ML20202H858

Insp Rept 50-341/97-14 on 970923-1107.Violations Noted. Major Areas Inspected:Operations,Engineering,Maintenance & Plant Support

ML20202H858
Person / Time
Site:	Fermi
Issue date:	01/03/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20202H837	List: ML20202H831 ML20202H853 ML20202H858
References
50-341-97-14, NUDOCS 9802230035
Download: ML20202H858 (31)

See also: IR 05000341/1997014

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U.S. NUCLEAR REGULATORY COMMISSION

REGION 3

%

Docket No.: 50 341

License No.: NPF-43

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Report No.: 50 341/97014(DRP)

Licensee: Detroit Edison Company (DECO)

Facility: Er,rico Fermi, Unit 2

Location: 6400 N. Dixie Hwy.

Newport, MI 48166

Dates: September 23 through November 7,1997

Inspectors: G. Harris, Senior Resident inspector

C. O'Keefe, Resident inspector

G. Cashatt, Technical Training Specialist

Approved by: Bruce L. Burgess, Chiel

Reactor Projects Branch 6

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EXECUTIVE SUMMAF<Y

Enrico Fermi, Unit 2

NRC Inspection Report 50 341/97014(DRP)

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

plant support. The repert covers a six week period of resident inspection. During this

period, tiie plant was shut down for a sixteen day mid cycle outage and started up again

without any personnel errors. Major outage work included sipping the entire cose,

replacement of two leaking fuel bundles, safety relief valve replacement, and performance

of various surveillance tests.

QDerationg

The inspectors concluded that operators continued to exhibit improved performance

in monitoring plant conditions. Personnel on rounds continued to be effective in

identifying and reporting problems. Supervisory presence in the field for operations

increat;d, partly as a result ci having reduced the administrative burden in the

control room. inspectors identified concems with a repeat problem involving

inadvertent deenergization of equipment, and lack of documentation of entries into

allowed Technical Specification (TS) exceptions with limited time Juration. Section

01.1)

Both startup and shutdown evolutions were performed smoothly and without error.

Licensed operator trainees in the control room were properly supervised and

contributed positively to crew performance. Briefings were frequent and effective.

(Section 01.2)

The reactor vessel pressure test at the conclusion of the mid-cycle outage was

performed expeditiously in a coordinated and controlled manner. Preparations,

particularly the use of the simulator, were effective in minimizing the timo spent with

shutdown cooling secured during a relatively high decay heat condition. However. .

the inspectors concluded that distractions from the test were not effectively

minimized in the control room. (Section 01.3)

The H insee identified that operators violated a TS required situstional surveillance

ched af electrical power source operability, when it was completed nine minutes

late. This TS violation is of additional concern because it is similar to a recent failure

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to verify electrical power availability documented in Inspection Report 50 341/97007,

Prompt corrective actions significantly raised the visibility of TS actions among

operators. -(Section 01.4)

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The licensee was able to reduce the number of Limiting Condition for Operations

(LCOs) entries by maintaining good equipment performance and by operations staff

actively pursuing resolution of all LCO issues and holding organizations accountable

for timely resolution. (Section O2.1)

Maintenance

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The inspectors identified that the standby liquid c)ntrol system configuration

challenged operators while performing surveillance testing, and that the high

pressure coolant injection surveillance test procedure did not include guidance to

pump down the

suppression pool. Coordination of switchyard 'nalntenance with ofisite personnel,

though improved over the last several monthP, continued to need additional .

Improvement. (Section M1.1)

The mid cycle outage was planned in greater detail than past outages, resulting in

better reviews, more complete preparations, and few schedule-related problems.

Problems observed during the previous refueling outage were observed to have

been effectively corrected. Teamwork and coordination were evident in identification

of equipment problems and performance of 'efueling floor activities. Outage

management personnel effectively communicated the results of risk analyses tn the

entire site. These improvements resulted in completing an a90ressive outage

schedule slightly ahead of schedule with a minimum of problems. (Section M1.2)

Enaineerina

The inspectors were concemed that the licensee did not formally evaluate and

document the operational impact cf the potential failure of selected solenold

operated valves remaining in service. Consequently, the licensee implemented

additional measures to pellodically verify operability of the affected valves. The

licensee's corrective action ofincreasing surveillance of selected systems was

acceptable. (Section E1.1)

Plant Support

The inspectors did not identify any specific issues in the area of plant support.

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Report Details

Summarv of Plant Status

The plant began this inspection period at 92 percent power. Power was reduced to

57 percent on September 24-20 for flux suppression testine !n responso to a second

fuelleak. A pinhole leak was determined to exist in a bundle in the center cell, and

one control rod was inserted to loca'ly suppress power. Power was returned to 93

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percent until the plant was shut down on October 3, for a planr.ed mid cycle outage.

The outage was inltlated to sip the entire core, replace leaking fuel bundles, replace

and test safety relief valves, and perform a number of surveillance tests to support

extending the date of the next refueling outage. The plant was restarted slightly

' ahead of schedule on October 17 and the generator was synchronized to the grid on

October 19. The plant was operated at c. near 96 percent power for the remainder

of the inspection period, except for a brief power reduction during October 28 29 to

repair several hot spots on 345 kV switchyard bus connections.

LDporationg_

01 Conduct of Operations

01.1 Conduct of Operations - General Comments

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a. Inmection Scope (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent reviews

of ongoing plant operations in the control room and in the field,

b. Findinas and Observallons

The insr '. ors r led that Nuclear Shift Supervisors (NSS) were active in

observing plant conditions and work in progress throughout the outage. On a

number of occasions, the NSS identified equipment problems during tours.

The inspectors noted that supervisory tours were a direct benefit to the shift,

and were a positive result of having reduced the administrative burden in the

control room when most work control activities were assumed by the Work

Control Nuclear Assistant Shift Supervisor (NASS). Also, the licensee

improved work coordination and allowed the NSS to become familiar with the

status of work and plant conditions by assigning NSSs to spend their first day

back from time off working in the outage management conference room.

The inspectors noted during turnover briefs and through reviews of Condition

Assessment Resolution Documents (CARDS) and logs that operators and

other licensee personnel on rounds were effective in identifying problems in

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the plant For example, a non licensed operator identified a low temperature

condition associated with an idle chiller in the control center heating,

ventilation, and air conditioning (CCHVAC) system. The system was promptly

declared inoperable and a faulty temperature switch was repaired. In another

example, a radiation protection (RP) technician on rounds reported that the

primary containment atmosphere monitoring system pump was making an

abnormal sound. The pump was promptly declared inoperable and repaired.

Throughout the outage, the licensee staff identified equipment problems

effectively. This is further discussed in Section M1.2.

