IR 05000010/1997019

Insp Repts 50-010/97-19,50-237/97-19 & 50-249/97-19 on 970828-1016.Violations Noted.Major Areas Inspected: Operations,Maintenance,Engineering & Plant Support

ML20203C948
Person / Time
Site:	Dresden
Issue date:	12/04/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20203C930	List: IR 05000010/1997019 ML20203C924 ML20203C938
References
50-010-97-19, 50-10-97-19, 50-237-97-19, 50-249-97-19, NUDOCS 9712160056
Download: ML20203C948 (30)

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U.S. NUCLEAR REGUI.ATORY COMMISSION REGION lll Docket Nos:

50-010;50 237; 50-249 License Nos:

DPR-02; DPR 19; DPR 25 Report No:

50-010/97019(DRP); 50-237/97019(DRP);

50-249/97019DRP)

Licensee:

Commonwealth Edison Company Facility:

Dresden Nuclear Station Units 1,2 and 3 Location:

6500 North Dresden Road Morris,IL 60450 Dates:

August 28 - October 16,1997 inspectors:

K. Riemer, Senior Resident inspector D. Roth, Resident inspector B. Dickson, Resident inspector in Training J. Roman, Illinois Department of Nuclear Safety, Resident inspector Approved by:

M. Ring, Chief Reactor Projects Branch 1 9712160056 971204 PDR ADOCK 05000010

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EXECUTIVE SUMMARY -

Dresden Nucioar Station Units 1,2 and 3

NRC inspection Report No. 50-010/97010(DRP); 50-237/97019(DRP); 50 249/97019(DRP)

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

s"; port. The report covers the period from August 28 though October 16,1997, of resident inspection augmented by staff from other sites and from the Region.

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Qgestions Several procedural inadequacies affected operators during this inspection period. The _

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procedural inadequacies were not identified by station personnel, but rather were

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self-revealing in nature. The procedures for operation of the emergency diesel Generator (EDG), response to the trip of an EDG, and operation of the fuel pool cooling systam were inadequate Operators following those procedures caused the EDG to be inoperable, caused an ESF actuation, and created a loss of spet fuel pool cooling.

Additionally, the procedum for operation of the TIP system was weak and operators were unable to operate the flP system in one of the modes specified in the procedure. In the specific examples noted above, operator performance was also weak in that the operators did not identify the procedure deficiencies before performance of the procedure.

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Operations activities were generally performed satisfactorily during this period. However,

observations by both NRC inspectors and outside observers noted severalinstances where operate performance deviated from licensee management expectations as promulgated in the Operations Standards, r

The EDG bopersbility event was self-revealing in that the knowledge deficiencies were e

not identified until the EDG tripped on low engine water pressure and subsequently unexpectedly autostarted during operators' response to the alarms. The operations staff demonstrate 1 an inability to perform the fundamental task of operating the EDG and

_ weakness in the knowledge of the automatic EDG start interlocks. Because of the

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inadequate procedures and operations staff perfonnance, an unexpected ESF actuation occurred and the safety-related emergency diess; generator was unnecessarily unavailable for more than 2 days,

The failure of the operators to follow discrete component operation procedures resulted in e

inadvertently rendering the Unit 2 EDG inoperable. While the consequences of this event were not as severe as the reector trip of July 28,1997, the cause was similar in nature in that the unit nuclear station operator (NSO) departed from the approved plan without the knowledge of the unit supervisor, The inspectors observed the licensee perform good self checking, peer review, and e

conservative decision making throughout most of '.soth high pressure coolant injection

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system operability surveillances.~ The inspectorr, identified valve leakage in the field prior to identification by the operators.

- The inspectors identified that operators were not following station procedures for racking out safety-related breakers and temporary lifting out-of-services (OOSs) for testing

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purposes. Following NRC identification of the procedural nonoempliance, th3 licensee e

noted additional examples of operators not complying v4th the OOS procedure,

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The inspectors wets concemed with a negative trend in human performance events, first documented in the prior inspection period, that occurrad during this inspection period.

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These events were both licensee and NRC identified and occurred during the

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perfonnance of routine, fundamental tasks. The licensee's self-assessments

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documenting these events appeared strong and critical.

Maintenance The inspectors noted that the licensee's overall pede,v,ews of troubleshooting and

diagnosis of the inoperable EDG was impacted by individual human-performance errors.

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The performance was similar to the incorrect diagnosis of problems on the standby gas treatment system documented in Inspection Report No. 97013.

While overall material condition of the plant has improved, material condition issues

continued to challenge plant operators. The events were primarily self-revealing and

placed the operators in a reactive mode.

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The material condition of the control rod drive system was poor. Maintenance work

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performed on the system to address some of the deficiencies adversely impacted

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operations when a control rod unexpectedly scrammed and inserted into the core.

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Enoineerina i

Initially, the data th::t the licensee used to track the rework performance indica'or was e

dependent on tne determetion of the event screening committee. The licenses recently modifisd the way the data was tracked.

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The licensee did not adequately assess the vendor's recommendations regarding the

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operation and calibration of the frequency meters for the EDG, This issue was similar to the failure to incorporate vendor recommendations into non-licensed operator rounds l

procedures for the hydrogen analyzers documented in Irr.pection Report No. 97013, Plant Support

The inspectors identified a discrepancy between actual plant radiological conditions and

posted survey maps. While no adverse effects resulted from this instsnce, tSe Iri&pectors were concemed with the potential for personnel contaminations or unnecessory radiological exposure.

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L Resort Details

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Summary of Plant Status

Unit 1 activities to support SAFSTOR were performed during this period. On September 10,

. 1997.' Unit 1 management issued a stop-wrk order based on a series of non-related personnel errors. The licensee lifted the stop wons on September 12,1997.

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- Uni; 2 began this inspection at full thermal power. With exceptions for planned testing and surveillance activities, the unit operated at or near full power throughout the inspection period.

Unit 3 began Qis inspection period near full thermal power. Full thermal power on Unit 3 was not

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achieved due to two limits: first, the control valve positions were limited to 85% open averr.ge or

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90% on any one control valve, and second the feedwater flow was limited to 9,73 Mlbm/h (instead of the approximately 9.8 Mibm/h at full power) as a result of an engineering review of the

fuel cycle analysis. The limits remained in effect until the end of the inspection period. A

_ planned down power was performed on September 8,1997, to determine the source of -

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. electro-hydraulic control fluid leakage, and to install a temporary alteration on the tooling piping

- for the main generator's rectifier to reduce stator cooling water leakage.

1 Operations

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Conduct of Operations

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01.1 General Comments (71707)

Using inspection Procedure 71707, the inspectore conducted frequent reelews of ongoing plant operations. Overall, the conduct of operations was safe and in accordance with

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procedurcs.

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I During the inspection period, events occurred or were discovered for which the licensee was required by 10 CFR 50.72 or 10 CFR 50.73 to nobfy the NRC. Some of the events and the notification dates are listed below:

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August 28 l (Units 2, 3) Unit 2/3 emergency diesel geneistor (EDG) engineered safety feature (ESF) actuation. The diesel tripped during a surveillance test, then

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restarted unexpectedly wL'n an operator reset the trip signal.

September 5 (Unit 3) High pressure coolant injection system declared inoperable due to gland seal condenser hotwell level problems.

September 9 (Unit 3) High pressure coolant injection system declared inoperable due 6

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a mechanical interlock out of adjustment. A component engineer observed that the drain dump valve was not properly aligned.

October 10 (Unit 2) Control rod 46-55 inserted to full in from fully withdrawn. The licent.ee retracted this event on October 14 after determi ing that the rod

' drift was caused by an improper torque setting for the coupling bolt, and

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not an engineered safety feature actuation.

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03 Operations Procedures and Documentation 03.1 Quality of Operations Procedures s.

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j The inspectors reviewed the role of procedures in several events, in particular, the inspectors assessed how the quality or completerr es of procedures contributed to:

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the unplanned ESF actuation of the 2/3 EDG on August 28,1997

the inadvertent securing of all Unit 3 8uel pool cociing on October 14,1997

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. the inability to use equipment referenced in a procedure for the traversing irHxn

l probe (TIP) system on October 10,1997

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Procedures for EDG Operation On August 28, a self-revealing event showed several procedural weaknesses. The

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event, an unplanned ESF actuation of the 2/3 EDG, vias a complex issue that showed weaknesses in both operator knowledge and procedures. This section of the report discusses only the procedural aspects of the event. Section 04.2 of this report describes the operator knowledge and performance issues. -The Unit 2/3 EDG was incorrectly

- operated, automatically tripped twice and automatically started once due to a combination

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- of procedural-based and performance-based errors.

