IR 05000237/1988029

Insp Repts 50-237/88-29 & 50-249/88-30 on 890123-0216. Violations Noted.Major Areas Inspected:Maint,Support of Maint & Related Mgt Activites.Implementation of Licensee Maint Program Determined to Be Satisfactory

ML17201Q409
Person / Time
Site:	Dresden
Issue date:	04/04/1989
From:	Darrin Butler, Ted Carter, Choules N, Eick S, Falevits Z, Hare S, Jablonski F, Kido C, Kropp W, Miller D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML17201Q407	List: IR 05000237/1988029 ML17201Q406 ML17201Q408
References
50-237-88-29, 50-249-88-30, NUDOCS 8904180108
Download: ML17201Q409 (50)

Text

{{#Wiki_filter:* U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Report_s No. 50-237 /88029(DRS); 50-249/88030(DRS) Docket No ~237; 50-249 Licenses No. DPR-19; DPR-25 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: Dresden Nuclear Power Station - Units 2 and 3 Inspection At: Morris, Illinois Inspection Conducted: January 23-27, February 6-10, and 16, 198 t;./~1;; Inspectors: W. J. Kropp _Tea,m1 L;eif d~ ~ 1 "-jf* i.1 G:L. i,,, .*"' fn.- D. ':). 1wt i er (, --;7f.l~ T. H. Carter Z. Falevits Contractor:. 'l.~)

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• Inspection Summary Inspection on Januar~ 23-27, February 6-10, and 16, 1989 (Reports No. 50-237/88029(DRS ; No. 50-249/88030(DRS))

Areas Inspected: Special announced team inspection of maintenance, support of maintenance, and related management activiti~s. The *inspection was conducted utilizing Temporary Instruction 2515/97, the attached Maintenance Inspection Tree, and selected portion~ of In~pection Modules 62700, 62702, 62704, and 62705 to ascertain whether maintenance was effectively accomplished and assessed by the licensee. . Results: Overall, implementation of the licensee's maintenance program was determined to be satisfactor Areai of strengths and weaknesses were identified as discussed in the Executive Summar Two violations were identified: failure to adequately evaluate 4.16kV breaker and 250Vdc motor control center failures and failure to follow procedures pertaining to safety evaluations for temporary change One unresolved item was identified that pertained to 4.16kV to electrical breakers.

• DETAILS Persons Contacted Commonwealth Edison Company (CECo)
• N. Kalivianakis, General Manager (BWRs)
• E. Eenigenburg, Station Maoager
• D. Booth, Master Electrician
• J. Brunner, Assistant Superintendent of Technical Services

,*J. Coonan, Maintenance Improvement Coordinator

• R. Mea-dows, Maintenance Staff Supervisor
• C. Schroeder, Services Superintendent
• M. Strait, Master Mechanic
• D. VanPelt, Assistant Superintendent of Maintenance
• G. Wagner, Production Services Superintendent U.S. Nuclear Regulatory Commission
• H. Miller, D~rector, Division of Reactor Safety, Riil
• S. DuPont, Senior Resident Inspector
• F. Jablonski, Chief, Maintenance and Outage Section, RIII
• E. McKenna, Section Chief, Performance and Quality Evaluation, NRR
• M. Ring, Chief, Project Section lB, Rill
• T. Ross, Project_Manager, NRR
• Denotes those present at the exit meeting on February 16, 1989.

Other licensee personnel were contacted as a matter of routine during the inspectio. Introduction to the Evaluation and Assessment of Maintenance This inspection was conducted to evaluate the extent that a maintenance program had been developed and implemented by the li~ensee at the Dresden Nuclear Plan Three major areas were evaluated: (1) overall plant performance as affected by maint~nance; (2) management support of maintenance; and (3) maintenance implementatio The goals of this inspection were to evaluate maintenance activities to determine if maintenance was accomplished, effective, and assessed by the licensee to assure the preservation or restoration of the availability and reliability of plant structures, systems, and components to operate on deman The systems and components selected for this inspection were based on a generic Boiling Water Reactor (BWR) Probabilistic Risk Assessment (PRA) study furnished to the team by the Reliability Applications Section of the Office of Nuclear Reactor Regulatio The systems/components selected were:

• *

Electrical

138kV Switchyard Breakers

4.16kV Breakers and Cubicles

Emergency Diesel Generator (EOG) Cooling Components

Power Transformers

• *

125 and 250Vdc Motor Control Centers (MCC) Mechanical

High Pressure Cooling Injection (HPCI) Pump and Skid Components

HPCI makeup water components

Automatic Depressurization System CADS) Valves Instrumentatio"n

Inverters

Instrumentation that initiates HPCI Inspectors reviewed work already accomplished, observed current plant conditions and work in progress, and evaluated the licensee's self assessment and correction of any weaknesse Major areas of interest included maintenance associated with electrical, mechantcal, instrument and control (I&C) and the support areas of radiological control, engineering, quality contrbl, t0aining, procurement, and operation Problems identified by th~ NRC inspectors were evaluated for effect on Technical Specification (TS) operability and technological - or managerial weaknes * This inspection was based on the guidance provided in NRC Temporary Instruction 2515/97, "Maintenance Inspection," and Drawing 425767-C, "Maintenance Inspection Tree.

The drawing, which is attached to this report, was used as a visual aid during the exit meeting to depict the results of the inspectio Historic Data The inspectors prepared for this inspection by review of data that described the Dresden Nuclear Power Station operating history in terms of availability, operability, reliability, and radiation exposur Included were Licensee Event Reports (LERs), the latest Systematic Assessment of Licensee Performance (SALP) report, completed NRC inspection reports and other industry dat Primarily, the inspectors were sensitive to technical and managerial problem~ that appeared to be maintenance relate Results of this review indicated that there were potential weakness in:

Preventive maintenance (PM) of mot~rs (LER 237/88009)

Thermal overloads CLER 249/88013)

HPCI flow trahsmitters (LER 237/88015)

Auxiliary switches associated with 4.16kV breakers (LER 237/88021)

Based on the results of this review, the inspectors were sensitive to these-issues and the potential weaknesses that existe During this inspection; concerns were identified that related to potential weaknesses with thermal overloads and auxiliary switch contact These weaknesses are discussed in other sections of this repor The inspectors reviewed plant operations history data since January 1, 1988, to assess the licensee 1 s performance in meeting four established goals: unplanned reactor trips; Engineered Safety Feature (ESF) actuations; Safety Systems actuations; and forced outage rat The goals established for each of the areas were representative of the industry 1s average in each of the area Results were:

One unplanned reactor trip; the goal was 2.9/yea * Seven ESF act,uations for Unit 2 and seven.for Unit 3; the goal was 10/unit/yea * Zero Safety System Actuations; the goal was 0.9/yea * Approximate forced outage rate of 0.1% for Unit 2 and Unit 3; th~ goal was 5.3%. Overall performance in the above four areas exceeded the established goals and indicated that maintenance had also improved. 2.2 Description of Maintenance Philosophy The inspectors reviewed site policy statements, administrative procedures, organiiation charts, established goals, and documents that described improvement programs for the maintenance proces * The licensee had a documented and comprehensive corporate maintenance plan, 11 Conduct of Maintenance (COM), 11 which included milestones and completion dates for improvement programs and goal Specific areas of the COM were assigned to each of the licensee 1 s nuclear facilities to develop procedures and polic The Dresden Nuclear Power Station was assigned as the 11 l ead 11 pl ant in the development of four of the 16 areas including post maintenance testing, maintenance procedures, failure analysis, and types of maintenanc Personnel from each nuclear facility periodically met to discuss each of areas being develope The goal for complete COM program implementation is 199 The HPCI system was the model for Dresden 1s Maintenance Improvement Program (MIP).

The MIP included motor operator valve (MOV) upgrade, PM program enhancement, failure analysis, work planning preparati6n and scheduling, post maintenance testing, and communication The HPCI system, as the 11model system, 11 was enhanced in terms of maintenance procedures, technical support, material condition, and overall appearance and performanc As of December 1988, approximately 83% of the action items for the HPCI model were complete *

• One important aspect of the 11 model system 11 concept was the utilization of PRA techniques to identify cr_itical component This was considered a strength by the t~am and should be considered for other systems at Dresde The inspectors noted how~ver, th~t vendor requirements of the critical components had not been reviewed by the licensee to identify any additional PM task HPCI had an availability.factor during 198 of 96.8% for-Unit 2 and 98.8% for Unit The licensee did not have an availability. factor for HPCI prior to 198 However, the. team reviewed the number of hours that HPCI was not available between January 1987 -

January 1988, and January 1988 - January 198 There was a noted improvement; 250 hours compared to 64 hour Regarding availability of other equipment, the cumulative availability factor for EDGs improved between 1987 and 1988 from 95.5% to 99.5%; the industry median for 1987 was 98.1%. There was no industry median available for 198 The licensee utilized goals to measure if maintenance was accomplishe The criteria included backlog and PM/CM rati However, the licensee had not established goals for measuring effectiven~ss of maintenance*such as the number of }imiting conditions for operation due to equipment problems and number of power reductions due to equipment problem Overall, the licensee 1 s philosophy was consistent with other licensee 1s in the areas of PM including predictive maintenance such as in the areas of . vibration analysis, lube oil analysis, and computer utilization for work control and schedulin The licensee was innovative in the use of work history, Time Series Analysis, to identify components that required increased attentio This, along with the PRA approach used for identification of HPCI critical components should be a solid foundation for the maintenance program, if followed through on other system *During the course of the inspection the team inspected areas that were affected by both COM and MIP, both of which had positive impact on the performance of maintenance at Dresde1 Combined with improvement in the availability and operability of HPCI and EOG, the team concluded that the maintenance process has improved overal Improvement, to some degree was attributed to the MIP; however most of the improvement-was the result of aggressive management involvement and the attitude of maintenance personne Review and Evaluation of Maintenance Accomplished 2. Backlog Assessment and Evaluation The inspectors reviewed the amount of work accomplished compared to the amount of work schedule The area of interest was work that could affect operability of safety-related equipment or equipment considered important to safety, such as some balance of plant component Maintenance work item backlogs were *evaluated for safety impact of deferrals, and causes such as lack of personnel, lack of trained/qualified personnel, lack of parts or engineering support.

• 2.3. Corrective Maintenance Backlog 2.3. The majority of non-outage corrective maintenance work requests (CMWRs) were prioritized B2, which was defined in the COM as work that must be scheduled within five day However, most of the B2 CMWRs were much older than five day As a result of an inspector 1s concern, the licensee reviewed the*backlog of B2 CMWRs to determine if any affected plant operability or should be immediately complete A small percentage were reclassified priority Bl; however, operability was not affecte The licensee revised the WR prioritization process to agree with the CO *

The backlog of both outage and ~on-outage CMWRs was tracked by the maintenance department by use of a computerized syste Backlog information could be obtained from the computer at anytim A tracking report was issued monthly to management on the status of the backlog The current as well as previous month's backlogs were listed so increases were readily apparen The report also indicated the percentage of CMWRs open more than three _month The number of CMWRs on hold for parts was not available to managemen A memorandum issued in September 1988 specified that cognizant personnel should provide computer input whenever a CMWR was on hold because parts were not availabl Only 2 CMWRs were identified by the computer as awaiting parts even though 16 CMWRs were on hold for parts in the instrument departmen The program for the verification of CMWRs on hold for parts had not yet been fully implemente The inspectors determined that on January 25, 1989, the non-outage CMWR backlog was 514 for mechanical maintenance (MM), 203 for electrical maintenance (EM), and 172 for instrumentation maintenance (IM).

lhe CM backlog was low and within the capabilities of current staf The inspectors reviewed several non-outage backlogged CMWRs and determined that none had impact on operabilit However,. based on the review of actual time spent on CMWRs completed in 1988, which was provided from a computer history, the inspectors determined the actual number of hours to complete a majority of the work requests was about twice the licensee's estimat Based on the number of craftsmen and doubling the licensee estimated hours to complete the backlog, there was apprnximately eight weeks work for MM, and three weeks for EM and I Even though no problems were identified, underestimates of the number of hours to complete maintenance work could adversely ~ffect an outage schedul Preventive Maintenance Backlog Preventive maintenance WRs (PMWRs) were also tracked by a computerized syste Both scheduled and non-scheduled PMs were tracke Based on review of licensee records, the inspectors determined that on January 23, 1989, the non-scheduled PM backlog was 230 and the scheduled PM backlog was This backlog was low and r~presented less than one months wor The licensee 1s ratio of PM hours to total maintenance hours averaged about 57% during 1988, which ~as higher than* the industry average of 42%, and approached the INPO goal of 60%.

