. This issue was discussed in

NRC Inspection Reports 50-482/97-19 and -20. The second event occurred on

October 15,1997, when mechanics removed a foreign material exclusion cover on a

hand hole for Steam Generator A, which had a locked high radiation area posting

attached This issue was reviewed during NRC Inspection 50-482/97-20. The third

event occurred on October 29,1997, when rigging failed as mechanics worked on

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feedwater isolation valves. The final event occurred when the Residual Heat Removal

Pump B breaker failed to close on demand as discussed in Section E2.1 of this report.

Following each of these events, the plant manager demonstrated an appropriate level of

concern by stopping the appropriate work to determine and implement immediate

corrective actions, placing higher priority on plant and worker safety, than on outage

schedule progress,

c. ConclusiQna

Licensee management demonstrated appropriate control of maintenance activities by

issuing stop work orders immediately following the discovery of significant maintenance

issues in order to identify and implement immediate corrective actions. This

demonstrated that worker and plant safety was more important to licensee management

than outage schedule progress.

111. Enaineering

E2 Engineering Support of Facilities and Equipment

E2.1 Maane-Blast Breaker Failures

a. Insoection Scooe (37551)

The inspectors evaluated the circumstances associated with four failures of

safety-related Magne-Blast breakers to close on demand.

b. Qbservations and Findinas

On October 1, 5, and 31,1997, the Residual Heat Removal Pump B oreaker failed to

close on demand, in addition, on October 30,1997, the Component Cooling Water

Pump B breaker failed to close on demand. Following the October 31,1997, failure, the

chief operating officer initiated an incident investigation. The team completed their initial

review by November 3,1997, and presented their initial draft repcrt to the plant safety

review committee. Following the breaker failure on October 31,1997, the plant manager

issued a stop work order to prevent additional fuel movement until this issue was

understood and immediate corrective actions were implernented. In addition, the

licensee quarantined the Residual Heat Removal Pump B breaker pending

troubleshooting.

On November 1,1997, the incident investigation team formed two groups of technicians

who separately developed troubleshooting plans. The two groups then cc ,;ared their

two plans and merged the best featuras of each plan into a single plan that the incident

investigation team used in the field. The troubleshooting led the team to the positive

interlock switch, Type CR2940U310. The actuator for this switch fully depressed the

plunger, but the switch contacts had completely open continuity with 125 Vdc across the

contacts. After identifying the failed switch, the team then racked the breaker down and

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monitored the resistance across the switch contacts as they manually actuated the

switch operating plunger. As they exercised the switch, the resistance dropped to the

nominal resistance of most closed switches. When the team removed the switch from

the breaker, they then passed the failed switch sequentially to each of the seven team

members present in the field. The team reviewed the site and industry hictory and found

no similar failures of this switch. Eased on the single failure, the team did not

recommend a hardware failure analysis of the switch and did not segregate the failed

switch to preserve as-found data.

After replacing the positive interlock switch, the breaker cycled on demand more than six

times, and Residual Heat Removal Pump B passed the surveillance test necessary to

demonstrate operability. Similarly, repeated cycling and successful surveillance testing

of the Component Cooling Water Pump B also demonstrated its operability.

During the plant safety review committee meeting on November 3,1997, the committee

directed the team to ship the failed switch to an independent laboratory for hardware

failure analysis. In addition, troubleshooting on October 30,1997, identified that Auxiliary

Switch SB-12 failed on the Component Cooling Water Pump B breaker, and the

committee directed the team to ship this switch to independent laboratory for hardware

failure analysis as well.

The hardware failure analysis for the positive interlock switch from the Residual Heat

Removal Pump B breaker found housing material particles present inside the switch

body and deposits of the housing material on the switch contact surfaces. While the

exact cause of the switch failure could not be determined, the evidence suggested that

this housing material physically prevented the contact surfaces from making good

electrical contact. The hardware failure analysis for the auxiliary switch from the

Component Cooling Water Pump B breaker found evidence of contact heating and heat

induced corrosion. However, the switch had been altered prior to shipment to the

analyst, and this mcy have prevented a more accurate determination of the failure cause.