The inspectors identified two instances where operators entered TS

exceptions with specific time frames without documenting the entry. During

the plant shutdown on October 3, the inspectors observed that the licensee

began de-inerting primary containment with the reactor operating above 15

percent power. -Technical Specification 3.6.6.2, applicability statement B,

allowed the licensee to de inert primary containment within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before

reducing power below 15 percent. The inspectors observed that this limited

time exception was entered but not noted in the logs or on a lim! ting condition

for operations (LCO) sheet. Additionally, on October 11, the inspectors noted

that the operators swapped divisions of shutdown cooling. An exception to

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TS 3.9.11.2 allowed removing the shutdown cooling pump from operation for

up to two hours per eight hour period. Again, this limited time TS action was

not documented. The inspectors were concerned that these TS entries into

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allowed exception conditions with specific time frames were not adequately

documented to allcw tracking. This issue will be tracked as an inspection

followup item pending inspector review of licensee actions in response to

these observations. (IFl 50-341/97014-01)

On October 7, operators inadvertently deenergized the west station air

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compressor, necessitating entry into the abnormal operating procedure for

loss of station air. Prompt operator actions avolded unacceptably low air

pressure. Operators wrote CARD 97-11186 to document the event and track

corrective actions. The licensee concluded that the load list had not been

properly updated to clearly list the compressor when it was instalkd in August

1996,- The inspectors noted that this was similar to previous problems with

inadvertent deenergizing loads that occurred during motor control center

fused disconnect switch lubrication efforts in March-April 1997. The licensee

instituted similar corrective actione for both events. The methcd used by

operators to determine the impact of opening a breaker or switch relied upon

, limited review of documentation that included incomplete information. For the

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instances referred to, all unintentionally deenergized eqiilpment was non-

safety related. This will be tracked at an inspection followup item pending

further inspector review of the adequacy of load list documentation and

operator practices in preparing for electrical outages. (IFl 50-341/97014-02)

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The incpectors reviewed Operations Night Orders and noted that several

entries had been in active status for a n"mber of days. Operations

administrative guidance suggests that active night orderc, should normally be

in effect for up to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />. The inspectors discussed their observations with f

operations management who stated that additional guidance was needed to

clarify management axpectations. The Inspectors reviewed the night orders

and noted that although most had exceeded the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> period, no

operational impact was evident.

c. Conclusions

The inspectors concluded that operators continued to er.hloit improved

performance in monitoring plant conditions. Personnel on rounds continued

to be effective in identifying and reporting problems. Supervisory presence in

the field for operations increased, partly as a result of having reduced the

administrative burden in the control room. Inspectors identified concerns with

a repeat problem with inadvertent deenergization of equipment and lack of 9

documentation of entries into allowed TS exceptions with limited time

duration.

01.2 Shutdown and Startuo Observations

a, lnspection Scope (71707. 71711)

The inspectors observed briefings and various plant evolutions associated

with the shutdown and subsequent startup from the mid-cycle outage, both in

the control room and in the field.

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b. Qbjervations and Findinas

During the plant shutdown process, the inspectors observed that operators y

effectively briefed each significant evolution. The shutdown schedule

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included ample time for each evolution. Trainees performed many of the

control room operations with qualified oparator supervision. Reactivity

controls were notably formal and controlled. Procedure use and adherence

was evident.

Similarly, the inspectors observed a careful and deliberate startup without any

personnel errors. The inspectors observed that the licensee appropriately

decided to discontinue the approach to criticality when it became clear that

criticality would have been achieved close to shift turnover time. Rod

withdrawal was also conservatively stopped while a process computer

--problem was correctedc-- The-approach to criticality was observed-to-be

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cautiouo.

The inspectors noted that control room operators exhibited an excellent

questioning attitude and took their time during both startup and shutdown No

schedule pressure was apparent dur'ng shutdown or startup. The inspectors

considered that the pre,ance of 1; censed operator trainees participating in

, control room operations for the first time during these evolutions contributed ,

positively to crew performance. The inspectors observed excellent trainee i

control and formal communications. The NSS and NASS clearly stated their  !

expectations in this regard, and were observed to be prompt in cori; ting any l

deviations from these standards. Licensee senior management we present

during both plant startup and shutdown. In addition, Nuclear Quality

Assurance (NOA) provided extensive plant restart coverage.

c. ConclusioJa

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l Both startup and shutdown evolutions were performed withuut error,

i Licensed operator trainces in the control room were properly supervised and

contributed positively to crew p:,rformance. Briefings were frequent and

effective.

01.3 Reactor _.P_assum3asssLLElP_V) Pressure Test Observations

a. inspection Jcgae ( 71707. 61726 )

The inspectors revie'Ned Infrequently Performed Test / Evolution 97 05, "RPV

Prossure Test Following the October 1997 Fuel Inspection Outage," and

associated Safety Evaluation 97-0117. The inspectors then observed the

briefing and performance of the RPV pressure test on October 15.

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b. Observations and Fintljem

in preparation for the outage, the licensee reccgqized that plant conditions

would be more challenging than during a normal refueling outage. The core

decay heat load was expected to be relatively high because almost no fuel

was expected to be replaced and because of the short outage length. As a

result of the higher decay heat load, the plant conditions required for the RPV

pressure test after reassembling the reactor vessel were examined in detail to

ensure they could be satisfied throughout the test,

in order to avoid the possibility of an inadvertent change of operational mode

due to heatup during the test, which required securing shutdown cooling flow,

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a number of changes wore made to the process. The licensee obtained the

O'fice of Nuclear Reactor Regulallon (NRR) approval of new special test

exception (TS 3.10.7) to allo'N plant temperatures of up to 212*F during the

test. Also, NRR approved a relief request to allow testing at reduced

pressure. Finally, the licensee revised the test procedure based on simulator

testing and predictive modeling.

Simulator testing was performed to allow operators to become proficient with

the use of the procedure, to test procedure enhancements based on the

results in the simulator, and to deterrnine the time required to perform the

! test. The same operators were then assigned to perform the actual test in

l the plant. Improved methods of plant temperature control and higher fill rate

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were successfully validated in the simulator.

The inspectors observed that the actual test was s.all briefed. Staffing for the

l test was appropriate. Coordination was very good among groups involved

l which allowed the time spent with shutdown cooling secured to be minimized.

l Throughout the test, the inspectors observed that engineering personnel

constantly verified that plant response matched predicted values.

l Licensed operators were distracted by several balance of plant annunciators

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which were received repeatedly. When the NASS permitted the repetitive

alarms to be left flashing, operators had to use the Sequence of Events

Recorder to determine the source of new alarms because up to seven

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annunciators were already flashing. Also, just after reaching test pressure,

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a licensed operator not associated with the test conducted two switchyard

breaker manipulations. This was done without a control room briefing and

required the attention of the NASS at a time when the test in progress was at

l its most important stage. The inspectors concluded that these distractions

were not effectively minimized,

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c. Conclusions

The RPV pressure test was performed expeditiously in a coordinated and

controlled manner. Preparations were effective in minimizing the time spent

with shutdown cooling secured during a high decay heat condition. However,

the inspectors concluded that control of annunciators and performing

switching operations during this brief test distracted control room operators

from the test.

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01.4 Missed TS Situational Surveillance Reauirement

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a. Inspection Scope (71707)

The inspectors performed an independent followup on the licensee's self-

identified violation of a TS situational surveillance requirement. The

inspectors reviewed corrective actions for the event with senior plant

management, and attended small group sessluns for operators.

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b. Findinas and ObservatioDE.