2.3. * Review of the scheduled PMWRs backlog identified a small percentage that should have been classified as corrective maintenanc The inspectors did not identify any that would have immediate impact on operability of a componen Since the misclassification represented a small percentage, the inspectors were not concerned with ariy impact on the backlo Review and Evaluation of Completed Maintenance. The inspectors selected the components and systems identified in Section 2.0 of this report for further revie The purpose of this review was to determine if specified electrical, mechanical, and I&C maintenance on those selected systems/components was accomplished as require This review in.cl uded:

Evaluation to determine the extent that Reliability Control Maintenance (RCM) was factored into the established maintenance proces * Evaluation of the extent that vendor manual recommendations, IE Bulletins (IEB), IE Notices (IEN), Service Information Letter (SILs), Significant Operating Experience Record (SOERs), and other outside source information were utilize Evaluation of the extent that maintenance histories, Nuclear Plant Reliability Data System (NPRDS) information, LERs, negative trends, rework, extended time for outage, frequency of maintenance, and results of diagnostic examinations were analyzed for trends and root-causes for modification of the PM process to preclude recurrence of equipment or component failure * Evaluation of completed CMWRs and PMWRs for use of qualified personnel, proper prioritization, *Quality Control (QC) involvement, quality of documentation for machinery history, description of problems and resolutions, and post maintenance testin * Evaluation of work procedures for inclusion of QC hold points, acceptance criteria, user friendliness, and general conformance to NUREG/CR-1369. - 11 Procedure Evaluation Checklist for Maintenance Test and Calibration Procedures Used for Nuclear Power Plant * Backlogs for selected component Review of Completed Electrical Maintenance The inspectors determined that the electrical maintenance philosophy did not yet include the concept of RC The licensee had initiated or had plans to implement predictive maintenance that included vibration analysis and a thermovision device to detect loose electrical termination Electrical maintenance was generally baianced between corrective and preventive, which was based on previous work history and/or vendor recommendation * The inspectors evaluated the extent that vendor recommendations, bulletins, notices, General Electric (GE) service letters, and other outside source information and correspondence were utilized in electrical maintenanc The component 1s selected for evaluation were the EOG, 125/250Vdc MCCs and 4.16kV sw-itchge*ar and breakers, and Reactor Protectidn System (RPS) Electrical Protection Asse~bly (EPA) unit The inspector reviewed 14 source documents to determine if recommendations specified in the vendor documents were incorporated into appropriate maintenance document The inspectors determined -that the licensee was.aggressive in the replacement of Tuf-L.oc sleeve bearings for 4.16kV breakers as described in GE Service Advice Letters (GE SALs) 073-313.1. and 318.l The inspectors also verified that the licensee had implemented the recommended maintenance defined in GE Service Information Letters (GE SIL) 448 that pertained to AKF-25 480V breaker Previous industry failures with the breakers were attributed to. mis-adjustment or lubrication problem The maintenance defined in GE SIL 448 was performed on the breakers for the recirculation MG set in April 1988 (Unit 3) and December 1988 (Unit 2).

The inspectors identified a concern with the control of electrical vendor source document An individual was not assigned to coordinate vendor data to ensure that recommendations and revisions were reviewed for applicability and possible incorporation into appropriate maintenance procedure Specifically, the inspector determined that:

GE SALs 313.lA, 323.1, 326.1, and 343.l could not be located in document control or technical staff fil~ *

Maintenance Procedures DMP-6700-3, 11 Inspection and Maintenance of 4kV Air Circuit Breakers Type AM-4.76-250-00 and AM-4.16-250-9H, 11 Revision 6, and DMP-6700-4, "Inspection and Maintenance of Switchgear Cubicles, 11 Revision 4, were based on vendor manual GEI-88771, dated March 196 Revisions A, B, C, and D had been is~ued by the vendor, but as of January 1989, had not been evaluated for possible incorporation into the applicable maintenance procedure Before October 1988, requirements of Procedure DMP-6700-3 did not conform to Instructions GEI-887710,which were issued in 197 Discussions with the originator qf Temporary Changes 88-545 and 88-546 indicated that discrepancies with trip latch and armature travel measurements were noted during the performance of maintenance activitie Breaker maintenance performed prior to October 1988 included verification of trip latch clearanc In October 1988, the licensee changed the requirement to verify the trip armature travel as specified by the vendor in 197 A technical evaluation was not made for those breakers not inspected subsequent to the vendor chang This item is unresolved pending a complete review on a subsequent inspection (237/88029-01 249/88030-01).

• The inspectors also reviewed licensee actions for IENs 88-86, 110perating With Multiple Grounds in Direct Current Distribution Systems, 11 and IEB 88-10, 11 Nonconforming Molded-Case Circuit

Breakers.

The licensee addressed the concerns and the activities were tracked on the Nuclear Tracking System (NTS).

No problems were note The inspectors reviewed the component failure history for the electrical components and systems selected in Section 2.0 to determine whether methods had been established and implemented for detecting repetitive failures and adverse quality trends, and whether appropriate corrective action had been taken to address adverse trend The inspectors also utilized NPRDS and LERs in the review to ascertain the effectiveness of the licensee 1 s trend analysis and root-cause analysi The review disclosed that numerous Deviation Reports (DVRs), WRs, and LERs had been issued because of equipment problems with 4.16kV circuit breaker Also, NPRDS data included failures associated with closing or tripping of GE 4.16kV breaker Examples of these historical problems were:

Failure due to defective, di~ty or mis-adjusted position switch (SBM).

DVR-12'-2-87-43 DVR-12-2-87-56 DVR-12-2-87-83 LER-237/88021 WR 68284 \\4R 65089 WR 41131 WR 31207 CCSW pump 2A failure to start - CCSW pump 2A failure to.start CCSW pump 2A failure to start SGTS automatic initiation 28 RFP failed to operate in test position 2C RFP failed to close Main feed water to bus failed to close Unit 3 DG butput breayer failure to close

Failure due to worn, defective, dirty o*r burned auxiliary switch in the breaker (SBM).

WR 40917 WR 55867 WR 58809 WR 63798 Main feed breaker to bus 24-1 failed to open in test positio~ 3C CB pump breaker failed to close 3C CB pump breaker failed to close 2C LPCI pump breaker failed to close

• *

Failure due to defective, dirty, stuck stationary auxiliary switch in breaker cubicle (SBM)

WR 54361 WR 63138 (LER 237/87009) DVR 12-2-85-13 Breaker from bus 34-1 to bus 39 failed to clqse Unit 2 DG output breaker failed to close Unit 2 DG output breaker failed to clos Numerous examples of pump run ~nd trip alarms due to switch failures Recent 4.16kV breaker failures (December 1988 to February 1989.

• WR 80956 LPCI 2B linkage cubicle fell off its pin, auxiliary switch defective WR 82012 LPCI -3C breaker failed to closed WR 82083 DVR-2-88-15 Bus 24 to 24-1 breaker t~ip coil burned up 20 LPCI pump tripped several times An evaluation of these historical problems disclosed the following concerns:

Procedure DMP 6700:..3, 11 Inspection and Maintenance of 4kV Air Circuit Breakers Type AM-476-350-00 and AM-416-250-9H,

' Revision 6 required that 4.16kV breakers be inspect~d and overhauled every 500 operations or five years, which ever came firs The inspectors requested the status of the PM work on the 4.16kV breaker The status was not known by the electrical maintenance department and was not given to the inspectors for several day Individual breaker work history had to be reviewed to ascertain the PM status of the 4.16kV breake It was determined that fifteen 4.16kV breakers in switchgear 24 and 34 did not have PM at the required frequenc The two most significant deficiencies were with the breakers for the 2C and 20 Containment Cooling Service Water Pumps, which were last overhauled in 197 In addition, breakers important to safety identified as Nos. 3411, 2405, and 2413 were last overhauled in 1973, 1975 and 1977 respectively. * Although not safety-re lated, the breakers were used to satisfy the TS requirements for two sources of offsite powe Failure of these breakers would reduce the number-of offsite power suppl~es available to the plan * It should be noted that Operating Experience Report (OPEX) No. 998-042 87-02400, dated July 28, 1987, response to INPO SER-84-27, discussed four events that occurred at another nuclear facility which involved failures of 4.16kV breakers to transfer on deman The breakers were the same type as those used at Dresde In each event, voltage to a 4.16kV bus was lost when an alternate feeder breaker failed to automatically close after the normal feeder breaker was opene Failures were caused by hardened grease and dirt in the stationary auxiliary 11 SBM" switch linkage within the normal feeder breaker compartment The report further stated that these events were significant because the stationary auxiliary SBM switch in a normal feeder breaker to a safety-related bus could prevent restoration of voltage to the bus from the alternate or emergency source upon a loss of offsite power sourc Also, at the time of the inspection, a 4.16kV feeder breaker failed to trip during an undervoltage surveillance test as a result of a burnt trip coi The cause of the failure was mechanical binding of the breaker mechanism; this breaker had last been overhauled in 197 n

On February 25, 1988, the technical staff identified that SBM switches utilized in 4.16kV breakers and cubicles had a history of problem The conclusion was that the SBM auxiliary switches were at near end of life based on the increase in SBM switch failure The technical staff also noted that the SBM switches were not included in the PM program and had not previously been checked for performanc Based on a review of the Total Job Management (TJM) history and discussions wjth licensee personnel, the inspectors determined that 15 SBM switches for some 4.16kV breaker switches had been replace Replacement was based on the failure of the switches to meet acceptance criteria d~fined in revised PM procedure The switches that passed were not replaced and would not be inspected for another three years, the PM frequency on 4.16kV breakers, even though the switches had a long history of failure and were at or near end of lif * Also in February 1988, DVR-2-88-15 identified that the 4.16kV breaker for the 2D LPCI pump tripped several times during pump start The cause was identified as dirt and lack of lubrication on trip latch roller mechanism, which would not have occurred if ,the breaker had been properly maintaine The licensee's evaluation of the deviation did not address the effects that the PM program had on the failure of the breake During review of DVR 12-3-88-82, the inspector noted de powered MOV M03-1301-10, the Unit 3 Isolation Condenser Makeup Supply valve, f~iled to open in July 198 The failute mechanism was dirt and sticking auxiliary contacts with builtup non-conductive deposits, which resulted in increased electrical contact resistanc The inspectors determined that the last PM on Unit 3 250Vdc MCCs 3A and 38 was performed in 197 PM for similar equipment on Unit 2 was performed several times, the last in 198 However, Procedure DMP-8300-2, "Inspection and Maintenance of DC Operated Cutler-Hammer Reversing and Field Contactors, 11 Revision 2, had not been inccirporated into the Unit 3 surveillance progra Since the Unit 3 HPCI torus suction valves were also supplied by the Unit 3 250Vdc MCCs, the inspectors were concerned with the material condition of the circuits associated with opening these valve As~ result, the licensee sampled the material *condition of breakers in the Unit 3, 250Vdc MCC The inspectors were informed at the exit meeting that the breakers were in acceptable condition and no problems were perceived with Unit 3 HPCI torus suction valve In summary the team concluded that the licensee failed.to:

Adequately evaluate the cause of Unit 2 LPCI "D" pump 4.16 kV breaker failure in February 198 An indepth evaluation would have identified that maintenance of 15 Unit 2 and 3 breakers was not performed at the required frequenc Two 4.16 kV breakers, which supplied the motors for Unit 2 Containment Cooling Service Water Pumps, were last overhauled in 1976.