The licensee reported in licensee event report (LER) 97-016-00 ("Autostart of the 2/3 Diesel Generator due to Operating Team Knowledge Deficiency") that deficiencies in j

several procedures contributed to the event. The licensee added information regarding EDG frequency meter operation to the EDG operating surveillanco test procedure

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(DOS 6600-01), and added direction to ensure that the EDG control switch was in "Stop" prior to resetting a trip.

L The licensee was required by Technical Specification (T.S.) 6.8.A to maintain the applicable procedures recommended in Appendix A of RG 1.33, Revision 2, February

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1978. Operation of emergency diesel goneators and procedures for alarm conditions i

were recommended in RG 1.33. Contrary to this, the licensee failed to maintain the '

operating surveillance procedure (DOS 6600-01) sufficiently to operate the EDG by not providing adequate procedural guidance regarding control-room indication of EDG speed

(VIO 50-237/97019-01 A (DRP); 50-249/9701941 A (DRP)) and by not providing adequate procedural guidance regarding the response to alarm conditions for the EDG

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(VIO 50-237/97019-01B (DRP); 50-249/97019-01B (DRP)). As a consequence of the inadequate operating procedure, the licensee _was unable to operate the EDG for a

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1-routine surveillance test and the EDG was made inoperable for 2 days. As a consequence of the inadequate procedure for alarm conditions, the EDG unexpectedly

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automatically started and retumed to an operating state with inadequate cooling, thereby causing the EDG to trip automatically.

The inspectors reviewed the annunciator response procedures that had been changed to address the automatic start. The licensee informed the inspectors that while gathering __

the procedures for the inspectors, the licensee noted that not all annunciator procedures

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I were changed. The licensee documented this in PIF.1997-07781. The licensee assigned an " apparent cause evaluation" to be performed to insolve the PlF, but the evaluation was not complete at the end of the inspection period.

Procedures for Fuel Pool Coeling Operstbn

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i Another procedural wealmess became self-apparent on October 14,1997. The event

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involved a loss of fuel pool cooling.

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The day-shift of operations noted an ircrease in'the Unit 3 fuel pool temperature during

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routine panel monitorir.w. The tempe.atura had increased from 90' F to 96* F. The r

licensee investigated and determined that the previous shift had swapped the train of fuel pool cooling, but had failed to provide reactor bulldog closed cooling water (RBCCW) to the oncoming fuel pool cooling heat exchanger. The licensee determined that the operations staff had performed the swap in accordance with procedure DOP 1900-01,

" Fuel Pool Cosling and Cleanup System." However, the procedure had been simplified during past revisions to direct the operators to vertfy that RBCCW was in opvation,

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whereas the procedure previously direcied the operator to verify that RBCCW was valved

into the correct heat exchanger.

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The licensee was required by Technical Specification (T.S.) 6.8.A to maintain the applicable procedures recommended in Appendix A of Regulatory RG 1.33, Revision 2, February 1978. Procedures for operation of fuel pool cooling were recommended by

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RG 1.33. Contrary to this, the licensee failed to maintain the operating procedure i

sufficiently to perform a swap of fuel pool cooling trains (VIO 50-237/97019 01C(DRP);

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50-249/97019-01C DRP)). As a conssquence, fuel pool cooling was inadvertently

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secured, and the fuel pool temperature increased from 90' F to 96* F until the error was

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detected and corrected.

Procedures for Traversing in Core Probe Operation On October 10,1997, the control room operators attempted to run a traversing incore probe (TIP) trace in response to a local power range monitor (LPRM) alarm. The operators attempted to perform Dresden operatiry procedure (DOP) 0700 06 (" Traversing incore Probe System Operation") in the automatic and manual modes. The TIP X-Y recorder did not function when the operators attempted to perform the procedure.

Subsequent discussion between departments resulted in the Operations department

realizing that the X-Y plotter is no longer used (even though DOP 0700 06 still referenced using the X-Y plotter); instead the instrument maintenance technicians provided an extemal recorder to perform the procedure. Operators consulted with nuciear engineering and performed a 10 MWe load drop to clear the annunciator and venfied thermal limits were within allowable ranges. The licensee initiated problem identification forms (PIFs) D1997-07488 and D1997-07583 to document and track closure of the issue.

in this example, the licensee did not identify the procedural inadequacy until the operators li were in the middle of performing the procedure in response to an alarming condition.

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99DelH!2n1 Several procedural inadequacies affected operators during this inspection period. The F

inspectors were concemed because the procedural inadequacies were not identified by station personnel, but rather were self-revealing !n nature. The procedures for operation of the EDG, response to the trip of an EDG, operation of fuel pool cooling, and operation

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of the TIP.;fotom were inadequate and weak. Operators following those procedures caused the EDG to be inoperable, created a loss of fuel pool cooling, and were um.bla to operate the TIP system. In the specific examples noted r.bove, operstor performance was also week in that the operators did not identify the procedure deficiencies before

performance of the procedure.

Operator Knowledge and Performance 04.1 (Unit 2. 3) Operator Performanet

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Inspection Scope (71707)

The it'spectors observed several operator activities to review and conipare performance against the publish W operator standards.

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Observations and Findinas Activities During this inspection period, the inspectors nuted several instances where the operators'

performance deviated from the site's published standards for conduct of operations:

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During the performance of the Unit 3 HPCI quarterly operability surveillance on

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September 5, the inspectors noted a high volume of activities in the control room and around the control board. The inspectors noted four lastrument mechanics, a non-licensed operator, and the oncoming control room operators by the Unit 3

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control area. The inspectors' awareness of this situation was heightened because this surveillance was being performed by a newly licensed operator (the newly licensed operator was shadowed by the NSO as required by administrative procedures). The inspectors questioned the Unit Supervisor on this situation and the Unit Supervisor responded by stating that the situation was created by the

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shift tumover in progress. The inspectors were concemed with the potential for i-unnecessary distractions while performing an evolution for the first time.

The inspectors observed the heightened level of awareness (HLA) brief for the

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2A Core Spray Pump Quarteriy Operability surveillance performed on

September 24,1997, and noted that the unit supervisor performing the brief did

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not discuss as-low-as-rossonable-achievable (ALARA) concoms. The unit supervisor did not discuss reviews,eg survey maps prior to entering the ibid nor solicit any comments from the crew regarding radiation concems as suggested in DAP 07-37, " Conduct of Heightened Level of Awareness Activities and High Impact Activities."

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On September 30,1997, the inspectors observed a power uscension to increase

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power on Unit '?. The unit had been dorated due to high seal temperature concems on the 2B reactor feed pump (RFP). During this evolution, the Unit Superviscr who was initially supervising this evolution left the horseshoe area during the power ramp and thus did not directly supervise reactivity changes using recirculation flow control. Also, the inspectors noted that the HLA for the power ramp was weak in that it failed to provide the NSos with a fixed end point for

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stopping the power ram,0. This allowed the NSO to continue raising power level i

during the initial portion of shift tumover, The inspectors reviewed PlF number D19g7-07317 written by'the Quality and -

e Safety Assessment (Q&SA) department during a Q&SA survetlance of control room activities. The PlF documented an opomtions practice that was not consistent with the Operations Department standards; operators treated certain '

" unexpected but routine" annunciators as " expected." In the PlF, the Q&SA

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department stated that the prochoe had become scoopted by both operators and -

the unit supervisors, i

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ConcluM

Operations activities were genersi / priformed satisfactorily during this posiod. However, observations by both NRC inspectors and outside observers noted several instances

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where operator performance deviated from licensee management expectations as promulgated in the Operations Standards, Each of these issues taken alone held minimal safety significance; however, the inspectors were conoemed that these examples, along with the regulatory issues discussed in Sections 03.1,04.3, and 04.5 of this report, were i

indicative of a recent decline in opwrator performance.

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04.2 (Unit 2. 3) 2/3 Ememency Diesel Generator (EDG)

a.