On September 25, the licensee declared Emergency Diesel Generator (EDG)

14 Inoperable due to miner load oscillations observed during surveillance

testing. Technical Specification 3.8.1.1.b, required that with one EDG

inoperable, the remaining offsite power sources must be verified to be

available every eight hours. However, on September 27, the licensee

identified that operations personnel failed to complete this verification until

eight hours nine minutes after completing the previous check. A prompt

critique determined that the situational surveillance was discussed at the shift s

turnover briefing, assigned to a specific licensed operator, and scheduled to

be completed an hour early. The licensee determined that the assigned

operator forgot, and there was no backup by other members of the shift until

five minutes before the verificatiun check was due. This event was of

additional concern due to an recent, similar, violation of TS 3.8.1.1.b. The

circumstances of the earlier violation were discussed in Inspection Report 50-

341/97007. Failure to perform verification of the availability of offsite power

was a violation of TS 3.8.1.1.b. (VIO 50-341/97014 03)

In response to this event, senior licensee management promptly conducted

small group sessions with all operators to discuss performance and

responsibilities in regard to assuring TS compliance. Management

expectations and regulatory requirements were clearly presented. The

inspectors observed excellent participation by all present and noted that

operators provided many suggestions for improving performance and tracking

of TS actions.

Among the measures impiemented was a shiftly " reflection time" meeting.

Midway through each shift, as a group, the entire operating shift reviewed

important work in progress or planned for the remaining part of the shift for

TS impact. The inspectors observed several of these meetings and

determined that the intended focus on TS actions was effectively achieved.

The meetings also had the benefit ofinvolvinn the non-licensed operators in

TS issues.

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The inspectors also determined that shift turnover briefs were more complete

in their discussion of LCOs which were in effect and were better in ensuring

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that situational surveillance requirements were discussed. However, the

Inspectors identified that turnover briefing discussions of LCOs did not include

the actions required in many cases. This was often done at the more

focussed reflection time meetings.

Additionally, the licensee modified the software on personal computers used

for log taking to include a user set alarm program for reminding operators of

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situational surveillances with short time durations,

c. p_onclusions

The inspectors concluded that the licensee took prompt corrective cctions for

the missed TS verification requirements. The involvement by senior

management in the small group sessions and the solicitat!on of suggestions

added to individual buy in by operators. Prompt corrective actions

significantly raised the visibility of TS actions among operators.

O2 Operational Status of Facilities and Equipment

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O2.1 fagirmg. red Safety Feature System Walkdowns (71707)

The inspectors used Inspection Procedure 71707 to walk down accessible

portions of the folicwing Engineered Safety Feature systems:

• Standby Liquid Control System

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Standby Feedwater

EDG 11,12,13 and Support Systems

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130/260V Battery Support Systems

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Reactor Protection System Power

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Combustion Turbine Generator (CTG) 11-1

Emergency E.iulpment Cooling Water System

Equipment operability, material condition, and housekeeping were acceptable

in all cases. Several minor discrepancies were brought to the licensee's

attention and were corrected. The inspectors identified no substantive

concerns as a result of these walkdowns.

The licensee continued work to improve the reliability of CTG 11-1. Because

this station blackout generator was out-of service for several months, the

licensee installed a temporary modification to provide blackstart capability to

the other CTGs and stationed a full time operator at the CTG yard. Additional

operators were also assigned to support work on CTG 11-1. Licensee

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management was sensitive to this manpower drain on operations, and

increased oversight of the project. At the conclusion of this inspection period, .

the licensee began a series of 50 runs of CTG 111 to demonstrate reliability

of the machine, which was expected to last a few weeks.

Equipment performance was good following the outage. The licensee was

able to maintain TS related equipment in service, resulting in o very low

number of LCOs each day. The inspectors noted that this improved

performance was due to operations personnel actively pursuing resolution of n

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all LCO issues and holding organizations accountable for timely resolution.

08 Miscellaneous Operations lasues (92700; 92701)

08.1 (Closed) Licensee Event Report 50-341/96QQ2;. Engineered Safety Fecture

actuation of torus to drywell vacuum breakers due to improper system lineup.

An operator used the wrong hydrogen recombiner system lineup during a

surveillance test such that drywell gases were pumped to the torus until a

vacuum breaker actuated. This was not immediately recognized because no

alarm function is associated with the vacuum breakers, so two actuations

occurred. The cause was personnel error due to inattention to detail by the

operator. Additionally, the licensee determined that the procedure was not

human factored well in defining preferred and non-preferred lineups. System

Operating Procedure (SOP) 23.409, " Thermal Recombiner System," was

revised to improve human factoring and clarity. Training was completed on

the event and the operator received discipline. The inspectors verified that

training was completed and that SOP 23.409 was revised to clarify the normal

and emergency system lineups. Corrective actions appeared to be adequate.

The licensee's analysis of this event identified that the operato;' inadvertently

established a system lineup that created a suppression pool bypass leakage

path for approximately one hour, in the event of a loss of coolant accident,

steam in excess of that allowed in the Updated Final Safety Analysis Report

(UFSAR) could bypass the normal blowdown path to the torus and l ail to be

condensed. The hydrogen recombiner system piping was 4 inch piping, but

TS 3.6.2.1.b, required that the total leakage between suppression chamber

and drywell be less than the equivalent of a one inch orifice at 1 psid. The

inspectors determined that the safety significance of the additional bypass

leakage flow area for the brief period it occurred was minor because it

remained within the UFSAR analyzed maximum allowable bypass leakage

area of a 7 inch pipe. Failure to meet the requirements of TS 3.6.2.1.b, was

a violation. However, this non repetitive, licensee-identified and corrected

violation is being treated as a non-cited violation (NCV), consistent with

Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-04)

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08.2 (Closed) Violation 50-341/96002 01: Failure to follow hydrogen recombiner

system operating procedure (SOP). This item in discussed in detail in

Section 08.1. Corrective actions appeared adequate to prevent recurrence.

This item is closed.

08.3 (Closed) Violation 50-341/94016-01: Failure to verify alternate decay heat

removal method. Operators failed to recognize that removal of a residual

heat removal service water pump from service necessitated entry into a TS-

required situatiotial surveillance to verify availability of an alternate decay heat

removal method within one hour and every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. The safety

significance of tho event was low because reactor decay heat was very low at

the time, and alternate methods of decay heat removal were avaHable. The

NSS and NASS involved were removed from shift duties, counseled, and

were assigned to conduct training for operators on the event. The event was

caused by three licensed operators relying on memory to determine the

applicable TS actions required, with each incorrectly concluding that no act;on

was required, in response to this event, the licensee formeri the Operations

Work Control Group to ensure appropriate categorization of work dc;uments

regarding TS impact during the work planning stages, which would then be

verified by the operating shift when work was approved to start. Shift

technical advisors were added to thn review chain for final approval of work.

Plant management communicated expectations for operator communications

and TS impact reviews to all operations personnel. Corrective actions were

completed and considered adequate This item is closed.

08.4 (Closed) Licenseo Event Report 50-341/94008: Failure to verify alternate

decay heat removal method. This was subt.1itted as a voluntary licensee

event report. This item is discussed in Section 08.3. Corrective actions

appeared adequate. This item is closed.