Adequately evaluate the cause of Unit J Isolation Condenser Makeup valve failure to open in July 198 Failure to perform preventive maintenance was not identified as a contributing facto Preventive maintenance had not been performed on Unit 3 250 vdc MCC, 3A and_3B *since 197 These MCCs supply power to HPCI torus iuction valve * Replace auxiliary switches (SBM) for Unit 2 and 3 4.16 kV breakers and breaker cubicles even though the switches had a history of failures since 1982 and were at or near end of lif Based on the examples above, the failure to identify root causes of equipment malfunctions and to take prompt corrective action is considered a violation of 10 CFR 50, Appendix B, Criterion XVI (237/88029-02; 249/88030-02).

During review of 4.l6kV breaker problems, the inspector noted examples of breaker swappings in DVR-12-2-87-37 and DVR-12-2-87-8 Since the breakers were not labeled, and the Master Equipment List identified 4.16kV breakers by cubicle number not by breaker serial number, traceability of completed PMs on the individual 4.16kV breakers was indeterminat The current maintenance methodology did not a 11 ow for assessment of specific breaker operating hi stor The inspectors reviewed 25 completed WRs, for use of qualified pe~sonnel, proper approvals, adequacy of work in~tructions, resolution of concerns, proper prioritization, QC involvement, quality of documentation for work history and understanding of problems and post maintenance testin In general, most WRs were prioritized as B2, schedule within five working days, and most were completed in a timely manne QC 'involvement such as requir:ed Hold Pu'ir1ts was not evident on most of the reviewed WRs and there was no block . on the WR for post maintenance testin Post maintenance tests were mostly written in the work performed bloc Rel ease for work and work instructions appeared to be adequat However, WRs did not contain the d_escription of the 11 as-found 11 condition and the 11mai ntenance cause" wa*s not complete Lack of "as-found" condition and "maintenance cause" was considered a weakriess because trending, rework identification, and root cause analysis would be hindere The following maintenance procedures were reviewed for inclusion of QC hold points, acceptance criteria, and user friendliness: DMP-6700-2, 11 Inspection and Maintenance of 4KV Air Circuit-Breakers Type AM-4.16-350-lC and lH," Revision DMP-6700-3, 11 Inspection and Maintenance of 4KV Air -circuit Breakers Type AMH-4.76-250-0D and AM-4.16-250-9H, 11 Revision DMP-6700-4, "Inspection and. Maintenance of Switchgear Cubicles,

Revis1on 4.

2.3. * DEP-8300-4, 11 Unit 2/3 Inspection of DC Motors and.Brushes,

Revision DMP-6600-7, 11 Diesel Generator Six Months Inspection Electrical Maintenance Department, 11 Revision * Some ptocedures did not provide step by step instructions for corrective maintenance activities and post maintenance testing requirement Also, checklists were not always consistent with the procedure; however, the MIP addressed these type deficiencies in electrical procedures and the ongoing ~rocedure upgrading process should resolve the concern The inspector reviewed the current backlog for the EDG cooling water components, 4.16kV LPCI breakers, 138 kV switchyard breakers and power transformer Results showed that there was no backlog of WRs that could immediately affect the operability of the component However, as previously discussed, lack of PM on 4.16kV breakers and the Unit 3 250Vdc MCCs for an extended period of time was considered a weakness that could affect operability of plant components and systems if not accomplished in a timely and aggressive manne Evaluation of Completed Electrical Maintenance Based on the review of completed WRs, backlog, work history, maintenance procedures, and the licensee's actions on source documents, the i~spectors concluded that electrical maintenance had not been satisfactorily accomplishe The following weaknesses and strengths were identifie \\~eaknesses

PM was not performed on Unit 2 and 3 safety and non safety-related 4.16kV breakers for an extended period of tim * Pm was not performed on Unit 3 250Vdc MCC * Root cause analysis was not performed for a subtle trend of problems associated with 4.16kV breaker opening and closing failure * An electrical vendor correspondence coordinator was not assigned to address and incorporate vendor recommendations - into maintenance procedures, which contributed to inadequate maintenance procedures and followup of vendor recommendation * 11 As Found" and 11 Probable Cause 11 data were not documented on the WR * Records of 4.16kV and 250Vdc PMs were not easily retrievable or available; the TJM program did not contain all PM data and was not user friendl.3. Strengths

Aggressive resolution to the 4.16 KV breaker Tuf Loe bushing issu * Morale and experience level of the electrical maintenance staff was* goo * Communication between maintenance and operations was goo Review of Completed Mechanical Maintenance The inspectors determined that the mechanical maintenance philosophy did include some aspects of RC The aspects included predictive maintenance such as vibration analysis and lube oil analysis, leak control program, use of sonic equipment to identify instrument air leaks, and MOV diagnostic test Mechanical maintenance was generally a balance between CM and P *

The inspectors evaluated the extent that vendor recommendations, IE Notices, IE Bulletins, and other outside source information was utilized in mechanical maintenanc The components selected for the ~valuation were the HPCI main and booster pumps; ADS valves and HPCI MOV The following procedures and vendor manuals were reviewed: Procedures DEP 040-9, 11 Limitorque Lubrication Surveillance Mechanical Maintenance," Revision DMP 040-16, "Limitorque Operator Repair SMT-000 and SMB-00,

Revision DMP 200-35, "Inspection and Maintenance of Electromatic Relief Valves," Revision DMP 200--37, "Target Rock Safety/Relief Valve Maintenance,

Revision DMP 2300-1, "HPCI Gland Seal Condenser Hot Well (GSLO) Pump Maintenance, 11 Revision DMP 2300-2, 11 HPCI Main Pump Maintenance, 11 Rev.ision DMP 2300-3, 11 HPCI Booster Pump Maintenance, 11 Revision DMP 2300-8, * 11 Inspection and Maintenance of HPCI Pressure Control Valve (2301-46) to Gland Seal Condenser, 11 Revision * Vendor Manuals V-018 - Target Rock Corporation Safety/Relief Valve Model 67F, EPN 203/3, May 17, 198 V-038 - Byron Jackson HPCI Pump, EPN 2302, January 7, 198 V-093 - Electromatic Relief Valve, EPN 203, May 5, 198 Maintenance procedures contained recommended vendor PMs identified

• in the vendor manuals and information from Bulletins, Notices, and plant/industry lessons learne The inspectors verified that vendor manuals were controlled and incorporated the s~rvice information from the vendo Only about one third of the vendor manuals were controlled while the other manuals were kept for general informatio The MM supervisor ~tated that although the uncontrolled vendor manuals were available for general information, the maintenance personnel were instructed to use only controlled manuals and drawings for safety-related wor The inspectors did not identify any concerns with.Vendor manual contro The inspectors perceived that PM of the ADS/safety relief (SR)

valves was a strength of the maintenance progra During each unit 1 s refueling outage, half of the ADS/SR valves were replaced with rebuilt and bench tested relief valves frdm the prevfous outage of the other uni Also; ne0 pilot valves were installed in the unit 1 s ADS valves that were not repl~ce The ADS/SR valves were maintained and tested at intervals that exceeded the vendor recommendations of 36 month The PM program for the ADS/SR valves was an example of manageme~t

s commitment and involvement in the maintenance proces The licensee had also developed a MOV overhaul program for all MOVs in the plan The overhaul consisted of a complete inspection and PM that included resistance testing of the MOV motor, lubrication of the main gear case, limit switch compartment and valve stem, and proper setting of torque and limit switche As of January 19, 1989, the status of the MDV overha~l program was as f6llows: Safety-related Safety-related (Non-EQ) (EQ) BOP To be overhauled

85 338 Overhauled to date

85

Balance

0 305 Percent Completed 76'}; 100% 10% As a result of previous inspections, the licensee committed to the NRC that all safety-related Environmentally Qualified (EQ) and non-EQ MOVs would be refurbished by December 198 The

• licensee 1s current schedule indicated a completion date of May 1989.. Based on the current staff and completion rate, the date appeared to be realistic for completion of the remaining 19 safety-related non-EQ valve The inspector reviewed IE Bulletins, Circulars, Notices and LER The following documents were reviewed and the licensee 1s responses were determined to be acceptabl *

IE Bulletin 85-03

IE Circular 80-07

IE Notices 82-26, 82-35, 86-14, 86-51, 86-63

LERs 249/87-17, 237/88-09, 249/88-13, 237/88-21 The licensee performed diagnostic testing for MOVs included in Bulletin 85-03, selected safety-related EQ and non-EQ valves, and selected balance of plant (BOP) valve Permanently mounted sensors for measuri~g steam force have been installed on all safety-related EQ and non-EQ MOVs that enable diagnostic tests to be performe The licensee anticipated better MOV performance and testing convenience from the Valve Operator Testing and Evaluation* System (VOTES) testing metho Thirty-six MOVs were diagnostically tested during this outag The inspector reviewed the NPRDS and maintenance work history of the HPCI pumps, HPCI MOVs and ADS valves, to ascertain if conditions ~xisted such as negative trerids and excessi~e rewor No problems were identifie During review of this history, the inspectors identified several strengths that reflected management 1s involvement in maintenance decision proces These strengths were:

Installation of a new five vane impeller in the HPCI booster pump to reduce vibration level This action was taken based on noise levels of the Unit 2 booster pump and the successful operation of the Unit 2 HPCI booster pump usin~ the new impeller desig * The licensee initiated plans to inspect the Unit 3 HPCI auxiliary oil pump during the next outage based on problems identified with the Unit 2 HPCI Auxiliary oil pump, a 11 skid

component that was not routinely subjected to P The license had made improvements in the MOV maintenance program since a NRC Diagnostic Evaluation Team inspection that was conducted during August 198 Improvements included:

Assignment of a MOV Coordinator to schedule and direct the improvement effort.