Inspection Scope (71707)

The inspectors reviewed an event that caused the following: operations to declare the 2/3 emergency diesel generator inoperable unnecessarily; parts to be replaced

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unnecessarily, and an unplanned autometic 'dDG start. The review included discussions with plant staff and review of the licensee event report and licensee investigation reports, including:

LER 97-016-00, "Autostart of the 2/3 Diesel Generator due tc Operating Team

Knowledge Deficiency"

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Report 237-200.g7-04400, Revision 1, "2/3 Diesel Generator LCO Extended due

to Knowledge Deficiency, Conservative Decision Making end Strobe Misuse During Troubleshooting."

i The inspectors also observed / reviewed several other operator activities and operational events to assess the adequacy of the published operations procedures.

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Observations and Findinos Eme'gency Diesel Generator Operation

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This discussion is limited to the operations performance issues only. Additional discussions regarding the 2/3 Emergency Diesel Generator are in section M1.2 of this i

report.

On August 27,1997, the licensee declared the 2/3 Emergency Diesel Generator inoperable following the discovery of a non-safety related toggle-switch installed on

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the 2/3 EDG feeder breaker that supplied the UnN 3 4160 V bus 331. The licensee subsequently evaluated the part and found N to be maaaf =Na. However, at the end of d

this inspedion period, the floonses had not completed its investigation into hev the part -

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became installed. Addstional inspector review of the parts issue will be tracked through j

LER 50 237/g7-016 00 ("Autostart of the 2/3 Diesel Generator due to Operating Team j

Knowledge Deficiency").

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The licensee replaced th:: feeder breaker, and attempted to run the EDG to prove operability. The high voltage operator (HVO) (the HVO was a non-licensed operator j

assigned tu run the EDG) reised the EDG t poed locally above the point at which the EDG room vent fan started. The HVO believed that the vent fan started at 800 rpm EDG speed; the EDG room verd fan starts before the EDG reaches 800 rpm. After the room

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I vont fan started, the HVO requested that the licensed nuclear station operator (NSO) in -

the control room read engine speed. The N80 read 60 Hz from the Unit 2 control room

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frequency meter. Unrecognized by the operations staff, the EDO speed was too low to i

energize the control room frequency meter, therefore the indication of 40 Hz was meaningless. The licensee did not read a redundant indication on Unit 3 of the 2/3 EDG

frequency. Normally, a techometer was used locally, but the HVO in the field was not suooessful in making the tachometer work.

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The EDG tripped off based on diesel engine low cooling water pressure. The HVO reset

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the local slant wnciator and the diesel autematically, and unexpectedly, started. The i

EDG again tript a due to low water pressure. 'lte control room operator then placed the 20G start swhch to stop.

During troubleshooting on August 28, operations personnel ran the EDG again. The HVO could not successfully use the hand-held tachometer to determine engine speed. The licensee had an engineer with a stroboscope to backup the HVO, but the engineer failed

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to use the stroboscope correctly. Thn licensee staff running the EDG believed incorrectly

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that the machine was at normal speed, despite the additional data that generator field

voltage had only reached 3000 veits (instead of the required 4160 volts) during the test run.

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The ll:ensee needlessly replaced the EDG cooling water pumps based on the information

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from the thre3 ncorrectly performed EDG runs and started investigating why the output

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voltage was low.

On August 29, the licensee ran the EDG while rotating equipment specialists monitored the test. The licensee found that the EDG was at 45 Hz and voltage was 3000 volts. The doenergized control room indications read 60.2 Hz and down scale on the Unit 2 and s

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Unit 3 control boards, respectively.

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On August 30, the licensee successfully tested the EDG and declared it operable.

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In summary, the evolution revealed serious problems in the licensee's ability to operate -

the safety related emeigency diesel generator. The inspectors noted that operations

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demonstrateNaknesses in the following knowledge and abilities:

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Ability to monhor EDG speed locally, i

Ability to monitor EDG speed in the control room, and

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Knowledge of the EDG interlocks that provide for automatic startup.

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The licensee assigned a thrn mon team to investigate the event and to determine corrective actions. The inspectors reviewed the licensee's report and concluded that the

report was thorough and complete. The inspootors noted that the licensee appioached i

the investigation from a broad pegootive by including interviews with operatims staff _

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not involved with the event.

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T% ikansee could not determine the spoolfic reasons wtr r the individuals l'alled to l

monitor EDG speed locally becaums the HVO and the engneer, who did not correctly determine EDG speed, had both ceased employment with the lic9nsee (not related to this

i event) prior to the licensee ceEC 4 its ir,vestigation.

The licensee found that the reason for falling to monitor EDG speed correctly in the control room was a common knowledge deficiency, and that the information was not oovered in routine training.

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I in reviewing the deficiency of kirity of the EDG interlooks that provide for automatic startup, the licensee found that the information regarding the trip and autostart logic was

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j covered in the EDO training lesson plan.

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I The NRC had previously (dontified weaknesses regarding knowledge of the EDG i

autostart logic. In July of 1997, the NRC performed on site Irdtial operator license exam i

validation and identified that the licensee personnel assigned to validate the exam were

weak in their laowledge of the role of the annunciator circurtry in the EDG autostart logic.

The licensee identified that deficiencies in several procedures contributed to the event.

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The licensee added information regarding EDG frequency motor operation to the EDG operating surveillance test procedure (DOS 6600-01), and added direction to ensure that

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the EDG control switch was in *Stop* prior to resetting a trip. Additional discussions of the role of procedures are in Section 03.1 of this report, c.

Anciusions l

The EDG event was self revealing in that the knowledge deficiencies were not identifi6d until the EDG tripped on low engine water pressure and subsequently unexpectedly L

autostarted during testing activities. The operations staff demonstrated inability to

perform the fundamental task of operating the emergency diesel generator and weakness in the knowledge of the automatic EDG start interlocks. Procedures for EDG operation and response to abnormal conditkes were inadequate because the procedures did not

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L provide guidance regarding use of frequency meters in the control room and resetting of local alarms. Because of the inadequate procedures and operations staff performance, an unexpected ESF actuation occurred and the safety-related emergency diesel i

generator was unnecessarily unavailable for more than 2 days.

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I i-The inspectors noted that the licensee's overall performance of troubleshooting and i

diagnosis was impacted by individual human-performance errors. The performance was similar to the inoonect diagnosis of problems on the standby gas treatmord system

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documented in inspection Report g7013.

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04.3 (Unit 2, 3) 2/3 Emernenov Diesepl 9enerator Alarm Troubleshootine

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lnanection tacoor 11101)

The ina' pectors reviewed the licensee's investigation into an incident during which a nuclear station operator (N80) in the control room and a norWioensed operator in tim l

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plard closed the air supply to the 2/3 EDO. This action rendered the 2/3 EDG !aoperable..

l The review included discussions with plant staff and review of:

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Prompt invest ga3on: " inadvertent rendering of the UnN 2/3 Diesel Generator e

inoperable "

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b.

Observations and Findinos

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On September 11, igg 7, an HVO reported te the UnN 2 N80 that the 2/3 EDG l

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annunciator panels were not responding correctly when the test buttons were pressed.

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operations staff in the control room, including the Unit 2 unit supervisor, discussed l

performing actions on 2/3 EDG equipmerd that would produce a control room alarm to

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determine if the alarms worked, it was agreed by the UnN 2 US and the Unit 2 N80 to

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- manipulate the limit switch only for the air start out-off valve to give an alarm in the control room.

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The HVO reported the Unit 2 N30 that the switch could not be manipulated without moving the valve. The Unit 2 NSO concurred and sent a second HVO to the 2/3 EDG room to perform an independent verification of the valve position following valve

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manipulation. The HVO then closed and re-opened the valve and the second HVO verified the actions.

,

i l

The Unit 2 NSO informed the US that closing the valve did not produce an alarm in the control room. The US recognized that closing the valve was beyond the scope of the

,

troubleshooting of manipulating the switch, and that closing the valve had momentarily rendered the 2/3 EDG inoperala.o.

,

The licensee removed the NSO and the HVO from shift and performed a prompt investigation into the event.

i The licensee used DAP 07-43, Rev. 03, " Discrete Component operation (DCO)," to

- t provide guidance for the operation of individual components where other procedural

,

guidance does not exist. The DAP addressed technical specifications and safety

.

evaluations and required appeval by the unit supervisor or shift manager for all DCOs.