08.5 LClosed) Insocction Followuo Iteqd50-341/94016 04: Performance of

troubleshooting and corrective mi tenance

i during surveillance activities.

Inspectors identified that numerous fastener problems were identified and

corrected in the source rangerintermediate range monitor cabinet during a

surveillance test as a result of on the spot troubleshooting. The condition was

later evaluated and reported as being outside the design basis of the plant

because the seismic qualification was not maintained with the loose

fasteners, for which an NOV was later issued. This licensee-identified

example of loose fasteners involved several process radiation monitoring

instrumentation cabinets, and each cabinet's fasteners were subsequently

corrected through an appropriate work request. The inspectors reviewed

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troubleshooting procedures, observed troubleshooting in the field, and

discussed troubleshooting practices with various plant personnel. The

inspectors also reviewed numerous closed work packages. No additional

examples of troubleshooting or corrective maintenance during surveillance

activities were identified. The inspectors concluded that procedures

governing troubleshooting clearly required separate approval and

documentation. Based on the correction of the original loose fasteners issue

and lack of additional occurrences, this item is closed. '

08.6 (Closed) Licensee Event Report 50 341/97012 00: Automatic reactor scram

on high scram discharge volume during shutdown conditions. A licensed

operator performing a surveillance procedure prematurely reset a manual scram without referring to the scram abnormal operating procedure, which

caused an unplanned scram when the scram discharge volume subsequently

filled 00. All control rods were already fully inserted at the time of the event.

Training was conducted for all operators on this event, and the operator

involved received discipline. The Inspectors verified that training was

completed, in addition, the licensee added steps to the surveillance

procedure (24.623) to ensure the scram was properly reset per Procedure

23.010, " Reactor Protection System (RPS)." This item is closed.

08.7 C 3d) Violation 50-341/96013 01;. Failure to follow procedures for resetting

a reactor scram resulted in an unplanned scram. This event is discussed in

Section 08.6. This item is closed.

08.8 (Closed) Violation 50-341/96002-04: Improper return of EDG 14 to a standby

condition. This event was caused by improper independent verification and

failure to list all components out of the standby lineup on the tagout sheet

restoration section. The licensee conducted training on the event, proper

methods for performing independent verification, and proper methods for

equipment removal and return to service. This training included pratucal

demonstrations. Additionally, operations management created the position of

shift foreman to provide increased oversight of non-licensed operators by a

licensed operator. The foreman was expected to brief each job when

assigned. The inspectors reviewed the event critique and corrective actions.

Based upon the corrective actions and lack of repeat problems in equipment

restoration, this item is closed.

08.9 (Closed) Inspection Followuo item 50-341/97002-03: Troubleshooting

practices prirr to writing a work request. The inspectors were concerned with

the variety of methods of implementing troubleshooting under the Conduct of

Operations administrative procedure, and with the lack of documentation for

troubleshooting activities. The licensee revised Operations Conduct Maneal

Procedure 04 to add additienal requirements for documentation of the

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planned steps befo6e performing any troubleshooting activity. The inspectors

noted that this was applied to troubleshooting conducted by all personnel, not

Jbst to operations personnel. The completed troubleshooting document was

retained as part of the CARD reporting the problem and listed as a reference

in any work requests initiated to correct the problem. The inspectors

reviewed several completed troubleshooting packages, and noted that checks

and approval were clearly documented. The inspectors observed that

operations, maintenance and system engineering personnel involved in recent

troubleshooting efforts used the new method, and were enthuWastic about the ,

process and sesults. The inspectors did not identify any other concerns. This

item is closed.

08.10 (Closed) Violation 50-341/96016-02: Operators did not adequately

respond to high level in the fuel pool. Operators did not verify that the

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fuel pool manual fill valve was shut, as required in the annunciator

response procedure, because they had not ordered it open during their

shift. /he valve was found to be two turns open after the fuel pool

started overflowing into ventilation ducts. Operators were trained on

this event, including management expectations for annunciator

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response, to stress the need for determining the cause of alarms and

ensur!ng that the steps taken in response correct the condition. The

inspectors observed improved annunciator response during routine

control room obsermons and verified that training was completed.

This item is closed,

ll. Maint.spance

M1 Conduct of Maintenance

M1.1 _Qeneral Comments

a. insoection Scooe (62707)

The inspectors observed all or portions of the following work and surveillance

activities. Work practices and procedure adherence were assessed. Tagout

isolation and administration were observed and reviewed. Radiological work

practices and RP support'of work were observed. Work packages were

reviewed for completeness and adequacy as well as plant impact and TS

action implementation requirements. Surveillance procedures were reviewed

and compared to TS, the UFSAR, and system design basis documentation to

, ensure requirements were being properly tested.

'

-

Troubleshooting of Reactor Water Cleanup Pump B

-

Scram Time Testing of Control Rod Drives

14

.. .

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

+

Shutdown Margin Surveillance Testing

In core Sipping and Vacuum Sipping of Fuel Bundles

Reactor Vessel Head Tensioning Activities

+

Bus 72F.C Undervoltage Surveillance Testing

Safety Relief Valve Surveillance Testing

Drywell Torus Vacuum Breaker Operability Surveillance Testing

Control center heating, ventilation, and air colditioning (CCHVAC) Duct

LeakageTesting

-

Flux Suppression Testing

Emergency Diesel Generator (EDG) 14 Governor Troubleshooting

High Pressure Coolant Injection (HPCI) Pump and Valve Operability

Surveillance

+

Preheater Drain Cross-Tle Valve Repalts

Logic System Functional Test of Bus 72EA and 72EB Undervoltage

Circuits

+

Feedwater Suction Strainer inspections

+

Reactor Pressure Vessel (RPV) Testing

• Core Shutdown Margin Verification

Corrective Maintenance Breaker Disconnect Hot Spot Repairs

Standby Liquid Control (SLC) Pump and Valve Operability Surveillarce

Test

.

Emergency Diesel Generator (EDG) 11 Surveillance Test

+

General Service Water Sluice Gate Repairs

Emergency Diesel Generator (EDG) 12 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run

Control Rod Drive Housing Support Visual Inspection

+

Control center hcating, ventilation, and air conditioning (CCHVAC)

Chlorine Detection Division 1, Channel Functional Test

Shutdown Margin Verification Testing

Control Rod Scram Time Testing

-

Combustion Turbine Generator (CTG) Ground Isolation

Troubleshooting

b. Observations and Findinos

The irispectors noted an increased questioning attitude among maintenance

workers during this inspection period. Workers increasingly utilized the CARD

process to report problems that were not directly related to the work in

nrogress.

While observing the SLC pump and valve operability surveillance, the

inspectors noted that the system configuration complicated test performance.

The valve throttled to control pressure was located 15 feet above the pumps.

The gauge used for setting the throttle valve could not be seen by the

operator, so a second operator reported pressure readings to the operator on

15

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

.

a ladder. However, as the pressure increased, the pump noise and throttling

noise increased to the point where communications became difficult. Also,

the inspectors noted that operators were unable to properly set up the step .

ladder used because the "A" pump prevented using all four legs. The ladder

was propped against a concrete lip at the bottom and leaned against a pipe

support at the top. Also, the length of the ladder made it difficult for the

operator to reach the valves.