The nuclear station operator who was present in Residual Heat Removal Pump Room B

et the time of the failed attempt to start the pump on October 31,1997, heard some

noise, presumably from the pump motor. The shift supervisor documented this

informatica in the contro! room logs; however, the incident investigation team did not

pursue this report and did not determine what this noise was. The team did evaluate the

indications p,esent following the failed attempt to start the pump and determined that the

breaker main contacts did not trip free, and therefore never closed. However, the team

never pursued this report of noise coincident with the attempt to start the pump.

A second notable omission in the incident investigation team's evaluation was the failure

to evaluate the potentialimpact of the recently completed bus outage maintenance

activities on the failures of the breakers to operate on demand. There was no

consideration for evaluating the chemicals ased durirg the bus cleaning as to whether

they may have had some impact on the breaker operation. Following the inspectors'

questions regarding this omission, the team asked chemistry personnel to perform this

evaluation. This evaluation did not identify any chemicalincompatibilities, but it only

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considered the chemicals used in relationship to the switch contacts, not the switch  ;

housing material, etc. l

On October 1,1997, the troubleshooting led the electricians to believe that the problem '

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had been in the control board hand switch because they found the individual contact

blocks on the switch loose and twisted. After straightening and tightening the switch and )

racking the breaker down and back up, the breaker functioned properly and the

electricians concluded that they had found and resolved the problem. When the breaker

failed to close again on October 5,1997, more extensive troubleshooting identified that

the coritrol board switch functioned properly, but that the breaker position in the cubicle

when racked up still left the positive interlock roller out of the proper position in the 'V'

notch in the interference plate, preventing the positive interlock switch from closing.

As a result of the poor troubleshooting result on October 1, electricians developed

troubleshooting guidelines for Magne-Blast breakers that included voltage and continuity

testing with the breaker in the as found condition. Prior to these events, the standard

practice had been to visually inspect the breaker, but then rack it down prior to

performing any troubleshooting measuiements. Since this resulted in the loss of the

as found data necessary to identify the problem on October 1,1997, this change in

troubleshooting practice represented an improvement and led to the identification of the

two switch failures on October 30, and November 1,1997, These guidelines, however,

did not prevent station personnel from disturbing the positive interlock switch or from

altering the auxiliary switch after removing them from their respective breakers.

On October 1,1997, the initial evaluation of the control board Residual Heat Removal

Pump B handswitch was performed by a nuclear rhtion operator assigned to the

Fix It-Now team. This operator moved the switer. sntact stack and finger tightened the

nuts holding the switch stack together. The inspw. w questioned the appropriateness

of an operator performing these activities without spasc maintenance training and

qualifications. The inspectors determined that the licensee did not have clear guidelines

to define the appropriate roles and limits for activities performed by the various members

of the Fix It-Now team. The plant manager acknowledged this concern and indicated

that future plans for cross training will address this issue.

The inspectors reviewed the licensee's preventive maintenance program for Magne-Blast

breakers. The inspectors determined that the licensee's program addressed all the

vendor recommended activities with two exceptions. First, the vendor recommended

periodic measurements of the breaker crank shaft end play. This issue was evaluated

during NRC Inspection 50-482/95-06 and not found to introduce concerns. Second, the

vendor recommended breaker overhauls at 5-year intervais. The licensee did not

perform overhauls at this interval, but established a program to conduct as-found testing

of breakers to identify the need for breaker overhauls.

Following a reactor trip on March 8,1995, complicated by a Magne Blast breaker failure

to complete a fast bus transfer, the system engineer reviewed all Magne-Blast breakers

and categorized them relative to their operating environment, frequency of cycling, safety

and commercial significance, plant safety analysis, vendor recommendations, and

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' operating history.- This review resulted in an 18 month preventive maintenance interval )

for all safety related breakers and for 13 critical nonsafety-related breakers. The i

remaining nonsafety related breakers were scheduled for preventive maintenance on a l

3-year interval, During the preventive maintenance, electricians performed time - 1

' response testing. If the time response testing results were acceptable, then the 4

preventive maintenance was performed and the breaker returned to service, if the time -

response. testing was unacceptable, then the breaker would be removed from service for  ;

overhaul.