The licensee was required by T.S. 6.8.A to implement the applicable procedures

.

recommended in Appendix A of Regulatory Guide (RG) 1.33, Rev. 2, February 1978.

F Procedures for administrative controls conditions were recommended in RG 1.33.

• Contrary to the above, the opeistor failed to imploraent DAP 7-43 prior to closing the air

-

l

.

.

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,

i start valve. As a consequence, the 2/3 EDG was momentartly rendered inoperable. This was a violation of T.S. 6.8.A (VIO 90 337/9701M2A (DRP); 50 34tf9701M2A (DRP)).

,

.

'

This issue was also of concem to the NRC because some aspects were similar to one of

-

- the contributing causes of the July 28 Unit 2 feedwater transient and subsequent reactor i

trip.

-

!

c.

Conclue1908 f

The failure of the operators to follow procedures resulted in the operators inadvertently rendering the UnN 2 EDG Inoperable. While the consequences of this event were not as -

,

severe as the reactor trip of July 28,1997, the cause was similar in nature in that the Unit N80 departed from the approved plan without the knowledge of the unit supervisor.

,

04.4 (Unit 3) High Pressure Coolant inlection (HPCI) System f

!

' a.

Inspection Scope (71707)

!

The inspectors observed the following surveillances from the control room and in the

.

j-plant, reviewed the test procedures, applicable technical spoolfloations (TS), the updated final safety analysis report (UFSAR), and interviewed operators performing the

,

surveillance activities:

Dresden Operating Surveillance (DOS) 2300-02, Revision 48, "High Pressure e

Coolant injection System Operability Verification Surveillance."

Dresden Operating Procedures (DOP) 2300-02, *HPCI Tuming Gear Operation."

• DOS 2300-01, "HPCI Motor operated Valve Operebility Verification"

b.

Observations and Findinns

The licensee completed this sedes of operating procedures and surveillances twice

during this inspection period. The first operability run on September 5 was the rssult of

,

,

i planned surveillance activity. The second surveillance performed on September 10 resul%d from the licensee decladng the HPCI system inoperable due to a stuck interiock dump valve discovered by the licensee on September 9.

!

pontrol Room observations

.

After completion of the warmup interval during the September 5,1997. HPCI system

$

operability surveillanoe, the control room operator raised the HPCI system's turbine speed to 2500 rpm. The operators then disengaged the tuming gear and tumed off the tuming i

gear motor as required by the procedures. Soon after this sequence, the *HPCI GLAND SEAL CONDENSER HOTWELL LVL Hl/LO" alarms annunciated. The control room operator immediately directed the field operator to verify that the gland seal leakoff (GSLO) drain pump had started and the condenser hot well level was going down.

'

Moments after this command the *HPCI GLAND SEAL CONDENSER HOTWELL HI PRESS' alarm annunciated. The NSO relayed this information to the Unit 3 supervisor and the unit supervisor immediately directed the NSO to clear the field operator from the HPCI room and trip the turt>ine. The licensee then declared the HPCI system inoperable.

Subsequent investigation by the licensee determined that the gland seal condenser level

J f

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ny y-w,v-v-.y-y.r----ww4~

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'

control /darm switch in the condenser malfunctioned (Reference LER 241W97000).

Despite this sequence of events, the inspector noted good self checking, peer review,

'

and quick conservative decision making throughout this HPCI system operability surveillance. The licensee isolated the HPCI system steam line for out-of-servica

'

.

purposes on Septerr.ber 6 and repieced the OSLO level switch on September 7. The

'

operability surveillance was completed suoosesfully on September 8,1997. The inspectors found in the N80 log book that the HPCI turbine was tripped by cperators

- during a September 7 operability surveillanoe in ruaponse to numerous exhaust drain pot

,

high level alarms. This issue will be trocked under LER 249/97009.

'

On 86ptember 9, maintenance personnel discovered a malfunctioning interlock dump

!

valve in the HPCI system front standard. The licensee declared the HPCI system

'

inoperable and repaired the valve. During the HPCI system operability surveillance run t

on September 10, the inspectors noted that the survelliance was done socording to wooedures. The inspedors also noted careful checks, use of redundant (computer)

'

nformation, and comful observations of panels.

Field Performance Observations

'

I During field observations of the September 10,1997, HPCI system operability surveillance, the inspectors noted leaks on both HPCI turbine stop valve above seat drain valves (AOV 230144 and 65). The leakage of the 230144 drain valve was more apparent than the leakage from the 230145 drain valve which displayed minimum air and vapor seepage. The inspectors also noted excess water undemeath the stop valve

,

above seat drain pot. The Inspectors then prompted the field operator on their observations. The inspector questioned the operator on his threshold for notifying the NSO of what may be considered adverse material condihon. The field operator

-

responded by stating that because leaks were not steaming he did not think it was an immediate concom.

,

The inspectors' awareness of the leaks was heightened because on June 19,1997, the licensee declared the HPCI system inoperable due to steam leakage on both drain

'

valves. Improper seat loading and mechanical binding caused this leakage (reference License Event Report 97-003). On June 21, the licensee repaired both valves and then declared the HPCI system operable aftu successful completion of HPCI surveillance (reference inspection Report No. 97013).

After inspectors raised concems, the field operator informed the NSO operator of leaks.

The control room operator immediately dispatched a mechanical maintenance supervisor

,

i to Unit 3 HPCI room to examine leaks. The Mechanical maintenance supervisor verified the leaking valves and determined that the leakage was not adverse enough to step

'

surveillance.

c.

Conclusions The inspectors observed the licensee perform good self checking, poor review, and conservative decision making throughout most of bcth HPCI system operability surveillances. The inspectors identified valve leakage in the field prior to identification by the operators.

.

b vo,

,,,., -,

,.am.,

....-e-,.,--w,-,

.v, w..-+ce,, ram,ee-.-iw,-,,%,,-e.-w-,wwmm++--v-r--e-ce-w-n.-,-e---no-..me-ww.r-

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- - - -

-

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- _ _ _ _ _ __ -

_ _ _ _ _ _ _..

. ___ _ ___

f M

$$W' taker Control and Procedural Adhstence P

bg;g@ Scope (71707)

he inspectors perfonned several plant walkdowns and reviewed operation activities to assess operation's adherence to plant procedures.

,

b.

Obserystions and Findinos On September 11,1997, the licensee temporarily lifted a 4160 V breaker to tim test mode from the Out-of-Service position to perform pressure switch logic testing on the 3B shutdown cooling pump (SDC). On September 16,1997, inspectors noted that the 4-kV breaker was still temporary lifted in the test position. This breaker was located in cubicle 10 of safety-related bus 34-1.

The Action and Limitation section of Dresden Operating Procedure (DOP) 6500-04

" Rocking Out Safety related 4kV Breakers," stated that breakers are not to be racked out in the test mode for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless plant is in hot or cold shutdown.

Additional!y, Dresden Administrative Procedures (DAP) 03 05 'Out-of-Service Procedures,' stated that when an OOS is temporary lifted for test purposes temporary lifts should not exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless approved by the stetn manager or his designee.

The inspectors informed the Unit 3 supervisor of the breaker status. The unit supervisor immediately removed the temporary lift and placed the breaker in the out of service position. The inspectors venfied the breaker was property placed in the OOS position.

As a result of the inspectors' initialidentification of these noncompliances, the licensee initiated a survey to see if any other OOSs were not in accordance with station procedures (reference PIF 1997 07052). The licensee identified three more OOSs that were temporary lifted greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. After this identification the licensee properiy indicated the status of each breaker.

Dresden T.S. 6.2.A requires, in part, that written procedures shall be implemented covering the activities referenced in Appendix A of RG 1.33. Appendix A of RG 1.33 references both the operation of AC electrical power systems and the Out-of Service Programs. The failure to property rack out the breaker in accordance with DOP 6500-04 is an example of a failure to comply with TS 6.2.A (VIO 50-237/97019 2B (DRP);

50 249/97019 02B (DRP)). The failure property to temp lift the OOS in accordance with DAP 03-05 is another example of failure to follow TS 6.2.A (VIO 50 237/97019 02C (DRP); 50 249/97019-02C (DRP))

c.