During the HPCI Surveillance (24.202.01) on September 29, the inspectors

noted that operators operated the torus water management system to pump

down the suppression pool at 450 ppm in order to maintain suppression pool

level within TS level limitn with the HPCI system running. The inspectors

v. ele concerned that HPCI valve seat leakage could be contributing to the

suppression pool water input. The inspectors discussed this observation with

a performance engineer, who was able to demonstrate by rough calculation

that the steam input to the torus closely matched the pumpdown rate, so

valve seat leakage into the torus was unlikely. However, the inspectors noted

that surveillance 24.202.01 did not specify running the torus water

management system in order to contral suppression pool water level. The

inspectors also noted that the surveillance test was delayed two hours

because test equipment problems were not identified until just before the test

was to start.

During routine oil analysis on EDG 12 following a 41 hour4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> surveillance run,

the licenses identified a marked increase in the severe wear index for the

outboard generator bearing. Vibration monitoring and temperature trending

for the bearing indicated normal bearing performance. The licensee

conducted a bearing inspection with the vendor present and conservatively

decided to replace the bearing due to observed minor but unexpected wear,

even though the bearing had only accumulated about 100 run hours since it

was last replaced.

During the mid cycle outage, the licensee was able to correct a number of

challenges to operators, inc* "ag replacing the seal on the "A" reactor ,

recirculation pump, several e ol rod position indication probes, and

Intermediate Range Monttor ' However, the licensee did not correct seat

leakage in the reactor water cleanup blowdown valve, so operators continued

to respond to repeated high pressure alarms for the blowdown line. Also, the

south reactor water cleanup pump seal and impeller were replaced during the

outage, but pump problems mntinued to challenge operators. The pump

capacity was reduced, and ne seal was runninp above its clarm temperature.

Shortly after the alarm setpoint was raised, the temperature indication failed.

System engineering and inaintenance personnel continued to work to resolve

these issues at the conchslon of this inspection.

_ __

16

.

!

Fonowing generator synchronization at the conclusion of the outage, the

licensee identified that several of the high temperature connections in the

Division 2,345 kV switchyard were utill present. A licensee investigation

revealed that offsite personnel assl0ned to refurbish the connections had only

worked connections with more than 1 mV drop for an applied 100 amp

current. As a result, the licensee reduced power on October 28 29 in order to

correct the remaining high temperature connections. The licensee

determined that inadequate control of work between the site staff and offsite

work group contributed to workers deciding the connections were acceptable

even though they had been identified as operating at high temperature under

load. As discussed in inspection report 50 341/97013, coordination of

switchyard maintenance with offsite organizations had improved over the last

several months.

While observing leakage testing of CCHVAC ductwork on October 6, the

'

inspectors observed that test engineers did not comply with work request

precautions. Specifically, Work Request 000Z971023 directed workers to

hang a safety caution sign over open duct access plates and reinstall eccess

plates when work was delayed or stepped. The inspectors observed that

signs were not hung and access plates were not reinstalled during work

stoppages until the omissions were pointed out by the inspectors. These

deficiencies were observed to have been corrected during subsequent

observations of the work. During testing, the licensee identified that one of

the dampers tested had a loose set screw on the positioner. The inspectors

observed that the licensee promptly inspected all eppropriate system dampers

and did not identify any similar problems.

The inspectors reviewed documentathn from the recent turbine building

heating, ventilation, anri air conditionir g (HVAC) system outage. The non-

safety system outage was terminated when excessive temperatures were

identified in the turbine building , " tunnel area. Later, as a result of

inspector questioning, the licensee G+ 'ined that resistance temperature

detectors used to provide a Main Sterm isolation Valve (Group I) closure

were affected by the high temperatures. An operability evaluation by the

licensee determined that the original environmental qualification life o' the

components had been considerably shortened as a result of operating at

higher ambient ten.peratures than analyzed, in response, the licensee

performed additional analysis that demonstrated that the affected components

remalt.ed operable with a reduced life. At the inspectors' request, NRR

reviewed the licensee's operability evaluation and agreed with the licensee's

operability conclusion. The inspectors further reviewed a safety evaluation for

the high temperatures in the turbine building. The inspectors noted that the

safety evaluation did not recognize that safety related equipment in the

turbine building could be adversely affected by the high temperatures. The

57

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_

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

licensee agreed with this observation and corrected the evaluation. The

licensee also agreed with the inspectors' conclusion that additional emphasis

is needed in the assessment of operational and safety impact resulting from

non safety system outages. The

inspectors will follow the licensee's conective act!ons to address the

assessment of non safety system outage impact. (IFl 50 341/97014-05)

Further discussion on the conduct of maintenance activities can be found in

Section M1.2.

c. Conclusions

The licensee improved plant material condition and corrected a number of

operator chall"nges due to equipment proibms. However, severat

equipment related challenges remained. The inspectors identified that the

SLC system configuration challenged operators while performing surveillance

testing and that the HPCI surveillance test prncedure did not include guidance

to pump down the suppression pool despite the significant inventory added to

the pool Coordination of switchyard maintenance with offsite personnel,

though improved over the last several months, continued to need additional

improvement.

The inspectors noted that during the turbine building HVAC system outago,

turbine building temperatures rose to within 10 degreet of the trip setpoint for

Main Steam Isolation Valve (Group 1) closure. The licensee also agreed with t

the inspectors' conclusion that additional emphasis was needed in the

assessment of operational and safety impact that re: nit from non safety

system outages. This will be tracked as an inspection followup item pending

further review of corrective actions. (IFl 50 341/97014-05).

M1.2 Outage Observations

a. Inspection Scope (62707. 60710)

The inspectors reviewed the outage schedule and work scope, defense in

depth plan, and an Independent Safety Engineering Group (ISEG) evaluation

of the outage plan. Licensee adherence to the defense in depth plan was

verified daily by control room observations and attending outage meetings.

Work and refueling / sipping activities listed in Section M1.1 were observed and

are discussed further.

b. Observations and Findinas

z b.1 Refuel Floor Activities

18

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

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

Refueling floor activities were planned in detail. This critical path sequence

included sipping all fuel bundles in the core to identify and replace leaking

bundles. The inspectors observed that although refueling activities had never

been critical path during previous outages, the licensee was able to complete

all activities in record time without error.

Supervision of activities was improved by using two refuel floor coordinators

and two senior reactor operators on each shift. Additionally, ona of the

refuelmg floor coordinators was assigned to frequently assess foreign material

exclusion practices. Coordination was observed to be excellent on the

refueling floor and with the control room. Refueling floor work was delayed

only once due to other plant activities.

The inspectors observed that appropriate radiological precautions were taken

for the fuel leaks. These included venting the reactor vessel through a high

efficicncy particulate air filter unit to the standby gas treatment suction,

limiting the number of personnel on the refueling floor when moving the

leaking fuel bundles, and planning the response to the potential airborne

release on the refueling floor. When a slight airborne release occur ed at the

start of sipping one of the leaking bundles, RP personnel 8-mpled the air,

_

promptly calculated the dose from the airborne release, and notified each

person present about the results (less than 1 mrem each). Radiation

protection support of refueling floor work was observed to be excellent, and

was further documented in Inspection Report No. 50-341/97015.