Assignment of a 11 MOV Team 11 that consisted of specially trained work analysts,,foreman, craftsmen,. and outage analyst E1ectrical and mechanical mainten~nce departments were represente A procurement specialist knowledgeable in the parts needed for MOV overhauls was also assigne-d to the tea * Implementation of VOTES, which was a new diagnostic progra The i.nspectors reviewed 17 WRs completed in 1987 and 1988 for the HPCI pump, ADS valve, HPCI MOV, and Feedwater component The WRs were reviewed for use of qualified personnel, proper approvals, adequacy of work instructions, resolution of concerns, proper prioritization, QC i nvo l vem.ent, quality of documentation of work history and understanding of problems and post maintenance testin In general, all work packages were correctly prioritized and completed' in a timely manne QC involvement was evident and post maintenance tests were conducted as appropriat Specifically, MOV WRs had appropriate post maintenance test requirements such as valve stroking, current limit switch signatures, and VOTES diagnostic test However, three weaknesses were identified as follows: The 11 cause code 11 block on WRs was not routinely completed, and therefore, the use of the 11cause code 11 for the identification of trends would be ineffective. Some of the WRs reviewed contained the 11 as found 11 condition in the 11work performed 11 block, but the 11 as found condition was not consistently recorde To ensure consistent input and for the ease of retri evabi l i ty, a block on the WR for . 11 as found 11 data would be usefu The inspectors also identified a strength with the system established for feedback that consisted of pre-job, post job, and workman 1s checklists; however, post job checklists were not consistently completed by work analyst The inspecto~s reviewed work procedures for inclusion of QC hold points acceptance criteria and user friendlines The procedures reviewed were the same procedures that were reviewed for inclusion of vendor recommendation The procedures were detailed, included required tools, acceptance criteria, and QC hold point Also, the procedures for MOVs contained information from IEB~, IENs, and plant/industry lessons learned.* There was a backlog of WRs for HPCI pump and skid components and HPCI MOVs* however, the backlog of CMWRs did not have immediate impact on , . . plant safet There was no backlog of PMs for HPCI pumps and skid components, ADS valves, and HPCI MOV.3. *

However, the inspectors noted that several PM tasks were completed after the indicated due date and the PM frequency was not always consistent with the scheduled due date. *The General Surveillance System (GSRV) file was being updated to show the correct base frequency and due dates for PM At ~resent, some PMs used the same date to identify PMs scheduled every 18 months as well as PMs scheduled every refueling outag Since ~he refueling outage dates can vary, there was a possibility for the work to be completed after 'the 11 scheduled 11 due dat The inspector reviewed several recent PMs and verified that the justification for deferral was acceptabl The l_icensee 1 s ongoing efforts to update the GSRV file will resolve the discrepancies in PM base frequency, equipment identification, and PM work descriptio There were no other concerns identifie The licensee initiated a leak control program in July 1988 in an effort to identify and control equipment water and oil leak Plant walkdowns by maintenance personnel were conducted and approximately 175 WRs were outstandin The backlog of leak-related WRs was reduced despite the impact on the maintenance work load due to the Unit 2 outag A maintenance foreman had been assigned the responsibility for leakage reduction as a top priorit The backlog of leak-related work-requests was tracked in weekly and monthly reports, which were reviewed by upper plant management and discussed specifically ~ith maintenance group Evaluation of Completed Mechanical Maintenance Based on the review of completed WRs, backlog and work history of PRA selected components, maintenance pr6cedures, and the licensee 1s actions on source documents the inspectors concluded that mechanical maintenance had been accomplished in a satisfactory manne The following weaknesses and strengths were identified: Weaknesses

Post-job checklists were not consistently used by mechanical maintenance work analysts to. assess the content of the work packages and documentatio * Cause code blocks were not completed on several WR * 11 As found 11 conditions were not consistently recorded on WR Strengths

Pre-job, post-job, and workman 1s checklists had the potential to provide good feedback to the work analysts if the checklists were consistently use * Industry initiatives and LERs were integrated into the maintenance program.

• 2.3. **

ADS/SR valves were maintained and tested at a frequency that was. m_ore conservative than industry practices. Performance of the Unit 2 HPCI booster pump was improved by installing a five vane impelle * Backlog for the HPCI system, ADS valves, and HPCI MOVs was low and there were no open corrective WRs that had immediate impact on the'operability of the component Review of Completed Instrumentation Maintenance The inspectors determin~d that the instrumentation maintenance philosophy did include an aspect of RC This aspect was the trend _ of plant instrument calibration data to predict instrument replacement prior to failur IM was balanced between CM and PM maintenance based on a review of previous work history, vendor recommendations and/or equipment qualification r~quirements, The inspectors evaluated the extent that vendor recommendations and other outside source information was utilized in I The components selected were the HPCI flow transmitter The inspectors reviewed the following documents:

Vendor Manual V-33, "Model 1153 Series B Alphaline Pressure Transmitters for Nuclear Service.

Survei 11 ance Procedure DIS 2300-10, 11 HPCI Steaml i ne High Fl ow Isolation Differential Pressure Transmitters 2352 and 2353 Calibration and Maintenance Inspection."

• EQ Binder CQD-1316 The surveillance procedure adequately implemented vendor recommendations and EQ requirement The inspector verified that the EQ maintenance requirements were scheduled at the correct surveillance interva The inspectors reviewed the component failure history for the component and systems selected to determine whether methods had been established and implemented for detecting repetitive failures and adverse quality trends, and whether appropriate corrective action had been taken to address adverse trend The inspectors als~ utilized NPRDS and LERs in the review to ascertain the effectiveness of the licensee 1s analyses of trends and root-cause The inspectors reviewed the NPRDS data and maintenance history files associated -

with the inverter No adverse trends were identifie The inspectors also identified the following strengt The licensee adequately addressed the main steam line (MSL) tunnel area temperature switch setpoint drift problem identified in DVR 12-3-88-3 Surveillance Test Procedure DIS-250-9, 11 MSL Tunnel Area Temperature Switch Calibration and Maintenance Inspection, 11 Revision 2,

was user friendly, incorporated vendor maintenance and calibration practices, and utilized an industry unique temperature switch calibration syste The previous revision of DIS 250-9 utilized a temperature calibration methodology that was susceptible to temperature variance~ within a temperature ove~. Revision 2 used a refrigerated circulator that should provide a more stable calibration environmen The inspectors reviewed the setpoi nt trending program for drywe 11 pressure switches for Emergency Core Cooling System (ECCS) initiation and reactor pressure switches for high pressure scra The setpoint trending program for bistable devices was proceduralized and up to dat The records for the switches indicated that the ca1ibrations were wHhin a*dministrative limits and occasional setpoint excursions outside of the limit appeared.rando The inspectors reviewed the General Surveillance System Master File (SSMF) EQ surveillance The licensee adequately implemented the EQ binder requirements for the temperature switches and the requirements were performed within the scheduled EQ surveillance interval.. The_inspectors reviewed LER No. 237/88-015, 11 HPCI Is*olated, Discovery of a Failed High Steam Flow Isolation Flow Transmitter.

HPCI steam line flow transmitter 2-2352 exhibited a trip setpoint of 156.25 inches of water differential, but the TS value was< 150 inche The redundant HPCI flow Transmitter was operable ~nd would have prbvided automatic HPCI system isolation if the HPCI steamline brok The transmitters were Rosemount Model 1153 The failed transmitter was returned to the manufacturer for further testing and inspectio The licensee. suspected that the transmitter fai-lure was caused by possible metal filings in the sensor dp cell or the glass to metal *seal in the transmitter sensor bod These type failures have occurred at other nuclear plant The licensee adequately asJdressed LER No. 88-01 The inspectors reviewed six recently completed IM CMWR The CMWRs were reviewed for proper approvals, adequacy of work inst~uction, resolution of concerns, proper prioritization, QC involvement, quality of documentation for work history, and understanding of post maintenance testin Maintenance was adequate1y performed; the licensee obtained proper signoffs, performed reviews, and evaluated the work performe QC inspectors reviewed the WR prior to the IM conducting the maintenance activity and released the completed WR if the work performed satisfied the work requeste In addition, any parts that were installed were verified against the part Suitability Evaluation List for proper applicatio The inspectors reviewed the f~llowing surveillance procedures for inclusion of QC hold points, acceptance criteria, user friendliness, and correct measuring and test equipment (M&TE): DIS 263-1, 11 Reactor Vessel Low Water Level Scram and Low, Low Water Level Isolation Transmitter Calibration and Maintenance Inspection, 11 Rev. DIS 500-2, 11 Reactor Vessel Low Water Level Scram and Low, Low _ Water Level Isolation Analog Trip System Calibration,

Rev. * DIS 500-3, 11 Reactor Vessel Low Water Levei ECCS Initiation Indicating Switch Calibration and Functional Test, 11 Rev. DIS 2300-1, 11 HPcl Stearnline High Flow Isolation Master Trip Unit Calibration, Rev. DIS 2300-2, 11 HPCI Flow Calibration, 11 Rev. DIS 2300-3, 11 HPCI Turbine Permissive (Reactor Pressure Greater than 90 PSIG) Master Trip Unit Calibration, 11 Rev. DIS 23007, 11 HPCI Area Temperature Switch Calibration and Maintenance Inspection, 11 Rev. DIS 2300-10, 11 HPCI Steam Line High Flow Isolation Differential Pressure Transmitters 2352 and 2353 Calibration and Maintenance Inspection, 11 Rev. DIS 2300-11, 11 HPCI System Isolation Reactor Pressure Transmitter Calibration and Maintenance Inspection," Rev. Some procedures did not provide acceptance criteria for the M&T The potential existed for the licensee to invalidate a calibration by not controlling the selection of M&T The following nondescript examples of M&TE requirements were stated in the procedures:

11Appropr*io.Lely sized dial manometers."

"Dial Manomete * "Flute Model 2100A Digital Thermometer or equivalent."

• 11Hiese test gauge or equivalent (minimum range 0-250 psig).

"Appropriately sized test gauges, 0 to 1500 PSIG.

Procedure DIS 2300-10 was used as reference -for calibration of the HPCI steamline flow transmitters to an accuracy of +/-0.375 Inches of Water Column (INWC).

The test performed on February 6, 1987, selected manometer DL-14 that was certified to +/-0.525 INW The certified calibration accuracy of DL-14 was less than the device being calibrate However, the licensee performed a "Before" and After Check" of all pneumatic M&TE used to calibrate critical plant equipmen In the above case, the maximum error that DL-14 exhibited was +/-0.2 INWC over its calibrated rang Therefore, the calibration was not affected by the M&T In all the other surveillances reviewed, the inspectors determined that the M&TE was of the appropriate range and accuracy to perform the calibratio.3.. The TS setpoint for ECCS initiation was based on reactor low water level of 84 inches; + 4 inches, - 0 inches, which was 119.5 to 111.7 INW The administrqtive setpoint was 112.7 INWC (+/-1 INWC).

The s~tpoint could range to the lower TS limf The inspe~tors reviewed the last calibration of the four reactor level indicating switche Switches 3-263-728 and 3-263-720 w~re both left with the setpoint at or near 111.7 INW The poteniial existed for the-M&TE inaccuracy to add an additional uncertainty to the 11 As Left 11 setpoint that would have resulted in a TS violatio The licensee stated that to allow an administrative setpoint to range to the TS limit was not a station practic The inspectors reviewed test equipment control records from the past two calibrations of LIS 3-263-728 and Manometer LD-19, used for the above calibrations, exhibited zero error near the 11 As Left 11 setpoint of the switche The licensee informed the inspectors that Procedure DIS 2300-1 would be changed to allow for M&TE inaccuracies at the setpoin The inspectors reviewed the current IM maintenance backlog.* The majority-of the WRs involved installation of replacement gauges to improve the ASME Section XI testing progra The only safety-related WR in the backlog was 080055, for main steam line high flow switch 3-261-2C, which exhibited a wide reset differentia The flow switch was operable and able to perform its safety functio A replacement flow switch had been ordere The inspectors determined that I&C maintenance was adequately accomplished and there was no backlog of WRs that could immediately affect operability of component Evaluation of Completed Instrumentation Maintenance Based on the review of completed WRs, backlog, and work history of the components evaluated, maintenance and/or surveillance procedures and the licensee 1s actions on DVRs, the inspectors concluded that completed IM was satisfactorily accomplished in a good manne The following weakness and strengths were identifie Weakness

Procedures for instrumentation surveillance did not adequately control the selection of M&T Strengths

Trends of instrument setpoint drifting were analyze * Pneumatic M&TE was calibrated before and after critical plant instrument calibration Engineering Support The inspectors evaluated the extent that engineerihg principles and evaluations were integrated into the maintenance proces This was accomplished by review of maintenance work orders, activities

• associated with failure analyse~, and other maintenance activitie Areas reviewed were engineering -support to PM, material qualifications, compliance with codes and regulations, system engineering concepts, industry initiatives,,and post maint.enance testin.3. System Engineering The 11 system* engi neer 11 concept was implemented at Dresden in June 198 System engineer duties were outlined in procedure OAP 14-1, Technical Staff Organization, Revision 8, Section 2 Each of 29 system engineers was assighed a number of plant systems to monitor pe~for mance, perform walkdowns, and assist maintenance personnel in repairs and test System engineers had 11ownership 11 and were expected to be cognizant of assigned system status.*

System engineers became involved with maintenance problems by initiation of a maintenance Problem Analysis Data Sheet {PADS).