Conclusions The inspectors identified that operators were not following station procedures for racking out safety-related breakers and temporary lifting OOSs for testing purposes. Following NRC-identification of the procedural noncompliance, the licensee noted additional examples of operator noncompliance with the OOS procedure.

.

-_

_

._

-

..

.

_

_.

_ _ _._._._.

_.

.

_

-

__ ____._____

!

i l

Quality Assurance in C;: -C:r.;;

07.1 ' (Unit 2. 3) Operations Performance

[

a.

Inspection Scope (71707)

i During the inspection period, the inspedors reviewed multiple licensee sew assessment

actMties, including:

,

e Plant Operations Review Committee (PORC) Meetings e Routine Q&SA AudH results i

e Safety Review Board Meetings o P.autine PlF Deficiency Documentation -

,

-

b.

Observations and Findinos The inspectors observed active management participation at the meetings. Identified deficiencies were generally being documented and tracked by the licensee's processes.

-

The PORC meetings were aggressive and probing; the inspectors noted one instance i

where the PORC board tabled discussion of the m6tter at hand and rescheduled the i

meeting for a later date because the board felt that the presenters were not adequately l

prepared to present the material. The Q&SA sudN of UnN 1 activities was strongly self-cdtical and documented human performance concems similar to NRC observations and concems assorjated with Units 2 and 3.

c.

Conclusions The inspectors were concemed with a negative trend in human performance events, first documented in the pdor inspection period, that occurred during this inspection period.

These events were both licensee and NRC identified and occurred during the performance of routine, fundamenW tasks. The licensee's self assessments documenting these events appeared strong and critical,

.

11. Maintenance M1 Conduct of Maintenance M1.1 General Comments (62707)

The licensee maintained good coordination of the progress of maintenance during this inspection period. This was done through daily meetings of the shift manager with the maintenance manager, construction maintenance superintendent, instrument superintendent, and other supervisory staff. The meetings discussed the risk significance of issues, the status of the work, and the expected completion dates. The inspectors noted that the meetings stressed accountability and schedule adherence by assigning a job owner and an expected completion date.

The licensee maintained a " POD Risk Report" to describe the status of emergent work and to prioritize work. Operations Department Policy No. 5 stated that all LCOs and

'

!

I l'

l I

.

- -.

..

-.

.

-

..

-.

.

- _.

.

- - - -

. -... -

_ _ _

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

_. _. _ _ _ _ _

p

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issues that were operator conoems were placed on the plan of the day with the sole purpose of setting Priorities for the site, and that " Operations Management has the responsM"' and obligation to assess the aggregate condition and a4ust priorttles as

,

require'

ine inspectors observed that operations managemord followed that policy, i

The inspectors concluded that the licensee maintained good communication of work

,

progress. The inspectors also noted that the meetings were r'ot driven by any one

'

'

.

individual, but instead functioned the same with differord ahlft managers and acting

maintenance managers.

The inspectors reviewed the coordination and priortties of inanntenance for failed technical specification related equipment. The licensee was Cr-;; 1 several times by

+

emergent work on safety-related equipmerd during this inspection period. The failure dates and the equipmerd reviewed included the August 28 unit 2/3 emergency diesel

'

'

j generator trips, and high pressure coolard injection (HPCI) system problems on

"

September 5 and again on September g.

.

.

The work on the issues was generally coordinated well; only minor problems such as not

!

having radiation protection available to support a test run occurred. However, as

discussed in section 04.2 of this report, poor personnel performanoe hampered the

actual diagnosis of the failures.

!-

As each major emergency LCO work was completed, the licensee reviewed the process for improvemord. In the case of the HPCI system's failure on September 9, the licensee

immediately applied the improvements (e.g., the use of a log book that was updated l

.

hourty and maintained in the Outage Control Center). The licensee planned to create a i

new policy to identify the roles and responsibilities for maintenance personnel assigned as an emergency LCO-project owner. The policy was not completed at the end of this

'

inspection period.

l Also during this inspection period, the Opeistions Manager, Maintenance Manager, I

Plant Engineering Manager, Work Control Superintendent, and Shift Operations

!

.

Supervisor determined what plant equipment would require increased maintenanoe

coverage (reference OPSLTR 97028). The licensee identified the equipment and the l

plant impact due to unavailability. The inspectors concluded that this was a proactive I

approach to coordinating coverage for significant components.

l M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Material Condition observations

!

a.

Inspection Scope

!-

The inspectors noted several material condition iss' - 4 and self revealing equipment failures during the inspection period, b.

Observations and Findinas The operations staff continued to be challenged by these items, some of which rendered safety-related equipment inoperable. The examples noted are listed below:

!

!

-

-.

_ _ _._ _ _ _ ____ _ _

_ _ _ _ _ _. _

__

_. _ _.

l

!

i I

e As documented in sections 04.4, M8.1, and M8.2 several material condition lasues rendered the Unit 3 HPCI system inoperable. (Reference LERs g7-00g and 97 010)

!

e During regulariy scheduled maintenance on September 15,1997, of the reactor

!

foodwater pump (RFP) inboard check valve (2-3206-B), the licensee identified that

'

10 of 18 retaining bolts were missing. The retaining bolts are used to secure the

!

'

seat assembly in the valve. Further inspection b/ the licensee revoeied that self-looking helioolls installed on the insert ring were missing. The insert ring is used to bolt the seat assembly inside the valve. The licensee investigation

.

concluded that the apparent cause of the loss of the retaining bolts resulted from

!

Installation of the wrong type of holloolis by the vendor.

,

After placing the 28 RFP in standby on September 26,1997, the licensee

!

discovered the local wessure indiostor reading 200 paig and the temperature at the ched valve and ;ust before discharge of MOV was 100* F. The licensee suspected that the check valve was potentially leaking.

• After completion of maintenance on September 28, igg 7, the licensee attempted to start the 28 RFP, but the minimum flow limit switch fell off the valve.

e On September 2g, the licensee discovered that the 2C RFP shaft temperature

,

was 240' F. The licensee ruspected possible discharge check valve leakage.

,

The licensee operated with the 2A Recombiner booster pressure control valve

(PCV) bypass cracked open because the 2A steam Jet air ejector (SJAE) train was

experiencing pressure oscillations from the Recombiner booster PCV. The 2A Recombiner booster PCV Bypass was showing indications of steam cutting.

.

The 28 SJAE Train was unavailable due to a steam leak on the preheater PCV bypass.

l c.

Conclusions

While overall material condition of the plant has improved, material condition issues continue to challenge plant operators. The events were primarily self revealinC and

'

!

placed the operators in a reactive mode.

!

l M2.2 Control Rod Drive System L

,

s.

Inspection Scope The inspectors performed a general walkdown of the CRD system to assess the material

- condition.-

b.

Observations and Findinos On September 20 during thic walkdown, the inspectors noted that the material condition

.

of the Hydraulic Control Units (HCU) was poor. The inspector noted approximately

'70 action request tags designating leaks throughout UNIT 2 CRD HCU banks alone. The

-

'

inspectors also noted that several limit switch actuating arms for both the inlet and outlet

l

..

.

. -

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

~.

-__,..---..,.__m__. I

,

scram valves were out of agustment. The inspectors informed the CRD system engineer of their concems regarding the reliability of the CRD HCUs. The system engineer's a

response to the inspectors' questions suggested that engineering and malhtenance i

personnel were aggressively planning and addressing lasues on the CRD system.

On October 10, while aqusting a limn switch position for CRD M-14 scram insert valve,

the rod suddenly inserted from position 48 to 00 in approximately Ave seconds (scrammed). The licensee's investigation concluded that the coupling bon used to secure

>

the scram valve assembly and position the limit switch was not torquod to 25 ft-lbs as

!

recommended by the vendor. Therefore, when the mechanic detensioned the nut holding the limn swNeh actuating arm, the coupling opened, allowing the valve disc to lift off Ns

!

seat causing the rod to drift into the core.

After this sel.% revealing rod drift incident, the inspectors 5,orformed arMher walkdown of j

the CRD Hydraulic System. The inspectors noted that many of the coupling bolt

assemblies used to couple the valve stem used a differord type coupling bolt (some were

stamoed with *L*). The inspectors questioned the system engineer on this difference and

<

the system engineer responded by stating the licensee purchased the entire coupling assembly (ooupling, coupling bolt, and nut) as a set from the vendor. The system engineer reported that the vendor stated that the *L" stamp symbolized low carbon steel and was sufficient for the application.