The licensee planned to further review the refueling process to identify

additional ennancements and opportunities for dose savings. The licensee

extensively recorded video observations of work in progress. The inspectors

noted that the licensee utilized high quality cameras to monitor work progress

and reduce dose. This, however, did not reduce the direct supervision.

The inspectors observed that fuel moves were proparly communicated to and

tracked by control room personnel. The senior reactor operator directing the

core alterations was present on the refueling bridge. Communications and

conduct on the refueling bridge exceeded the standard observed in the

control room.

The inspectors observed that licensee corrective actions for problems

involving refuel floor activities during the previous refueling outage were

uniformly effective. The entire evolution was conducted without a personnel

error or procedure adherence problem. Dose was considerably lower than

predicted for the evolution. Fuel pool level and water inventory were carefully

19

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

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

monitored by operators. Head tensioning and subsequent operational mode

change were very controlled. This issue is iJrther discussed below in

Sections M8.1 and M8.2. Refueling bridge reliability was effectively improved

under the Maintenance Rule system improvement plan, and the reliability was

clearly established before the outage began. There were no schedule

interruptions due to refueling bridge problems during this outage.

b.2 Work Control

Outage management effectively limited the outage work scope, with emergent

work added on a strictly controlled basis. The inspectors observed that

virtually all of the work scope additions were handled by the Fermi Integrated

Resource Support Team; therefore, the work additions did not impact any of

the planned work.

The inspectors noted that the outage schedule was planned in greater detail

than in previous outages. All surveillance tests were scheduled prior to

starting the outage, in contrast to past practice where the tests would be

added to the schedule only a few days ahead of the work. The new practice

resulted in cetter scheduling of manpower, particularly in operations. The

inspectors noted that the late addition of surveillance tests had previously

challenged ISEG's abikty to review surveillance tests to determine their impact

on the defense in depth plan. The inspector's review of overtime identified

that the operations department had virtually no unscheduled overtime during

the outage, an issue which has been a challenge in the past. The better

scheduling also resulted in virtually eliminating problems in meeting required

plant conditions for surveillance tests, which wa9 a problem that was

observed a number of times during the last refueling outage, as documented

in Inspection Report No. 50-341/96013(DRP).

Outage preparations included a new practice of preparing all tagouts and

scaffnld requests prior to the outage. The inspectors did not identify any

scaffold location or approval discrepancies during this outage, compared to

numerous problems identified during the previous outage. Few tagout

problems occurred during the outage.

b.3 Risk Management

The inspectors reviewed ISEG Report 97-014 on the mid-cycle outage scope

and schedule review. The ISF.G review was detailed and properly focussed

on safety. The ISEG identified a number of concerns in their initial review,

which were adequately resolved by the licensee staff. The inspectors' review

of the schedule and the resolution of ISEG's concerns did not identify any

additional concerns. Due to the limited work scope, the licensee was able to

20

.

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

maintain nearly allimportant power sources, decay heat removal systems,

and reactor vessel fill systems available throughout the outage. This resulted

in excellent defense in depth coverage, and fulfilled the guidelines set forth in

Operations Department Instruction (ODI) 44," Operations Outage Philosophy."

The inspectors observed that ISEG and outage management personnel were

proactive in keeping the licensee staff aware of the impact of the higher

decay heat loads than during a normal refueling outage. This was of

paiticular concern for the reactor vrssel pressure test and is discussed in

Section 01.3.

The ilcensee utilized a software program for evaluating shutdown risk,

Operational Risk Assessment and Management (ORAM), en a trial basis

during this outage. This was performed in parallel with normal manual risk

assessment. The results of this trial were generally positive and resulted in a

number of plant model refinements. Outage management personnel

effectively communicated the results of the ORAM analyses to the entire site

by posting color graphs and brief discussions of the critical work impact on

defense in depth at various locations throughout the site. The licensee

planned to continue to seek industry experience with this risk acsessment tool

before further implementation of ORAM.

The inspectors reviewed the new ODI 44. This document formalized past

practices and delineated operations management expectations in detall. The

inspectors considered this document to be a significant addition that

adequately covered the topic. The inspectors observed that adherence to

ODI 44 was good, although adherence in one minor inspector identified case

was not possible due to the ODI being overly restrictively worded. ,

b.4 Conttactor Control

During the previous refueling outage, the licensee had a number of contractor

control problems. During this outage, the licensee relied almost exclusivq

on site personnel to perform scheduled work, with refueling and fuel sipping

being the significant exceptions. The licensee utilized a number of offsite

Detroit Edison personnel to supplement the site work force. The inspectors

observed that the control of visiting workers was excellent during this outage.

Site supervision for visiting workers was observed to be very active at work

sites. Site access training was modified to include contractor control issue

lessons leameo from the previous refueling outage. Pre-job briefs for visiting

21

.

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

workers were observed by insprctors to stress the need to ask questions of

. site personnel when in doubt. '

b.S Plant Equipment Walkdowns

The inspectors nr 3d that the licensee effectively utilized seve ral teams

designated to coudcct equipment walkdowns, particularly in 'ormally

inaccessible areas of the plant. These walkdowns were scheduled ~at

appropriate times during both startup and shutdown sequences when ri- -

'N9s acceptably low but the systems of concern were hot and ~

>

During startup, this effort included a vacuum leak team whic' m + a in

ensuring the plant retumed to operation with a low air inlea' +

.cse

walkdnwns were performed jointly by operators, system eng . ., and RP

personnel. Deficiencies identified by the teams were documented on CARDS,

b.6 Excessive Safety Relief Valve (SRV) S6tpoint Jrift Raported

On October 13, the licensee identified that the SRV oilot valve setpoint testing

of pPot valves used during the first part of the cycle indicated that 11 of 15

SRVs had a setpoint that was outtide the +/- 1 percent setpoint tolerance i

specified in TS 3.4.2.1. Al! SRVs were replaced during the mid-cycle outage.

This condition was reported per 10 CFR 50.72.(iii)(D). The inspectors will

review the plant impact of this condition under 1.icensee Event Report 50-

341/96017, Revision 3.

c. Conclusions

The mid-cycle outage was planned in greater detail than past outages,

resulting in better reviews, more cemnlete preparations, and few schedule-

related problems. Problems observed during the previous refueling outage

, were observed to have been effectively corrected. Teamwork and

coordination were evident in identification of equipment problems and

performance of refueling floor activitas. Outage management personnel

effectively communicated the results of risk analyses to the entire site. These

improvements resulted in :ompleting an aggressive outage schedule slightly

ahead of schedule with a minimuni of problems.

> -

M8 Miscellaneous Maintenance issuco (32902)

M8.1 (Closed) Violation 50-341/96f17-018: Inadvertent operational mode change

due to detensioned isactor head bolt. IEs event was directly caused by a

data recording error during initial tensioning and compounded by weak

commurdcations. The licensee deterrnined that a procedural deficiency

, 22

'

l

- _ _ _ _ _ _ _ _ _

__ _ _--_______ _

v

existed, in that, the procedure for tensioning the reactor vessel head directed

an operational mode change from refueling to cold shutdown before

completing head tensioning verification. The procedure was changed to

correct this deficiency. The inspectors observed improved communication

and verification of head tensioning data during the mid-cycle outage.