For example, WR 076399 described that the HPCI Auxiliary Oil Pump (AOP) pressure switch had drifted, which caused the stop and/or control _valves to close and trip the HPCI pum The IM Department initiated a PADS to determine the correct pressure setpoint for the AO With the help of the system engineer, the vendor, and information from the Quad Cities station, a nominal setpoint was selecte The system engineer was in the process of preparing a special test procedure to determine the AOP shutoff setpoin It appeared that system engineers were involv~d in resolution maintenance concern Effectiveness of the system engineer role in the maintenance process depends on invoJvement with the PADS, feedback system to work analysts, and the identification of deficiencies during system walkdown.3. Technical Support There were three groups of technical staff engineers that were involved* in modifications, inservice inspection (ISI)/inservice testing (IST), and plant performanc The licensee recently implemented a fail~re analysis program that utilized PAD This program required a PAD if failure caused th~ components to be inoperable, more than 80 hours wefe expended to repair a component, or a component failed the post maintenance tes There had been approximately 185 PADS issued but only 13.were resolve Discussions with licensee personnel determined that revisions to the PADS process were under consideratio One consideration was desig-nation of the personnel who would be involved in determining the failure mode ~nd subsequent corrective action The inspectors were concerned with the number of open PADS and the slow progress in this are Since approximately 90% of the PADS were still open, the inspectors ~ould not evaluate the effectiveness of the measures for failure analysi The inspectors reviewed the measures established to identify diverse trends in equipment performanc Trends of results were evident for predictive maintenance in the areas of vibration data, lube oil samples, and instrument set point drif However, a useable trend

• program based on work history had not been established because the TJM had not yet been completely updated with equipment identifications (EIDs) and historical work histor~. Attempts were made by the licensee to utilize work history that currently was put in the TJ A tr~nd was defined as two corrective WRs issued on a component in a period of_ six month The inspectors considered this as a 11 gross

approach because potential trends over time or trends common to a specific model number would not be identifie The established frequency, two occurrences in six months was. the same for all com-ponents and did not consider the importance of a component to safet Technical staff engineers performed tests and monitored equipment performanc The inspectors reviewed procedures used to periodically calibrate plant performance ~onitoring equipment and determined that monitoring instruments were calibrate The inspectors reviewed a list of instruments that were used to ~ollect quantitative data during - operator 1s round Of the approximately 50 instruments, 22 were not in a formal calibration program including those associated with the Reactor Waterup Clean, Reactor Building Closed Cooling Water, Control Rod Drive, Main Steam Isolation Valves, Main Generator, Turbine Oil, Condensate, and Off-ga Instruments associated with these systems should have been reviewed for inclusion in the calibration progra The inspectors reviewed several deviation reports, LERs, PADs, and work packages regarding the failure of feedwater regulator valve 2A due to blockage from debri The root cause analysis did not appear t6 correct the problem; however, upon further discussion with the licensee the inspector determin~d that a new valve design was recently installed in Unit 2, which will prevent the intrusion of debri The 11 stacked di sc 11 design was similar to the Unit 3 feedwater regulator valve, f6r which there have been no problems of blockag Resolution of the valve operability problem was acceptabl The inspector determined that the licensee 1s evaluation was acceptable for LER 237/88-0 One cor0ectiv~ action was to inspect the HPCI Gland Seal Leak Off pump motor every refueling outage and to add Pressure Control Valve 2301-46 to the PM progra The inspector verified that these comprinents were identified for periodic surveillanc The lubrication program was described in OAP 7-6, Revisio*n 4, and POS 40-2, Revision 1 Of the 21 components, from which oil was required to be sampled, only 14 samples were trende Paragraph B. of OAP 7-6 required that all oil samples be trende No justification existed for those samples not trende The licensee indicated that some oil samples need not be trended, such as the diesel fuel day tanks, for which new oil was analyzed prior to use in the diesel syste Oil samples were plotted, but a formal report had not been issued with an evaluation of the sample There were several examples of corrective actions, such as oil changes; however, these actions _ appeared to be isolated cases rather than implementation of a fully developed and comprehensive trending progra The _licensee had not

2. fully developed acceptance criteria for a method to present the trended acceptance criteria for evaluation of adverse trends, nor the correlation of sampling data to significant events, such as oil change, filtering old oil, equipment run time, or equipment availa-bility due to unscheduled maintenanc The inspector did not identify any equipment failures caused by oil degradatio Coordination and implementation of the lubrication program was handled by sev~ral station personnel, technical staff and operations, and by correspondence with the corporate office 1s System Material Analysis Department (SMAD).

On-site expertise for the assessment of the samples and trend analysis was still under developmen Work Control The inspectors reviewed several maintenance activities to evaluate the effectiveness of the maintenance work control process to assure that plant safety, operability, and reliability were maintaine Areas evaluated were control of maintenance work orders, equipment maintenance records: job planning, prioritization and scheduliog of work, control of maintenance backlog, maintenance procedures, post maintenance testing, completed documentation, and review of work in progres Preparation, prioritization, scheduling, implementation, and post maintenance review of WRs was described in Procedure OAP 15-1, 11Work Requests, 11 Revision 2 The inspectors attended several morning meetings to observe how licensee management coordinate*d normal plant activities and outage related wor The inspectors attended the morning meeting, the Plan of the Day Meeting, and Outage Meetin With only minor exceptions, all req~ired onsite organizations were represented at those meetin The meetings were relatively structured, purposeful, and appeared to coordinate the efforts of all groups in attendanc The licensee utilized activity schedules that tracked all major onsite activities for the wee The inspector compared work packages completed before and after MIP initiatives were issued and determined that recently completed work packages were better organized and described the activities performed in more detai The TJM data base preserved information from the work packages, which improved efficiency of the maintenance proces Specification of the correct post maintenance test was an important final step in the work process to deter-mine if a component or given piece of equipment was operabl The licensee was dependent on the work analyst for specification of the correct post maintenance test, which was accomplished by use of the guidance developed in June 1988, as documented in Maintenance Department Memorandum 4 To date, the licensee had implemented the memorandum only on a pilot basis by use of one mechanical work analyst on selected WRs. * The licensee planned to incorporate Memorandum 47 into a formal procedure after additional pilot programs have been complete *

• 2. The number of cancelled WRs appeared excessiv Out of a sample of approximately 2000 WRs, October 6 to December 31, 1988, about 20% had been cancelle Based on comparisons to other licensee 1s, the inspectors considered this an abnormally high percentage and a

_drain on th~ licensee 1 s resource The primary cause appeared to be that field personnel were inconsistent in use of the two part WR identification tag. the first part of which should hav~ been hung on the equipment and the Second part attached to the WR for This process would have precluded other persons form duplicating WR The in~pectors determined that analysts reviewed applicable vendor manuals, walked down equipment and systems that required repair, and ensured that correct drawings and procedures were supplied in the work package if require In most cases, maintenance procedures were availabl Work instructions had been developed for repetitive jobs that weri not covered by a procedur The~e instructions were stored on a computer diskette for future us WRs contained adequate work instruction If the *work was outside the scope of the WR, the work instructions were amended and reapprove Except for the problem noted in Section 2.4.2.3, no significant problems related to maintenance planning were note * Overall scheduling and prioritizing of maintenance work appeared to be acceptabl Appropriate emphasis was given to those items of safety significance

Personnel Control The inspectors reviewed the licens~e 1 s staffing control and staffing need Inspection activities included interviews with plant personnel, observations of the training facility, observation of plant activities, and review of documentatio The maintenance training program was accredited by INPO in January 198 The training career path enabled a candidate to advanc~ from apprentice to a journeyman t~chnician in approximately four year The inspector interviewed electrical,

• mechanical, and I&C training coordinator Each had.a 11Training Qualification Matrix 11 that listed the personnel and all general and specific trainin The matrices showed that each plant employee received site specific, security, and radiological control trainin Refresher classes in these areas were conducted on a regular basi Training and qualification records were rev1ewed for approximately 18 maintenance perso.nnel that participated in maintenance activities witnes~ed by inspector Training records were readily available and documented all training receive The inspectors determined from review of the training records that personnel were qualified to perform the assigned maintenance activitie The electrical, I&C, and mechanical departments were staffed with 41, 31, and 108 craft personnel respectively, which appeared to be adequate for non-outage wor During planned outages the licensee used a mobile work force to supplement the electrical departments 27 '2. by about 40%.

This work force was made up of personnel from the local fossil station Craft personnel only received Dresden Nuclear General Employee Training (NGET) training for access to the site, but the foremen received.additional training in administrative and main-tenance procedures, _in addition to training on plant philosoph According to conversations with the Assistant Superintendent of Maintenance, the training _of contractor personnel, in this case, mobiles, was the next area to be addressed by the INPO accreditation proces The inspectors reviewed safety-related WRs that had mobile craft personnel participation to ensu~e that appropriate supervision by station personnel was eviden At all times mobile craft personnel worked on safety-related equipment with a qualified Dresden employe The licensee 1 s control of mobile work forces was satisfactor Shift manning for maintenance was reviewed for all organization All primary organizations were manned durihg the back shift In the event some support organizations were not manned, for example, document control, the department head or designee was on call.* During the inspection there were no instances observed where maintenance activities were adversely effected due to the licensee 1 s shift manning policie ' Observations of Current Plant Conditions and Ongoing Work Activities Observation of Material Condition The inspectors performed general plant as well as selected system and component walkdowns to assess the general and specific material condition of the plant to vei*ify that WRs had been initiated for identified equipment problems, -and to evaluate housekeepin The selected systems and components which were selected are identified in Section 2.0 of this repor Walkdowns included an asses~ment of the ~uildings, systems, and components for proper identification and tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and any unusUa l conditions. _ Unusual conditions included but were not limited to water, oil or other liquids on the floor or equipment; indications of leakage through ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lightin Note: Unit 3 was in operatio Results of walkdown were as follows:

Reserve Auxiliary Transformers 22 and 32 local control panels were observed to be very dusty and had rusted termination points, conduits were not sealed and a rusted tool was laying inside the transformer 32 pane The inspector determined that these cabinets had never had PM performe Lack of PMs could eventually affect the transformer 1s control and-protective circuit '*

..