Also, during this same walkdown, the inspedors noted two washers that were being used on the coupling assemblies to secure damaged finger spacers on the coupling assemblies. The system engineer was unaware of these washers and stated that the washers were not appropdate. The system engineer then pulled the maintenance history for the affected scram valves but could not identify when the inappropdate fixes were done. After evaluation of the placement of these washers, the inspector conduded that these washers did not adversely affect the safety related function of the scram valves but represented past poor maintenance practices.

The licensee initiated a PIF (Digg7-06503) which declared that the Unit 2 CRDs have

.

very poor performance. Specifically, they are very difficult to withdraw. The licensee also t

initiated a Nuclear Tracking System Irsvestigation (NTS) number 237201g632601 to

!

identify the causes.

c.

Conclusions

>

The matedal condition of the CRD system was poor. Maintenance work performed on the system to address some of the deficiencies adversely impacted operations when a control rod unexpectedly scrammed and inserted into the core.

M2.3 Emeroency Llohtina Material Condition a,

inspection Scope (62IQZ1 Dudng the pedod, the hopectors identified emergency lights which had their battery installed incorrectly within the emergency light assembly. The inspector discussed the situation with electrical maintenance personnel, reviewed the UFSAR section on l

i

!

l

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

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

_

_

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

. _ _..

emergency lighting, reviewed licensee drawings on emergency lighting, and reviewed a

,

Problem identification Form (PlF) from Braidwood Station on a similar problem.

b.

Qhservations and Findinas

The lights appeared to be missing either or both Ilw battery tray and the pressure bar.

Within the emergency lioM assembly, the battery rests on the battery tray and is pressed

against the front of the unit by the pressure bar Without ellhor of these items, the battery

is free to move around inside the emergency ligM assembly. The battery being free to move within the emergency light assembly effects the seismic y"%h, of the.

,

emergency lights. After being notified of the problems with the emergency lights, licensee a

personnel initiated a PlF (# Digg7 07316), notified site and design engineering for j

assistance with the seismic conoems, and began a walkdown of the emergoney lights to determine the extent of the problem.

'

The inspectors asked electrical mainte, nance personnelif they were aware of a similar problem at Braidwood station in the past. The elecideal maintenance personnel stated

,

J the problem at Braidwood involved securing the battery assembly to the mounting shelf -

>

and had been evaluated at Dresden Station.

,

!

Cor.rary to electrical maintenance's statements, the problems previously exportanced at

!

Bra dwood were similar to the present problem at Dresden. Braidwood

'

PlF e:4 201 7-0601 dated March 6,1997, stated in part, "... batteries in some of the

-

emergenci Hghts are not secured to the enclosure using the hardware supplied by the manufacturer with the light. The related hardware is either partially or completely missing

,

from the light enclosure... "

I The inspectors will continue to investigate issues involved with the problem. Pending

'

further inspector review of the seismic requirements of the emergency lights, and of the i

licensee reso;ution of the matter, this item will remain an inspector Follow-up l

llem (IFl 50 237/9701943 (DRP); 50-249/9701943 (DRP)).

c.

Conclusions

,

L Due to past practices, the batteries in many emergency lights were potentially incorrectly

,

installed. The incorrect installation may affect the seismic qualification of the emergency lights. The inspector will further inspect the issues with the emergency lights in future inspection periods.

'

l

'

M8 Miscellaneous Maintenance issues (g2g02)

,

M8.1 (Closed) URI 50410/9700511(DR81; Unit 1 Maintenance Rule (MR) program. The inspector examined two aspects of the Unit 1 MR program The first involved the current

.

program, implemented on November 1,1996, and the second involved the procedures and policies the licensee used prior to that date. During these reviews the inspector

examined the following documents:

Decommissioning Program Plan for the Dresden Nuclear Power Station,

-*

Unit 1, Revision 5, dated December 1996

,

C is

,

i a

+e.-,..-mw.m...,.-,e---.-e

+.~o

---*-.---~.wr

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---

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-

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= - r wr v-r ~, w-nm

-

e,

---

cr,,...---m--~emm

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

- - -

-

-. - -. - - - -

t i

!

Dresden Dooommissioning Procedure (DDP) 06, Revision 1, dated November 1, f

1996

.$

DDP-06, Revision 2, dated June 27,1997 t

+

!

Dresden Technical Surveillanos (DTS) 001001, integrity Surveillance for UnN 1

+

.

Structuras, Revision 0, dated August 7,1994

,

DTS 0010-02, UnN 1 Fuel Transfer Tube and Valve inte9tity Surveillanos,

+

-

Revision 1, dated June 12,1995 j

DTS 0010 03, Unit 1 Fuel Storage Pool and Transfer Pool integrity Surveillance, s

+

Revision 0, dated October 18,1994 i

Dresden Chemistry Procedure (DCP) 100602, Fue! Pool Corrosion Morwioring, i

+

Revision 1, dated August 17,1995

'

DCP 2106-02, Fuel Pools, Revision 1, dated April 4,1995

,

,

Dresden instrument Surveillance (DIS) 170009, Unit 1 Fuel Pool SPlNG

!

+

Calibration, Revision 2

,

Dl81700-14, Radioactive Gaseous Effluent Monitor Low, Mid, and High Range

+

Noble Gas Channel Calibration, Revision 9 Dis 1600-01, Unit 1 Fuel Building Area Radiation Monitor Calibration, Revision 5

.

l DlS 1900-01, Unit 1 Spent Fuel Storage Pool Level instrument Functional Check, i

+

-

Revision 3 i

Dresden Mechanical Surveillance (DMS) 5800-01, Overhead and Gantry Cranes,

+

Monthly inspection and Proventive Maintenance, Revision 1, dated February 23, 1994 DMS 5800-02, Overhead and Gantry Cranes, Annual Inspecta.) and Preventive

,

Maintenance, Revision 1, dated February 23,1994

'

.

Dresden Operating Surveillance 1700-01, Periodic checks of Unit 1 Area

' Radiation Monitors, Revision 6, dated February 6,1996 i

'

Dresden Radiation Surveillance (DRS) 2000-03, SPING Effluent Monitor

+

Calibration, Revision 5, dated t eauary 31,1995

!

DRS 2000-06, _SPING Efflu+nt Monitor Quarterty Functional Test, Revision 4

+

Dresden Administrative PrMure 01-03, Administrative Control Program for

+

Dresden Unit 1. Revision 3, dated March 8,- 1996

+ -

Dresden Unit 1 Technical Specifications

,

i l

'

.

.

,_

i

.-

<

nuw..--

,,

-er-

.. m wewe-rz mvoa em 7e-n + -

-*-y

- w -r n

en, s,--w-rn vi--

rc ry-g-

--

y ef

.

mw g

. _ _.___ _._ _ ___ _ _ _. ______

-_

__

,

,

,

To evaluate the adeqwy of the licensee's current MR program, the inspector reviewed

,

DDP-08, Revisions 1 and 2 and examined the scoping studies the licensee completed, t

,

The scoping was drawn from the decommissioning plan and propedy identifled those

-

structures, systems, and components (88C) needed for the storage, control, and.

maintenance of spent fuel in a safe condition in lieu of dek signifloanos determinations

,

tied to a formal probabilistic ris6. assessment, the licensee identifled several key SSCs as

!

"important to safety." This was considered soceptable. The inspector noted that performance criteda had been established as wen as L.eventive mairdenance and

-

surveillance requirements. The inspootor determined that these modvities formed an acceptable program of condition monitoring. The inspector also noted that the licensee's administrative control program, DAP 0103 required an annual evaluation of Dresden Unit

.

i status and that this review included all of the aspects required in section (a)(3) of the rule. Based on these examinations, the inspector concluded that the licensee had in place an adequate MR program.

Prior to the impiomentation date of the rule (as amended to include decommissioned

>

plants), August 28,1H6, the licensee had in place programs to control the maintenance of equipment needed for the storage, control, and maintenance of spent fuel in a safe condition. These were put in place following the January igg 4 freezing event. These programs included structural integrity surveillance for the building, fuel pool, and transfer

'

pool and preventive maintenance and surveillance requirements. The inspector noted l

that the decommissioning plan identified t

s systems needed for safe storage of the -

spent fuel and further identified several systems as important to safety. The inspector

-

concluded that this met the requirements for scoping. The inspector reviewed the structural integrity monitoring program and the preventive maintenance and surveillance programs for the systems identified in the decommissioning plan. The inspectos

,

determined that the surveillance test acceptance ortteda were appropriate goals and the periodicity of the tests and prcventive maintenance activities provided an acceptable

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!

monitoring program as mquired by section (a)(1). This item is closed.