Potential data discrepancies were observed to be appropriately questioned

and resolved by the refueling floor coordinators and work group. The

inspectors also observed improved communication of head tensioning status

to the control roam and a mode change conducted at the appropriate time in

the sequence. Corrective actions were observed to be appropriate and

effective. This item is closed.

M8.2 (Closed) Licensee Event Report 50-341/96018: Inadvertent operational mode

change due to detensioned reactor head bolt. As discussed in Section M8.1,

the inspectors determined that corrective actions were ade quate to address

the root causes of the event. This it' m is closed,.

M8.3 (Closed) Inspectico Foliqwuo item 50-341/95014-01: Primary containment

airlock test connection p:pe cap untested following restoration from airlock

testing. At Region Ill's request, NRR performed a formal review of the

licensee's practices of using administrative controls to ensure the cap was

reinstalled properly and not performing a local leak rate test (LLRT) after

reinstalling the cap. The NRR response concluded that the licensee's

practice was consistent with the staff's position for LLRTs for test, vent and

drain connections under Option A et 10 CFR 50, Appendix J. Thus, no

violation was considered to have existed at the time of the inspection.

. Subsequent to the inspection, the licensee adopted Option B of Appendix J.

Under that option, the cap must be tested. The inspectcrs determined that

the licensee changed the surveillance test procedure for airlock LLRTs

(43.401.206) to use a different test connection which included an additional

isolation valve Sat was Type B tested. This avoided disturbing the above

cap, so the cap was also tested during the airlock LLRT. Therefore, the -

current licensee practices were determined to be in compliance with the

applicable wRC requirements. This item is closed.

M8.4 (Closed) Violation 50-341/96013-02: Non-operations personnel operated

valve without permission, resulting .in overfilling the spent fuel pool (SFP).

'

,

The inspectors reviewed changes to Operations Conduct Manual 05, ' Control

of Equipment," and observed that the procedure strengthened the

requirements for the approval of non-operations personnel manipulation of

equipment and requiring that any exceptions be approved and logged by the

NSS. The inspectors observed that a specific briefing for refueling floor

workers was held prior to the recent mid-cycle outage, which stressed

23

s

s

_ . - -

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

_ - __-

__

controls placed on operating equipment. The inspectors verified that -

operators exhibited increased sensitivity and frequent monitoring of fuel pool

skimmer surge tank levels, and all SFP fill!ng operations were performed only

by operators. In cddition, the licensee performed training for operators,

system engineers and chemistry personnel on the Operations Conduct

Manual 05 changes discussed above. The inspectors determined by

discussions with selected individuals in these groups that the training was

effective. This item is closed.

JI1_. Enaineerina

o

E1 Conduct of Engineering

E1.1 Solenoid Operated Valve (SOV) Investiaation Update

a. Inspection Scoce (92902. 92903) ~

The inspectors reviewed the licensee deviation event report; held

conversations with maintenance and engineering personnel; reviewed

technical, industry and vendor manual information for SOVs; and held

discussions with NRR and region specialists,

b. Observations and Fitdinas_

The inspectore continued to review issues with the solenold valves discussed

in Inspection Report 50-341/97013(DRP). The inspectors reviewed the

licensee's justification for the continued o;;erability of solenoid valves that

were not planned to be replaced prior to plant restart. The licensee identified

, 14 SOVs for replacement during the mid-cycle outage, schedulad system

outages, and the following refueling outage. The SOVs were chosen based i

on mndel number, service conditions, and risk significance. The inspectors

were concerned that the licensee did not formally evaluate and docaent the

operational impact of the pc'ential failure of the valves remair.Mg in service.

Based or. NRC concerns, the licensee decided to perform increased

frequency testing of the affected SOVs to verify ongoing operability. Region-

based inspectore and NRR personnel determined that the additional

corrective aciion was sufficient to determine operability.

,

c. Concluuons

"

The inspectors were conemed that the licensee did not formally evalu ete

and document the operational impact of the potential failure of the valves

remaining in service. Consequently, the licensea implemented additional

measures to periodically verNy operability of the affected valves. The

l 24

,

A

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

- _ - _ _ ___ _ _ _-__ ____ __ __ _-_____-____-__

licensee's corrective action of increasing surveillance of selected systems

addressed the inspector's concerns.

E8 Miscellaneous Engineering issues (92902)

E8.1 (Closed) Licensee Event Report 50-341/90008: Auxiliary building basement

not fully meeting divisional separation criteria. During a plant walkdown, the ,

licensee identified that electrical cables from Division 1 Non-Interruptible Air

System did not have adequate separation from a Division 2 instrument rack.

A continuous fire watch waa posted until the Division 1 cabling could be

protected with fire wrap. The inspectors reviewed the plant modification,

walked down the completed fire wrap modification, and discussed the ,

protection methodology with a fire protection engineer. The modification

appeared to adequately restore the required divisional separation. The

licensee also performed an evaiuation to determine if additional areas existed

whare divisional separation of cables was inadequate, and none were

identified. Failure to maintain adequate separation between divisions o"the

safety related air system was a violation of 10 CFR 50

Appendix R. However, this non-repetitive, licensee-identified and corrected

violation is being treated as a non-cited viciat'on, , consistent with Section

Vil.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-06)

E8.2 (Closed) Licensee Event Report 50-341/97004-0 * Calibration of primary

'

containment oxygen monitor in de-inerted environment challenging operability

of monitor in inerted environment. The licensee determined that the TS limit

of 4 percent oxygen inside containment duriig power operation was never

,

violated because the maximum observed insrument error was based on a .

review of the nine occasions when an unanticipated non-conservative error

was introduced. The licensee's response to this discovery was discussed

with licensee senior managernent at a pre-decisional enforcement conference

on August 8,1997. As a result, it was determined that a violation occurred

due to failure to report the problem in the 'icensee's c~rective action process

and violation 50-341!97013-02 was issued. This item is closed based on the

issuance af the violation.

E8.3 (Close violation 50-341/97013-02: Failure to write a Deviation Event

Report for a non-conservative error introduced in primi y containment oxygen

monitor calibration. The licensee implemented a new corrective actions

reporting program which encompasserl a greater scope of problem reporting.

The inspectors observed that this process effectively lowered the threshold for

reporting potential problems since its impleraentation in September 1997. As

25

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..m. . _ . _ - _ _

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

,

>'

a result of not reporting this problem, past system operability was not

investigated in a timely manner and corrective actions were initially

incomplete. The inspectors noted that the licensee completed a special test

to determine the conditions under which the error was introduced. The

licensee then developed a proced re to accurately calibrate the oxygen '

l

monitor under either inerted or deinerted conditions. Training for operators

end system endneers on the event stressed the need to question and report

anomalous wjications. Corrective actions appeared to be adequate. This

item is closed.