.. Access to equipment was generally available from the floor or platforms provide Both Unit 2 and 3 HPCI rooms and various levels of Turbine Building were recently painted to improve housekeepin The licensee had begun.a painting program throughout the plant that differentiated Unit 2 from Unit 3 equipment by the use of different color The painting program* should be beneficial in reducing the number of 11wrong unit 11 type personnel errors and indicated-a positive management attitude towards housekeeping. Identification of Unit 2 and 3 HPCI equipment was facilitated by new plastic tags that were prominently displ~yed on or near the equipmen The licensee indicated that all equipment at the station will be similarly identifie \\:Jalkdown of Unit 2 and 3 HPCI systems on February 9, 1989, showed that most of the scaffolding, hoses, containers, tools, and debris identified during walkdowns on January 23 and 24, 1989, had been removed after the work was finishe All maintenance work was completed on the Unit 2 HPCI equipment pending po~t-maintenance testin Un.it 2, 125Vdc MCC 2A battery to main Bus 2A-1 breaker handle indicated approximately three inches away from the ON position, even though the breaker was energize The inspector was informed that when the breaker trips, the handle would then point towards the ON positio In addition~ the licensee indicated that this appeared to be a known -problem with these type of breaker Operating de breakers that are not correctly positioned could result in errors and unnecessary trip During a walkdown of the Unit 2 electrical systems, the 125 Voe MCC 2A ground detector recorder was not inkin A WR identification tag had not been hung on the recorder indicating that a WR had not been initiated. The recorder could have responded to a de ground potential, but would not have produced a permanent recor Within several days, the recorder was repaired by the !M The threshold for writing a WR appeared too high to address some oil and water leak For example, during the walkdown of the Unit 2 HPCI system, the inspector identified a groundwater leak that was dripping onto several valves and equipmen Funnels and hoses were in place to carry away the liquid. There were no WR identification tags hung on the valves and there was no

• wR identified to correct the groundwater leak. Subsequently, the HPCI system engineer generated WR 081718 to address the ceiling leak and to check the valves for leak I I

Unit 3 LPCI 11 B 11 Pump Room housekeeping was substandard even for a room that was going to be painte Contaminated bags and other items were not kept within the roped off area designated for such item A waste oil drum,- solvent cans, and paint cans and rags were lying throughout the roo * Valve 3-2301-10, suction from Condensate Storage Tank, was leaking several drops per minute into a funnel and hose, but no WR had been writte The HPCI system-engineer generated WR D82138 to address the lea * The inspectors reviewed the Unit 3 Appendix D, "High Voltage Operator Round Book, 11 for the i dent ifi cation of abnormal operating conditions and the identification of corrective maintenance item The inspectors identified the following items: U2 Diesel Generator, Auto-OFF Switch in Auto, unmarked position; U2/3 Diesel Generator, Auto-OFF Switch in Auto, unmarked position; and all three Diesel Generator crank case oil level checks low * The inspector discussed the items with the Unit 3 Operating Enginee There was some confusion about what switch the operators were to verify in AUT The licensee determined that it was the Diesel Fuel Oil Transfer switc The switch was ~arked with OFF and ON with a spring return to center, an unmarked position (AUTO).

The licensee will properly identify these switthes and clarify the Appendix D operator rounds log to reflect the equipment identificatio The licensee followed up on the low crank case oil readings and verified that there was sufficient crank case oi There was confusion on how to read the dip stic The dip stick markings were provided by the manufacturer for an operating diese Since diesels at a nuclear plant are normally not operating, the markings were ambiguou The licensee consulted the vendor manuals and determined what the crank case oil level should read on the dip stick for a non-operating diese Also determined was the low level point on the dip stick that would require the addition of one drum of oi This low level mark was well above the minimum crank case oil level required for the diesels to be operabl The inspectors verified that the markings had been inscribed on the dip stick Also, a note was added to the dip stick that stated which markings were to be used for a shutdown diese.16kV EQ switchgear 24-1 contained a differential relay (SA-1) in the DG Cubicle No. 2 that was not labele Also, a start relay in Unit 3 DG engine control cabinet was not labele * Unii 3, 480Vac safety-related MCC 38-1, Compartments C4, F3, Gl, G2, G3, G4, Hl, H2, H3 and H4, and Unit 2 safety-related MCC 29-2, Compartment C contained thermal overload assemblies without reset push button In order to reset the thermal _ overloads, the operator had to open the compartment door, which

• did not appear to be a safe operating practic Compartment Cl of Unit 2 480Vac MCC 29-2 contained a burned-out main power indicating light and the cap was missin This condition apparently was not detected during daily operator round *
• During the walkdown of the Unit 3 HPCI system, the inspector found various oil leaks at the HPCI.main pump inboard seal and oil return line The seals and flanges were not perceptively leaking, but a sizeable puddle of *oil had collected on the ski WRs 081747, 81748, 81749, and 81750 were subsequently generated
• to address the leak *

Out of six WR identification tags identified in the field during the BOP portion of the facility walkthrqugh, one di not have a WR generated for the component, and another had the associated WR cancelled approximately five months earlier but the tag was still attached to the equipmen * A walkdown of the control boards was perfbrmed on the Unit 3 HPCI and LPCI system All control switches were correctly positione There were no annunciator windows lit or equipment caution and/or red tags-hung on any of the equipment associated with the system * A walkdown of electrical components was performed on the Unit 3 LPCI syste The area around the breaker cubicles was free of debris; the breakers were adequately identified and correctly positione * A walkdown of instrument and control components was performed on Unit 3 LPCI syste Generally, equipment was properly identified and maintained; instrumentation cable_s and primary sensor lines were adequately secured; pressure sensing instrumentation was properly valved into service and none of the valves and fittings was leaking; and electrical conduit connections to the instrumentation were properly seal e The inspectors were informed that plant management performed periodic walkdowns of the plant but did not routinely observe work in progres Also, the inspectors determined through discussions with licensee personnel and the review of records that craft supervisofs need to perform more spot inspections in the electrical are Generally, equipment problems identified by the inspectors during plant and system walkdowns had been identified by the licensee 1s WR process or were otherwise corrected except in the electrical maintenance are Overall, the material condition was considered satisfactory to maintain operability of components at a level commensurate with the components 1 functio However, greater management attention to ongoing work and component deficiencies should enhance the material condition of the plant.

• 31
• 2..4. *

Observation of Ongoing Work Activities The inspectors observed ongoing work in electrical, instrumentation, and mechanical maintenance area The inspectors selected activities from the Plan of the Day listings, work assignments in individual maintenance shops and through discussions with individual foreme Where possible, safety significant activit.ies were chosen for foll owu All maintenance activities were witnessed/observed to determine if activities were performed in accordance with required administrative and technical requirement Work activities were assessed in the fo 11 owing areas:

. Administrative approval prior to start of wor * Equipment properly tagge * Replacement parts ~cceptabl * Approved procedures available and properly implemente o Work accomplished by experienced and knowledgeable personne * Appropriate post maintenance testing included and conducte Electrical Maintenance The inspettors observed portions of four electrical maintenance activities as discussed below: WR 73948 lB Recirc MG set generator collector ring WR 81443 - Valves FCV-5202C and FCV-54020 indicating lights~ WR 81765 - HPCI Turning Gear Motor brushe WR 81947 - 4.16kV Bus 24-24-1 Feeder Breaker 2411 burned coi During observation* and review of work performed as required by Unit 2 WR 73948 the inspector noted that part of the LPCI logic was to be bypassed so that MG set work could be performe The temporary system alteration prqcedure was used by the Electrical Maintenance Department to add a jumpe However, the same procedure was not used when the jumper did not accomplish the desired resul Electrical mainten~nce personnel removed an instrument plug connector, without authorization, to establish the necessary LPCI logic to allow the work to be accomplishe The root cause of this problem appeared to be the unfamiliarity of the electrical work analyst and foreman with* the requirements of Procedure OAP 7-4, 11 Control of Temporary System Alterations, 11 Revision 1 This procedure stated in Paragraph 4.(5) that a temporary system alteration evaluation must be performed by engineering prior to alterations to the system, such as plug removal Failure to follow procedures is considered a violation of Criterion V of 10 CFR 50, Appendix B (237/88029-03).

This violation was very similar to the one discussed in Section 2.4.2.3 where corrective action to prevent-recurrence is describe During replacement of the trip coil in Breaker 2411, as described in WR 81947, the inspector observed that the electrical maintenance craft person appeared to have difficulty in measuring and adjusting the 11Trip Armature Clearanc The maintenance procedures did not provide detailed notes and cautions for disassembly and_ reassembly of the trip coi In addition, the required safety-related splice units to reconnect the trip coil were not available in the storeroo The inspectors witnessed work on the 2A RPS MG set contactor breaker as instructed in WR D-8165 The breaker had been overhauled and was being tested in accordance with Procedure DMP-7300 This procedure required a test of the phase A and the phase B overload relay The maintenance foreman told the inspector that if the trip time acceptance crit~rion was exceeded, the procedure instructed the tester to 11 reset the relay and immediately repeat the test.

11 This practice was justified by the licensee because the acceptance criterion was based on a vendor testing temperature of 40 degree_ centigrade (104 degree Fahrenheit) which more closely matched the design testing temperature and would be a more realistic a~sessment of the true time to tri Although the tests did not aff~ct Technical Specification operability, the inspectors were concerned that tests were performed in an ambient temperature that utilized acceptance criterion based on a 104 degree F environment without-documented justification and the apparent philosophy that allows changing initial test conditions - to meet test acceptance criterion without any technical base The inspectors concluded that, generally, the performance of electrical maintenance activities was effectively accomplishe.4. Mechanical Maintenance The inspectors observed portions of 11 mechanical maintenance activities as discussed below: WR 73503 WR 81059 WR 81529 WR 81647 WR 047113 WR 073224 Rebuild limitorque operator for valve 2-3004 Replace CRD strainer drain line Test spring pack for Isolation Condenser Valve 2-125 Rebuild limitorque operator for Valve 2-3201 Modify piping on Unit 2 Offgas Hydrogen Analyze Align coupling on Unit 2 Turbine and Generato *

WR 077760 Install flange on torus drain. WR 077761-1 Install snubber on torus drain pipin. WR 078559-1 Install U-bolt on torus drain pipin WR 079006 VOTES diagnostic valve testin WR 080492 Rebuild auxiliary and emergency oil pump on HPC The inspectors observed portions of the work performed, examfned work package documentation, and interviewed the personnel involve The following observations were made:

Work packages were complete and generally well organize * Travellers included step-by-step discussion, QC hold points for signatures,. and specific instructions to guide the workmen through the work packag * Drawings and Field Change Requests (FCRs) were up-to-dat o Special process permits were included for welding and designated fire watc * Work procedure instructions were augmerited by QC hold points for tightening fastener * Personnel training_ logs were.included in the work packag e Engineering analyses were included for hoisting and riggin * Periodic HP surveillances were witnessed by the inspector during the work activity in the Unit 2 torus basemen * Personnel access log was signed and. a workman was posted at the access hatchway to the torus basemen * Information was transferr~d to other inspection team members, who verified acceptability of materials, personnel training records, and control of calibrated instrument The inspect6rs witnessed portions of work on the CRO system as described in WR 81059, which involved replace~ent of the CRO strainer drain lines with a flexible-metal hos The work request contained work instructions to remove the existing pipe and valves, and install new valves, fittings and flexible hose Attachme~ts to the work request delineated the required valves and flex hoses, but the required fittings were not delineated, which resulted in an approximate two hour delay in the jo The delay was significant because the Health Physics (HP) technician responsible for surveying the job remained at the job site until the required fittings were_

• '

2.4. obtained from the warehous This occurred when HP support was limited at the end of the outag Another delay was encountered because the work instructions were insufficien The flexible hose installation created :a personnel trippi~g hazar The work analyst would not discuss the matter with the foreman nor come to the work are After a lengthy discussion with the foreman the analyst came to the work site and cbncluded th~t the planned rciuting was insufficient and would require modificatio Work on the testing of a Limitorque valve operator spring pack, as des_cribed in WR 081529, was delayed for approximately two hours due to the unavailability of a QC inspecto Since no other instances were encountered of this type, the incident appeared to be isolate The inspectors concluded that performance of mechanical activities was effectively accomplished by skilled maintenance personne The maintenance p~rsonnel appeared conscientious and knowledgeable of the work performe The performance of these tasks was witnessed entirely or in part by the respective foreme Involvement of QC personnel was observed during the torus drain work performed by Project and Construction Services (PACS) and substation construction personne Work on the turbine gen~rator coupling by plant personnel was witnessed by the GE representative who verified critical measurements and provided technical advice for achieving final alignmen * Throughout the performance of these tasks, the inspector was favorably impressed by the morale and experience level displayed by the personnel involve There was good commYnication between maintenance and operations group None of the jobs witnessed were delayed by problems of material availability or conflicting activitie !here were no problems identified during the observation of the above task Instrumentation Maintenance The inspectors observed portions of four instrumentation mainfenance activities as discussed below: WR 053914 WR 077549 WR 081632 SP 89-1-12 Color band control room indicators with normal/abnormal operating range Calibrate Local Power Range Monitor alar Calibrate HPCI area temperature switche Test RPS response tim Work instructions for WR 081632 detailed the removal of two HPCI area temperature switches and installation of a jumper to change the configuration of the plan Step 2 of the instruc~ions was confusing, in that it stated, 11 Place a jumper as per the attached

2. * checkoff sheet If OAP 7-4 is required note the Jumper Log Number of the checkoff sheet.