M8.2 (Open) LER 50-249/97 0900: HPCI System Declared inoperable Following Gland Seal Leskoff Condenser Hotwell High Level Due to Drain Pump Stop Switch Failure. This LER documented the self revealing failure of the Unit 3 HPCI system during routine surveillance testing. The failure occurred on September 5, igg 7, and the HPCI system was restored following repairs on September 8.

During the routine testing, the gland seal leak off condenser hotwell high level alarm was l

received. Nine minutes later, the gland steam exhauster tripped off and caused the gland seal leak off condenser high pressure. Operations tripped the turbine 2 minutes later.

The licensee identified that the mercury bulb in the level switch had shifted and its glue had failed. The shift caused the bulb not to break the circuit when it should have.

l Because of this, the drain pump had continued to run beyond its normal shutoff. -The pump eventually introduced air into the drain line. The licensee identified air in the GSLO drain pump discharge pressure regulating valve sensing line, and concluded that the air delayed valve operation. This led to the high condenser hotwell level, and the water then caused the gland steam exhauster to trip. The licensee did not 'dentify any l

cause for the glue failure and subsequent mercury bulb ro'.ation.

L l

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The licensee did not identify any previous failures or replacements for the level switch, in

June of 1997, the UnN 2 HPCI system failed a surveillance and was docdared inoperable j

due to sticking of the same swNch (ref. LER 50 237/97 01300, IR 97012). The licensee

did not perform specific inspections of the UnN 3 level swhch in response to the UnN 2 i

failure because the UnN 3 HPCI system had recently been examined. The inspectors concluded that this was a random equipment failure.

.

.

.

The licensee repaired the mechanical cornponents of the HPCI system. However,

!

Inspector review into the initial post-maintenance operstloo of the HPCI system revealed

some potential issues regarding performanoe of prorsquishes. Therefore, this LER is

'

being kept OPEN pending additionalinspector review of the operators' performence.

>

M8.3 iClosedl LER 50-24g/97 01000: High Pressure Coolant Ir(ection Declared inoperable

Due to Turt ine interlock Dump Valve Being Out of Agustment and Stuck in the Closed Position induced by Normal Wear and Vamish Buildup. This LER documented the

discovery by a licensee component engineer that the interlock dump valve was not at its

!

correct standby position. The condition was discovered on September 9,1997, although the licensee could not determine when the failure ectually occurred. The HPCI system was declared inoperable and was restored following repairs on September 10.

,

.

,

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The interlock dump valve was supposed to prevent the uncontrolled opening of the i

control valves following a re-initiation of the HPCI system. However, following an l

HPCI system trip, the motor speed changer closes the control valves within about l

11 seconds, so the time the HPCI system was vulnerable to uncontrolled opening of the

!

control valves was small.

,

,

The licensee concluded that the dump valve was stuck shut due to wear and oil vamish buildup. The !!censee could not locate any work on the valve, and no surveillance test tested or required inspection of the valve. A 1995 Performance Centered Maintenance analysis of the HPCI system front standard identified the interlock dump valve as one of

,

the components that should be incorporated into the HPCI system front standard maintenance inspection program, and had scheduled the HPCI system front standard inspections to occur during D3R18.

The licensee inspected the Unit 2 HPCI system and verified that a similar condition did f

,

i not exist.

l

,

No routine surveillance test procedure verified the functioning of the valve. No procedure changes were made in response to the event. The licensee concluded that there was no need to monitor the operation of the valve during periodic HPCI system surveillanoe tests.

The inspectors concluded that the event showed mixed performance in the area of plant I

material condition problem identification. The identification by the component engineer of the failed valve showed a questioning attitude and good system knowledge. However, there have been several recent HPCI system runs following the startup of Unit 3, and some work in the HPCI system front standard, and the failed valve was not identified during those run times, i

i

22

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E.-

i E2 E ;* wn-h; Support of Feellities and F.quipment E2.1 EDG Freauencylyleier Calibration i

i s.

Innoection Scope (62707)

The inspectors reviewed tne calibratkm of the control room frequency meters for tie i

emergency diesel generators, j

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!

b.

Observathrit.godBMUDet

,

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As stated in section 04.2 of this report, the licensee was unable to run the 2/3 emergency diesel generator successfully. Par 1 of the problem was a lack of krc;wti;+ regarding when the frequency motor in the contrcl room provided useful information.

,

At Comed's La 8elle station, the frequency meter in the control room was not being used i

,

as desortbed in the vendor's manual (see NRC inspection Report 50 373\\97015;

.

50 374\\ 97015). Specifically, the Yokogawa vendor manual 4556K24 701, " Types AB 16

antM0 Frequency Meters (Taut Band suspension)" for the meters at La Salle said " Allow

,

10 c.,stes warm-up after energizing frequency meter before reading."

!

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The inspectors reviewed General Electric vendor manual 4555K11-002,

" Types AB14, 15, 16, 18, -ils, and -40 Frequency Motors," applicable to the Dresden i

equipment, and verifica that the 10-minute wait was not mentioned. However, the vendor

'

manual update said to use manual 4555K24 701 as a supplement for Types AB 16

j and 40. Dresden's meters were Type AB-40, so the note regarding a 10 minute wait I

was applicable. However, the inspectors noted that the manual said, "To obtain the best

-

possible accuracy, calibration of the instruments should be checked after a warm-up of at

least 30 minutes at rated voltage." The licensee was unaware of the vendor's recommendation, and had not assessed it.

t Subsequently, the licensee personnel at La Salle performed a bench test of the population of the sample of meters utilized at LaSalle and Dresden (LaSalle Work

>

Request g70097659 01). The system engineers reviewed the data and found no significant problems with the calibration,

,

,

The test performed was a calibration of the meter following a 60-minute warm up time,

'

then a 24-hour cool-down time, then a series of readings with a 60 Hz source soplied.

The inspectors reviewed that_ data and concluded that the warm-up times did nc.t have a significant effect on the meter readings,

'

c.

Conclusions The iscensee had not adequately assessed the vendor's recommendations regarding the operation and calibration of the frequency meters for the emergency diesel generators.

Following inspector quest!oning, the licensee performed tests that showed that the i-vendors' recommendations did not have a significant effect on obtainlag a true reading

,

from the frequency meter.

.

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The inspootors noted that this issue, failure to review and assess vendor

recommendations, was similar to the failure to incorporate vendor recommendations into

j non-licensed operators' rounds procedures for the hydrogen analysers (see inspection

!

repori 97013 Section 04.5)

ES Miaoollaneous Engineering issues (92903)

E8.1 While issoMng improperty installed concrete expansion anchors (CEAs) at the Quad

,

Cities Station, the licensee determined that a safety factor of 2.0 was originally used to i

qualify the CEAs on high energy pipe whip restralrds at both the Quad Cities and.

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Dresden Stations. This design approach was inconsistent with the standard safety factor

- i of 4.0 that was used for CEAs on other types of pipe restraints. After reviewing their

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justification for using a safety factor of 2.0 and discussing N in detall with them, the NRC

!

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disagreed with the 16consee's technical arguments.

I j

The NRC determined that additional analyses and/or anchor boM onpacity upgrades would be required for high energy pipe whip restraints, in order to meet the CEA manufacturers'

recommended capacities. The NRC staff considered the criteria for CEAs given in IE Bulletin 79-02, and in Revision 2 of the Generic !mplementation Procedure developed i

by the Seismic Qualification Utility Group for Unresolved Safety issue A-46, to be a

acceptable. This is considered an Unresolved Hem perding the review of the licensee's schedule to complete the additional analyses or upgrade the anchorage capacity.

,

(URI 50 237/9701944 (DRP); 80-249/9701944(DRS)).