E8.4 (Closed) Unresolved item 50-341/06010-11: Inverted Boraflex panels in SFP

storage racks not accounted for in calculation of impact of possible Boraflex

gaps. The licensee commissioned a calculation of the combined effects of

these two conditions. The inspectors reviewed License Change Request 97-

128-UFS and safety evaluation (SE 97 0112) approving the change to the ,

UFSAR to incorporate the combined calculation. The licensee analysis

concluded that under design cor. . ms, TS 5.6.1 requirements for margin to

criticality of the fuel in the SFP stc. age racks were met. The inspectors

determined that the conclusions of the analysis appeared reasonable and

a

were baseo upon conservative assumptions. This item is closed.

E8,5 (Closed) Inspection Fo!!owuo item 50-341/96010-12: Inverted Boraflex panels

in SFr- storage racks not documented in UFSAR. Th7 licensee determined

that the combined ef'ects of the two conditions dis.;ussed in Section E8.4

'

were not accounted for because the results of the eight storage cells with H

inveded pcnels were not documented in the UFSAR. Failure to maintain the

UFSAR updated with the current configuration of the SFP storage racks was

i a violation of 10 CFR 50.71. However, this non-repetitive, licensee-identified

and correctec' violation is being treated as a non-cited violation, consistent

with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-341/97014-07)

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee

management at the conclusion of the inspection on November 10,1997. The

licensee acknowledged the findings presented. Th3 inspectors asked the licensee

whether any materials examined during the inspection should be considered

proprietary. No proprietary information was identified.

X3 Management Meeting Summary

On November 6-7, J. Jacobsor., acting Deputy Director, Division of Reactor Safety,

26

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.

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

._

Region lli visited the site to observe the plant condition-and discuss licensee

' performance in preparation for the upcoming SALP, During this visit, he met with ,

various members of the licensce's staff.

I

.

.

27

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PARTIAL LIST OF PERSONS CONTACTED -

.

Licensee

S. Booker, Electrical Maintenance Superin'endent _

D. Cobb, Operat!cas Superintendent

W. Colonnello, Work Week Manager -

'

R. Delong, Superintendent, System Engineering

T. Dong, NSSS, Technical Engineering -

P. Fessler, Plant Manager

J. Greene, Superintendent of Maintenance Support

K. Howard, Superintendent, Flant Support Engineering

E. Kckosky, Superintender.t, RP and Chemistry

J. Korte, Director. Nuclear Security

R. Laubenstein, Mechanical Maintenance Superintendent

P. Lynch, NSS, Operations

R. Matthews, I&C Maintenance Superintendent

W. Miller, Work Week Manager

J. Moyers, NQA Director

N. Peterson, Acting Director, Nuclear Licensing

J. Plona, Technical Director

T. Schehr, Operating Engineer

J. Sweeney, Supervisor of Audits, NQA

NRC

J. Pulsifer, NRR Systeins Branch

A. Kugler, Project Manager, NRR

H. Ornstein, AEOD

R. Gardner, DRS, Rlli

D. Butler, DRS, Rlll

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INSPECTION PROCEDURES USED

IP 60710: Refueling Activities

IP 61726: Surveillance Observations

IP 62707: Maintenance-Observation

IP 71707: Plant Operations

IP 71711: Plant Startup from Refueling

IP 92700; Onsite Followup of Written Reports of Nonroutine Events at

Power Reactor Facilities

IP 92901: Followup - Operations

IP 92902: Followup - Engineering

IP 92903: Followup - Maintenance

ITEMS OPENED, CLOSF.D, AND DISCUSSED

Opened

50-341/97014-01 IFl TSs Entered into Without Documeatation

50-341/97014-02 IFl Adequacy of Load List Documentation

50-341/97014-03 VIO Failure to Perform Verification of Availebility of Offsite

Power

[ 50-341/97014-04 NCV Failure to Meet Requirements of TS 3.6.2.1.b

50-341/97014-05 IFl Non-Safety System Outage Impact Assessment

50-341/97014-06 NCV Failwe to Maintain the Divisional Separation in Air System

50-341/97014-07 NCV Failwe to Maintain the UFSAR Updated with Current

Configuration of the SFP Storage Racks-

Clos,ed

50-341/94008-00 LER Failure to Verify Alternate Decay Heat Removal Method

50-341/94016-01 VIO Failure to Verify alternate Decay Heat Removal Method

50-341/94016-04 IFl Performance of Troubleshooting and Corrective

Maintenance During Surveillance Activities

50-341/95014-01 IFl Primary Containment Airlock Test Connection Untested

50-341/96002-00 LER ESF Actuationi to Torus to Drywell Vacuum Breakers Due

to improper System lineup

50-341/96002-01 VIO Failure to Follow Hydrogen Recombiner SOP

50-341/96002-04 VIO Improper Return of EDG 14 to Standby

50-341/96008-00 LER Auxiliary Building Basement not Fully Divisional

Separation Criteria

50-341/96010-11 URI inverted Boraflex Panels in Spent Fuel Pool

50-341/96010-12 IFl Inverted Boraflex Panels in SFP Storage Racks not

Documented in UFSAR

29

.. . ..

.

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

50-341/96013-01 VIO Failure to Follow Procedures for Resetting a Reactor

Scram

50 341/96013-02 VIO Non-Operations Personnel Operated Valva Without

Permission, Resulting in Overfilling the Spent Fuel Pool

50-341/96016-02 VIO Operators did not adequately respond to high level in the

Fuel Pool

50-341/96017-018 VIO Inadvertent Operational Mode Change Due to

Detensioned Reactor Head Bolt

50 341/96018-00 :R Inadvertent Operational Mode Change Due to

'

Detensioned Reactor Head Bolt

50-341/97002-03 IFl Troubleshooting Practices Prior to Writing a Work Request

50-341/97004-01 LER Calibrntion of Primary Containment Oxygen Monitor in De-

inerted Environment Challenglng Operability of Monitor in

Inerted Environment

50-341/97012 00 LER Automatic Reactor Scram on High Scram Discharge

Volume During Shutdown Conditions

50-341/97013-02 VIO Failure to Write a Deviation Event Report for a Non-

Conservative Error Introduced in Primary Containment

Oxygen Monitor Calibration

t

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

t

)

LIST OF ACRONYMS USED

CARC,

CTG

EDG Combustion Turbine GeneratorCondition Asse

Emergency Diesel Generator

HPCI

ISEG High Pressere Coolant injection

3 LCO Independent Safety Engineering Group

LLRT Limiting Condition for Operation

NASS Local Leak Rate Test;ng

NCV Nuclear Assistant Shift Supervisor

NOA Non-Cited Violation

Nuclear Quality Assurance

NRC

NRR Nuclear Regulatory Commission

NSS Office of Nuclear Reactor Regulation

Nuclear Shift Supervisor

ODI

ORAM Operations Department instruction

RP Radiation ProtectionOperational R!sk Assessment and Managemen

RPV

SFP Reactor Pressure Vessel

Spent Fuel Pool

SLC

Standby Liquid Control System

O SOP

SOV System Operating Procedure

Solenoid Operated Valve

SRV Safety Relief Valve

TS

Technical Specifications

- UFSAR

VIO Updated Final Safety Analysis Report

Violation

31