Procedure OAP 7-4, 11 Control of Temporary System Alterations, 11 Revision 11, was used to control temporary system alterations and provide the steps to perform a Safety Evaluatio Evaluation and on-site review was required prior to the installation of a temporary alteration.* In the above case, the evaluation had been initiated; however, the temperature switcn removal and jumper installation had commenced prior to approval of the Safety Evaluatio This appeared to be the result of confusing work instruction * Failure to follow Administrative Procedure OAP 7-4 is considered an example of a violation of Criterion V of 10 CFR 50, Appendix B (249/88030-03).

The licensee took immediate corrective action The work was stopped and Discrepancy Record 89-013 was initiate The following training was provided to all IM department management: (1) work analysts were instructed to be more precise in work instructions *as to when a Temporary System Alteration Authorization Sheet was required; (2) a training synopsis was presented to clarify the need for a Temporary System Alteration Authorization Sheet; and (3) foreman were requi.red to check for the requirement to use Temporary System Alteration Authorization Sheets during pre-job package reviews and if the use of a sheet was suspected, but not specified, the work package would be returned to the work analyst for review and clarificatio The inspectors determined that the training would be adequate to prevent recurrence and also verified that al~ IM management personnel had received the trainin There was no impact on safety from the jumper installatio A similar violation of Procedure OAP 7-4 is described in Section 2.4. The corrective actions described above were considered sufficient to resolve both issue The inspectors concluded that p~rformance of IM activities were effectively accomplished by skilled IM personne Except as noted, IM personnel appeared conscientious and knowledgeable of the work performe Radiological Controls The inspectors observed work being performed in contaminated/ radiation areas, movements of tools/equipment to and from these areas, and interactions of workers with radiological controls* personne Generally, health physics support and oversight of ongoing work or with ALARA review of specific tasks w~s adequat Radiological controls, posting, and labeling ~ere generally goo Cleanliness and housekeeping appeared generally good for extensive outage conditions.. Through observation of work in prociress and discussions With licensee personnel, the inspector determined that radiological controls were generally integrated into the maintenance process as evidenced by:

Proposed facility changes were formally reviewed by the ALARA grou An experienced radiation protection person reviewed WRs to determine the need for a Radiation Work Permit (RWP) and an-ALARA revie * An ALARA group representative attended job~planning meeting * A computerized RWP/TLD-SRD do~e tracking system was used as an ALARA too * QA audits of the radiation protection program, including ALARA, were performed and findings were addressed. . * Station dose goals were established, and work gr*oup doses were tracke * Monitoring to support RWP issuance, RWP job coverage, and use of dosimetry appeared goo On jobs where the RWP was adequately developed through communications between the affected departments, the RWP and/or the work orc;ler and procedure was adequately detailed to assure adequate job coverage, and enough advanced notice was given to the radiation protection department so that adequate Radiation Control Technician (RCT) support was available. The inspectors noted that improvements in the following areas could be made:

Work packages and/or associated RWPs for work performed in radiologically significant areas did not always contain detailed radiation protection precautions and hold points to assure that proper radiation protection practices and requirements were followe * Work packages, for work in radiologically significant areas, did not always contain tool/equipment/staging requirements; therefore,. unnecessary dose could be received fo radiation/ high radiation areas because of ineffi~ienc (Refer to Section 2.4.2.2 for a specific example.)

• It appeared that additional, enhanced, radiation w6rker training was needed for persons who perform work in. radiologically controlled area This need was made evident when shortcomings were observed in handling potentialiy radioactive materials and equipment such as used protective clothing, tools, respirators, and radwast Similar shortcomings were described in licensee radiological occurrence and personal contamination report M~nagement ~upport for radiological controls and ALARA programs appeared adeq~ate*, ~hich was evident by reductions in personal doses, personal contamination events, and the exten~ of contaminated areas

2. over the past few year Further improvements, such as space management during major outages appeared necessary to effect further reductions.* Maintenance Facilities, Material Control, and Control of Tools and Measuring Equipment The inspectors re-viewed activities in the areas of facilities, equipment, and material control to assess support given to the maintenance proces Interviews were conducted with various maintenance management and craft personnel to determine the policies, goals, and objectives; and followup observations were performed to determine the extent to which the plan practic~s, procedures, equipment, and layout supported the maintenance proces The three maintenance groups had separate workshop area.4. Facilities The mechanical, electrical, and instrument maintenance workshop areas were located in the Shop and Warehouse building inside the protected area, but outside the radiologically controlled are The mechanical shop.contained a machine tool area, small hot shop, small hot storage area, tool crib, hot tool crib, vendor manua.l library, offices for the master mechanic, maintenance foreman, and other support staf The inspector observed that large plastic tents were in place around tools and equipment which had the potential to create an airborne contamination are Although no work was in process, the inspector observed that several workers were eating food next to a roped off area by one of the tents, which did not appear to be a radiologically sound practic There was an area specifically designated for the rebuilding of CRD assemblies immediately adjacent to the reactor buildin In addition, the Unit 1 turbine floor wris 11sP.ci for the rebuildinq of Limitorque valve operator The licensee's policy about work on contaminated objects was that the item must be surveyed for contamination prior to exiting the radiologically controlled area and entering any sho The tool washdown/decontamination facility was centrally locate These practices minimized the spread of contamination and allowed better utilization of a relatively small mechanical maintenance shop, which was not equipped to routinely handle these task As a result of a recent INPO inspection, the licensee had taken action to remove flammable material from the maintenance shop area at night and when not in us No unattended flammable materials were noted during the inspectors walkdown of maintenance facilitie Mockup facilities were not in use during the inspection, although the inspectors d~d observe a mockup for CRD removal and mechanical stress improvement program (MSIP).

Mockups of Limitorque valve operators were used to train and qualify electricians and mechanic.4. Access to the el ectri cal shop was fr,om outdoors or through the mechanical sho There were plans to add a new electrical maintenance shop, which will be on the first floor and have-better plant acce.s The current shop area was clean, had a good layout of work benches with several bench tools, and a tool cri There were also offices for the master electrician and foreme The instrument shop was more centrally located and closer to the control room and plan The shop was well lit and each IM had a work benc The general foreman and scheduler shared the same office, which appeared to provide means for initiating good work planning and communication The room also contained equipment calibration records, surveillance test packages, and vendor manual The IM master and IM assistants were located near by and were ffequently observed in the shop area assisting with maintenance i tern As part of the MIP, the licensee plans to expand the maintenance facilitie On average, this includes an increase in shop size of about 20% for each shop in addition to added office space to accommodate maintenance engineers, planners, and schedulers, who are currently located in trailers or other areas remote from the shop Laydown areas appeared td be sufficient but crampe * All maintenance foremen were assigned a beeper that could be accessed anywhere in the plant~ Throughout this inspection, this communication system demonstrated its effectivenes Material, Equipment, and Tool Control The warehouse facility included good Level A and Level B storage spac Physical control of access to the warehouse facility was good, environmental controls were effective, cleanliness and housekeeping aspects were very goo Policies and procedures were docume~ted and implemented for procurement of parts and material Guidelines were established anD effectively implemented to address lead time for procurement, specification for parts and materials, documentation requirements, testing, inspections, acceptance records and stock quantitie Guidelines were also established to expedite

• emergency procurement through the Pool Inventory Management System (PIMS).

Reorder points were set by the Maintenance Department but controlled by warehousin A "Physical Inventory List" was generated by computer and used by the inspector to access controls and identification of materia The Inventory List described the item, identification number, physical location, date last inventoried, and shelf lif Shelf life

• controls we~e in effect as well as controls for consumable materials such as solvents, lubricants, gasket materials, and welding rod A separate storage facility was established for flammable material and other materials that required special handlin Guidelines and controls were established for the issuance and return, of unused materia *

'2.4. Overall, program concepts and performance in this area were good, however, two concerns were identifie * .Material was delivered to the mechanical contractor 1s warehouse facility where the material was receipt inspected and controlled; however, material for other contractors was also delivered there and stored in a roped off 11 Hold 11 are No 11 List of Materialu on 11 Hold 11 was maintained which made it possible for material to be picked up and misplace Misplacing of electrical switches did delay control room work for an extended period of tim * Safety-related items were procured from a vendor not listed on the Quality Approved Bidders Lis BWR corporate engineering purchase requisition NU-8428 (Purchase Order 763497) was issued to procure four GE type SBM switches, but failed to adequately identify the ijpproved vendor 1s location on the requisitio The requisition was intended for GE in San Jose, California, but instead went to GE in Schenectady, New York because the Quality Assurance (QA) coordinator. and purchasing agent failed to identify the approved vendor plant locatio GE Schenectady was not listed on the 11Quality Approved Bidder List 11 to supply the switche The switches arrived at the warehous~, but were not receipt inspecte Alsoi the switches were issued without proper documentation and misplaced until found by a tech staff enginee The procurement problem was identified before the switches were installed. The inspector ~eviewed the procurement process by selecting three purchase orders (POs) including 501335DR80 and 502042XX28 The inspector verified that the vendor was an approved source; reviewed the method utilized for acceptance of the procured item; and ascertained that the correct quality and technical requirements were in the P No problems were identifie Cbntrol and Calibration of Measuting and Test Equipment (M&TE) Each_department maintained its own tool crib and tool issue/return lo T~e log listed information such as: job and tool description, issue return dates, and personnel name Tools were returned on a daily basis and log sheets were maintained for two year Procedures were developed and implemented for the issue, return, and recall of M&T The inspector performed a walkdown of all three tool cribs and verified that equipment identification and storage requirements were me All equipment was identified by labels with equipment name, identification number, calibration date, next calibration due date, and equipment locatio A yellow 11 Certified M&TE 11 tag was~ attached to M&TE certified ciffsite by System Operational Analysis Department (SOAD); a yellow 11 Certified 11 sticker was attached to M&TE certified onsite; and a green 11General Usage Equipmentu tag was attached to equipment that required attention to keep it in safe and serviceable conditio Control and storage of M&TE was good in that defective or 11 calib.ration due 11 instruments were stored in a separate room away from those that were in calibration and acceptable for us The inspector checked the status of three M&TE items used for work observed b~ other inspector The issuance and return process was verified for Digital Multimeter DW-4, Digital Multimeter 127290D, and Temperature Monitor DT-24 used f6r WRs 77549, 79163, and 81632 respectivel Maintenance supervisors maintained good records and made it possible to review documentation that otherwise would have had to be reviewed at SOA A 11Tech Center Instrument System Monthly Report 11 was generated by SOAD that listed the calibration schedule and identified the tools which were to be certifie Tools were picked up by S9AD, located offsite, during the month calibration was due and returned to the station after calibratio The inspector interviewed the electrical, mechanical, and instrumentation maintenance supervisors who were responsible for M&TE contro The activities and records related to control calibration~ and management of M&TE met program requirements and commitment.5 Licensee 1 s Assessment of Maintenance (Quality Verification) 2. The inspector evalu_ated the licensee 1s quality verification process in the maintenance area by the review of audit reports, surveillance reports, trending and corrective action documents, and the maintenance self assessmen The documents were reviewed to assess ~echnical adequacy, root cause analysis, timeliness of corrective action, and justification for closeout of corrective document Review of Audits and Surveillance The inspector reviewed 10 QA audits and 12 QA surveillances of maintenance activities performed during 198 The QA audits and surveillances were performance based and managemPnt gave adequate attention to the areas of closing audit findings and followup of* corrective action The licensee utilized experienced personnel and technical experts to co~duct audits and surveillances which were performed in accordance to schedule A total of 56 onsite and 4 offsite audits were complete The ~udit*findings were analyzed and assigned to a matrix containing-the 18 requirements found in-10 CFR 50, Appendix B - 11Quality Assurance Criteria for Nuclear Power Plants and.Fuel Reprocessing Plants.