E8.2 Assessment of Performance Indicators

'

i The inspectors reviewed the performance indicators submined by the licensee in i

response to the U.S. Nuclear Regulatory Commission request for information pursuant to 10 CFR 50.54(f). The inspectors reviewed the indicator for rework and discussed the tracking of rework with the licensee person assigned to track rework. The inspectors also i

reviewed licensee self assessments in the area of rework.

l The cognizant licensee personnel established a baseline of rework by reviewing data for

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igg 7 and establishing what was rework following a change to the methodology for rework

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tracking. Also, the licensee was then confident of the validity of month-to-month comparisons of rework for 1997.

The licensee's Q&SA department performed an audit of rework and determined that the

_

rework percentage was accurately calculated from the rework database, but Q&SA determined that the process changes were too recent to be evaluated.

'

l The tracking of rework was based on reporting of rework through the licensee's biograted reporting process. The inspectors reviewed the NSWP A 15, Revision 01," Comed

'

Nuclear Division Integrated Reporting Program," and verified that, "The Event Screening Committee shall: Review and mark the Screening information section for.,, Rework,"

During routine audits of the event screening committee meetings, the inspectors

,

observed that the licensee does discuss if an item is rework.

'

The licensee was finclizing DRAFT NSP-WC-3007, Revision 0, " Rework Reduction,"

during the inspection,

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The inspectors concluded that the rework tracking was dependent on the determination of the event sorooning committee. During routine observations of the event screening committee, the inspectors did not identify issues that were rework that were not classified

- by the committee as rework.

!

N. Plant Summort

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R1 Radiologloal Protection and Chemletry (RP&C) Controls

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R1.1 General Comments (71760)

During routine inspections in rM4:4:$:"; controlled armes, the inspectors assessed the performance of the licensee.

Overell, the licensee's radiation protection staif enforced the plant's radiologiool control

standards. The licensee continued to use personnel functioning as "grooters" to assure

<

,

that workers entering the radiologically controlled etwa were aware of dose rates and

administrative protection requirements. However, as stated in section R4,1 of this report, the inspectors noted some station survey maps conoems.

.

R4 Radiological Protection and Chemletry (RP&C) Controls

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R4.1 Genyol of Survey Mao Updates

-

a.

Inspection Scone (71750)

)

Following licensee identification that security personnel was not reviewing current valid

'

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surveys for the roof area, the inspectors assessed and compared current plant radiological conditions against posted survey maps, b.

Observations and Findinas

,

On September 14, during plant tours inspectors noted that sections of the Unit 2 HPCI system room were roped off with step off pads. These conditions were different from

'

those shown on the survey map. Upon exiting the radiologically protected area (RPA),

the inspectors requested an updated survey of Unit 2 HPCI room from radiation protection (RP) technician desk. This survey map dated September 11,1997, contained

.

an up-to-date survey of the area. When questioned on the station's policy for informing

'

rad workers on changes in general areas of the plant before entering the RPA, an RP technician stated that he was unaware of any station procedures which govem or.

'

dictate the criteria for updating the general area survey maps, which are posted for

>

review outside the access control point of the RPA. The inspector then questioned RP supervisors on policies.

-Two days after initial inquiry the RP manager informed the inspectors of actions undettaken by the RP department to address the issue brought forth by the inspectors.

The actions consisted of the RP technicians posting an updated list of areas where general area surveys had deviated from posted survey maps, Also, the licensee stated that this would be documented as an NTS item for future review.

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Conclusions The inspectors identified a discrepancy between actual plant radiolog! cal conditions and posted survey map conditions. The inspectors were concemed about the potential.

V. Mananoment Meetinas X2 Exit Meeting Summary The inspectors presented the inspection results to members nf license management on October 16,1997, following the conclusion of the inspection period. 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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PARTIAL UST OF PERSONE CONTACTED

,

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Ucensee

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• T. Bezouska. Site VP Staff

'

• E. Carroll, NRC Coordinator

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• F. Fink, Business Site Business Manager

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'J. Hoffley, Station.'2:r+;+r

'8. Holbrook, Training Manager

- *8. Kuczynski, SNft operations supervisor

'

'J. Lewa6ed, Regulatory Performance Administrator

• 8. Osgood, Communications

'8. Perry, Site Vm President

• C. Richards, SQV AudN Supervisor

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_ T. Riley, Reg Assurance Supervisor

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'F. Spangenberg, Reg Assurance Manager

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• J. Tietz, Plant Engineering Safety System Supervisor

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• L Weir, Design Engineering Superintendent

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'R. Wiggins, Maintenance Staff Superintendent

• 8. Zank, UnN 1 Operations Manager r

• Denotes present at exit meeting

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l INSPEC110N PROCEDURES USED

,

i IP 40$00:

Effectiveness of Licensee Controls in Idantify%g, Resolving, and Prevent;ng

!

Problems I? 62707.'

Mainienance Observations

!P91726:

surveillance Observations IP /1707:

Plant Operations

.'

IP 71750:

Plant Support Activities ITEus OPENED, C!.OSED, AND DISCUSSED 9etoed 50 $7:249/g7019-01A(DRP) VIO Inadequate EDG operaung procedure regarding EDG frequency

.

56 23?S9/970i9-01B(DRP) VIO Inadequate EDG alarm response procedure regarding auto-start logic GO 237;249/97G1941G(DRP) VIC Inadequate fuel pool cooling operating procedure regarding RBCCW

$0 237;249/97019 02A(D?ti') V)G Fe!!u o to follow adrninistrative pmcodures for discrete

'

component operation prior to cie gng EDG sir start valve 50 237;249/97019-0/B(DRP) VIO

.4l lure to follow administrative procedures for rocking out breakers 50 237;249/97019-02C(DRP) VIO Failure to follow administrative procedures for temporary lifting 50-237;249/97019-03(ORP) IFl Review of the selsmic requirements of the emergency lights 50-237;249/97019-04(DRP) URI Review of analysis of concrete expansion anchors selsmic qualification Closed 50,249/97 010-00 LER High Pressure Coolant Injection Declared inoperable Due to Turbine Interlock Dump Valve Being out of Adjustment and Stuck in the Closed Position Induced by Normal Wear and Vamish Buildup FO-010/97005-11(DRS)

URI Unit 1 Maintenance Rule (MR) program.

,

Discusatd 50 237/97 016-00 LER Autostart of the 2/3 Diesel Generator due to Operating Team Knowledge Deficiency (Non-safety related parts)

50 249/97 09-00 LER HPCI System Declared Inoperable Following Gland Seal Leskoff Condenser Hotwell High Level During to Drain Pump Stop Switch Failure i

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i UST OF ACRONYMS USED

^

- ACAD-Atmospheric Containment Atmosphere Dilution

BRC Business Review Committee

!

CCST CoM2minated Condensate Storage Tank i

CC8W-CFR

.

Coreninment Cooling service Water -

-

Code of Federal Regulations CR Control Room

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DAP Dresden Administrative Procedure i

DATR Dresden Administrative Technical acquirements i

DEOP Dresden Emergency Operating Procedure

,

DES Dresden Er$::tg Survemance

DGP Dresden General Procedure DIS Dresden Instrument Surveillance

!

DOA Dresden Operating At, normal

,

DOE Department of Energy DOP

Dresden operations Procedure DOS Dresden Operations Surveillance DT8 Dresden Technical Surveillance ECCS Emergency Core Cooling System EDG Emergency Diesel Generator

EMD Electrical Maintenance Department EOF Emergency Operations Facility i

EP Emergency Preparedness

'

ERO Emergency Response Organization

FHA Fire Hazard Analysis FME Foreign Material Exclusion -

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spm Gallons Por Minute G8EP-Generating Station Emergency Plan HPCI High Pressure Coolant INection

,

HVAC_

Heating, Ventilation, and Air Conditioning

IFl Inspector Followup item IMD instrument Maintenance Depenment

,

IRB issues Review Board kW Kilowatt i

kV Kilovolt LER.

Licensee Event Report

-

LOCA Loss of Coolant Accident MG Meriin-Gerin MMD

- Mechanical Maintenance Department MW Megawatt NCAD:

Nitrogen containment Atmosphwe Dilution

- NSO Nuclear Station Operator-NTS Nuclear Tracking System OSC-Operational Support Center OE Operability Evaluations

'

. PlF Problem identification Form

'

' psig Pounds Square Inch Gage PVC Poly-Vinyl Chloride

- RFT

- Radiation Protection Technician l

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