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c. Conclusions

Licensee troubleshooting activities for General Electric Magne-Blast breakers following

repeated breaker failures exhibited significant weaknesses, most notably in the area of -

preservation of as found data. Despite these weaknesses, the licensee provided ,

adequate assurance that the breakers were operable following the completion of '

corrective actions. The licensee's preventive maintenance generally followed the vendor

recommendations with the exception of breaker overhaulinterval. The licensee

performed as-found testing which indicated that the breakers continued to ' meet the

'

vendor recommended time response requirements for new or recently overhauled

breakers.

IV, Plant Suonott

P5 Staff Training and Qualification in Emergency Preparedness

P5.1 Innovative Emergency Pla0Erilj

a. Insoection Secce (71750)

The inspectors reviewed the performance of an emergency plan drill which provided

innovative training opportunities.-

. b. Observations and Findinos

On December 3,1997, during a licensed operator complex scenario simulator drill, the

training staff coordinated with the emergency preparation personnel to extend the drill to

the plant staff to obtain the benefit of more realistic operator training and an innovative

emergency plan drill, During this unscheduled, unannounced drill scenario, the control

room personnel would typically simulate a telephone call to the operations manager.

Instead of calling the instructor in the simulator control booth, the simulator operator

actually called or paged the operations manager. The management staff reacted as tney -

would had this been a real plant event by holding meetings, providing briefings to senior

managers, providing direction, and involving other plant staff personnel including

engineering, maintenance, and plant support personnel. When the scenario required the -

declaration of an emergency plan event classification, the drill notifications were made,

and when the event escalated to an Alert, the actual on call team staffed tne technical

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1 support center and supported the simulator control room in the same manner as they f

would during a more typical emergency plan drill or exercise.

The inspectors considered this an innovative scenario, and noted that it exercised

aspects of the licensee's emergency plan and management response in a manner

different than they are normally exercised during typical emergency plan drills._ Following

the drill, the training staff identified several lessons leamed that they plan to incorporate

into future similar training scenariosi These lessons include the inability to conduct a

management player critique, given the unscheduled nature of the scenario, and '

improved expectations for controller needs,

c. Conclusions

- The training and emergency plan staff conducted an unscheduled, unannounced:

- emergency plan drill using an innovative technique that exercised management control,

management decision making, and other aspects of the emergency plan that normally do

not get exercised as effectively during typical emergency plan training scenarios.

V. . Management Meetings

X1 Exit Meeting Summary

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

conclusion of the inspection on December 16,1997. The licensee acknowledged the findings

presented;

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

be considered proprietary. No proprietary information was identified.

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" ATTACHMENT  !

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PARTIAL Ll'ST OF PERSONS CONTACTEDi

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[M,Ifrkgus, Manager, Licensing and Corrective Action.;  ;

G; 0; Boyer, Chief Administrative Officer

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~ : O.L Maynard, President and Chief Executive Officer '

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. B. T, McKinney, Plant Manager -

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, R. Muench, Vice President Engineering)  !

tW.' B.' Norton, Manager, Performance improvement and Assessment ~

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C. C.' Warren, Chief Operating Officer q

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[" INSPECTION PROCEDURES USED =

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IP 37551'_ - Onsite Engineering

IP 61726 : Surveillance Observations

' IP 62707 Maintenance Observations

IP 71707 . Plant Operations-

iP 71750 Plant Support Activities

IP 93702 - Prompt Onsite Response to Events at Operating Power Reactors

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- ITEMS OPENED AND CLOSED  !

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Opened  ;

50-482/9722-01-- . VIO . Midloop operations (Section 01.3) -f

Posttrip review deficiency (Section O4.1) i

' 50-482/9722-02: VIO.

Failure to remove action request taga after

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?50-482/9722-03 N J 'I

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work completion (Section.M2.1) .

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Closed

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c 50-482/9714-04 URl; Spent fuel pool canal posting (closed b'y issuance of

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i .- notice of violation with NRC Inspection Report 50-'-

b _  : 482/9720)

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~' Failure to remove action request tags after work .

50482/9722-03~ NCV:  :

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completion'(Section M2.1) l

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