Apparent trends were noted in_ areas of Criterion V - Instructions, Procedures, and Drawings and Criterion VI - Document Contro The QA program for trending was effective in audit findings and identifying significant trends that may develo The areas identified by the inspector, were also found by the licensee and reported in the Quarterly Trend Repor The QA group also performed 252 surveillance inspections during 1988 with an emphasis on operations and maintenance area QA deficiencies were tracked by computer, which generated a printout for quarterly followu The printout described the problem, type

J

2...6 2.. of audit/surveillance, root cause code, auditee 1s response and new statu The status of the deficiencies was document~d and filed by the assigned QA inspecto Review of Corrective Action Findings from Maintenance Audits 12-88-17, 12-88-18, and 12-88-23 were followed up, reviewed for corrective action and closed_by the licensee._ A total of 10 findings were reviewed by the inspector and appeared to be adequat For example, audit finding 3 from Maintenance Audit 12-88-17 identified spare parts for Environmentally Qualified electrical equipment found in the storeroom, which did not meet current QA Manual Documentation requirement Monthly followups were performed by QA and the audit was closeef based on review of EQ records, completed receipt inspections of existing items, and a better set of purchas~ ~equirements by BWR Engineerin Review of Maintenance Self-Assessment The inspector reviewed the report of the licensee's self-assessment of maintenance performed in June 1987, which consisted of team members from the six CECo plants and INP This self-assessment included evaluations of 16 maintenance area A second assessment was performed in September 1987, by a team that consisted of INPO, EPRI, and GE personnel along with Dresden Station managemen This second assessment was performed in the seven weakest maintenance areas identified during the first assessmen As a result of the assessments, a 11 Conduct of Maintenance 11 program, which has been discussed throughout this report, was initiated to improve corrective, preventive, and predictive maintenanc Estimated implementation_ date of the program is April 199 Overall, the licensee's self-assessment of maintenance was effectiv QA audits of maintenance were performanrr h~s~d. Also, deficiencies identified and corrective actions were being tracke Overall Plant Performance Performance Indicators The inspectors reviewed historical data that included licensee event reports, availability factor for selected systems, forced outage rate and reliability data such as reactor trips and engineered safety feature actuations, which for 1988, were below the industry average High pressure coolant injection and emergency diesel generator availability factors indicated improvement overal Plant performance for 1988 was goo Plant Walkdowns The material condition of the plant was satisfactory and no condition was noted that would have immediate adverse impact on operability of equipmen Housekeeping, overall, was satisfactor The following strength and weaknesses were identifie. l

• . *

Equipment identification was good as compared to other plants inspecte * Threshold for writing work requests appeared too high to address equipment deficiencie * Hardware deficiencies were not identified on a work request including a Unit 2 125Vdc battery feed breaker handle, missing Unit 3 motor control center overload reset buttons, water leaking into Unit 2 high pressure coolant injection room, and an oil leak from the booster pump bearin * Emergency diesel generators 2; 3, and 2/3 excitation field breakers and reactor protection system breakers were not included in the preventive maintenance progra Management Support of Maintenance Management Commitment/Involvement Management was committed to improve maintenance activities at Dresden as shown by several improvements that were initiate The Maintenance Improvement Program was a broad based program_to improve maintenanc The inspectors identified strengths in the maintenance program that indicated management was committed to the improvement of maintenance at Dresde For example:

Active participation in industry initiatives such as Institute of Nuclear Power Operations, Boiling Water Reactor Owners Gfoup, Electrical Power Research Institute, Nuclear Utility Management and Human Resource Committe * Initiation of the Maintenance Tmprnvement Progra * Personnel knowledgeable of and dedicated to the Maint~riance Improvement Progra * Use of time series analysis of equipment failures to determine preventive maintenance requirement * Use of probabilistic risk analysis 6f the high pressure coolant injection syste * Periodic assessment of the Maintenance Im~rovement Program by corporate personnel and subsequent corrective action by station personne * Improved reliability of motor operated valves by use of teams for preventive maintenance.

Initiation of a strong preventive maintenance program for safety-related valve * 2. *

Aggressive resolution of the 4.16kV breaker Tuf-Loc bushing proble However, continued involvement and strong commitment by man~gement is necessary to improve maintenance activi-ties to the level desired by Commonwealth Edi so For example:

Non aggressive preventive maintenance program for 4.16kV circuit breakers and Unit 3 250 Vdc motor control c~nte * Inadequate resolution of problems with 11 SBM 11 switche * Slow progress in establishing an equipment trending progra Management Organizations and Administration The inspection indicated there was strong per-formance of the management organization in the administration of the maintenance progra Examples of strengths in the management organization and administration were: o A long ra~ge maintenance plan had been established as specified in the Conduct of Maintenance manual.

Personnel were dedicated to the Maintenance Improvement Progra * Plant improvements were evident, such as, resolution of the Tuf-Loc bushing problem, replacement of the high pressure coolant injection booster pump impeller, and the plant painting progra * Maintenance of safety relief valves and motor-operated valves was goo However; there were areas that needed increased management attentio For example:

Resources had not been adequately allocated to close out PAD * Administration of a preventive maintenance program for 4.16 kV breakers and Unit 3 250Vdc motor control centers was wea Some components had not had preventive maintenance since 197 * Performance indicators did not measure effectiveness of maintenanc * Plant aging consideration for electrical components had not been addressed.

J

2..8 2. Technical Support Technical support of mai nte.nance was satisfactor The inspectors identified the following strengths:

A probabilistic risk assessment of the high pressure coolant injection syste * Procedures for motor-operated valve maintenance and testing were detailed, user friendly and incorporated previous lessons learned: However, some weaknesses were identified:

Inadequate root cause analysis and corrective action for the 20 low pressure coolant injection breaker and the isolation condenser motor-operated valv * Trending prbgram did *not consider component significanc * Inadeq~ate quality control observance of electrical work activitie The following observations were noted conternfng the MI * The program analysis date system had not been fully implemented. Critical high pressure coolant injection system skid mounted components had not been identifie * Only about 1/3 of the vendor manuals were controlle * Only about 3 of 15 systems had been walkdown to verify equipment identification ~umbers for incorporation in the total Job Management Progra Completion of thi~ work was not ~xpected before early 199 * A new post maintenance testing program was being developed~ Maintenance Implementation Work Control Work control activities were satisfactor The inspectors identified the following strengths:

Backlog of corre~tive maintenance was lo * Post job checklists provided work analysts with useful informition for planning future work activities.

" l;

2. *

However, weaknesses did exist as follows:

Work was initiated without adequate engineering revie * Total Job Maintenance histories we~e incomplete for completed work request * Planning adversely affected several work activities due to lack of spare parts, identification of needed parts, unavailability of QC and unplanned operations which caused increased area radiatio *

Time required for maintenance was actually twice that estimate * Work requests for corrective maintenance were i~correctly identified as preventive maintenanc *

Work request probable cause blocks were inconsistently completed and not ~sed_for trendin * Measuring and testing equi~ment range and accuracy was inconsistently spRcifi~ Plant Maintenance Organization Performance fn this are was goo Examples of strengths were:

Morale and experience 1evel of maintenance personnel was hig * Pneumatic measuring and testing equipment was calibrated before and after critical plant instrument calibration * Setpoint trending program was goo * Communications between maintenance*and operations was goo Some weaknesses were noted:

Preventive maintenance status of 4.16kV breakers and 250 Vdc MCCs was not known by the electrical departmen * 4.16kV breaker maintenance performed prior to October 1988 was not technically evaluate * A coordinator did not exist for electrical vendor manual update * Testing techniques for thermal overload devices partially defeated the purpose of performing the test. A trend program based ~n equipment histories had not been establishe "" 2.. Maintenance Facilities, Equipment, and Material Control Performance in this area was satisfactor The fo 11 owing strength

• and weaknesses were identifie *

Traceability of materials used was goo * Lists of material on hold at contractor facilities did not exis * Electrical switches were purchased by the corporate organization from an unapproved source; no copy of the purchase order was sent to the sit Peisonnel Control Personnel at vari.ous management levels were interviewed and were knowledgeable of responsibilities and accountabilit The staffing requirements for mechanical electrical and instrum~nt departments appeared to be adequate for non-outage.wor The mechanical and electrical departments were adequately supplemented with a mobile work force during planned outage The following strengths were identifie *

• Personnel Training Matrix was a useful tool to identify personnel qualified to perform specific tasks:

Training records were readily available and documented all trainin * Mockups were a useful training too. Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviation An unresolved item disclosed during this inspection is included in Paragraph 2.3.2.1 of this repor. Exit Meeting The inspectors met with licensee representatives (denoted in Paragraph 1) on February 16, 1989, at the Dresden Plant and summarized the purpose, scope, and findings of the inspectio The inspectors discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspectio The licensee did not identify any such.documents or processes as proprietar ', AC ADS ALARA AOP BOP BWR CECO CM CMWR COM CRD DC DG DVR ECCS EOG EID EM EPA EPRI ESF EQ FCR GE GEI GEK G.E SAL GE SIL GSL GSUR HPCI HP I&C IEB IEN IM INPO INWC ISI/IST K LER LPCI MCC MG MIP MM MOV MSIP MSL M&TE APPENDIX A Alternating Current Automatic Depressurization System As Low As Reasonably Achievable Auxiliary Oil Pump Balance of Plant Boiling Water Reactor Commonwealth Edison Company Corrective Maintenance Corrective Maintenance Work Request Conduct of Maintenance Control Rod Drive Direct Current Diesel Generator Deviation Report Emergency Core Cooling System Emergency Diesel Generator Equipment Identification Electrical Maintenance Electrical Protection Assembly Electrical Power Research Institute Engineered Safety Feature

Environmental Qualification Field Change Request General Electric General Electric Instruction General Electric Vendor*Manual General Electric Engineering Service Advice Letter General Elecfric Service Information Letter Gland Seal Condenser Hot Well General Surveillance High Pressure Coolant Injection Health Physics Instrument and Control IE Bulletin IE Notice Instrumentation Maintenance Instit~te fof Nuclear Power Operations Inches of Water Column Inservice tnspection/Inservice Testing Kilo Licensee Event Reports Low Pressure Coolant Injection Motor Control Center Motor Generator Maintenance Improvement Plan Mechanical Maintenance Motor Operated Valve Mechanical Stress Improvement Program Main Steamr Line Measuring and Test Equipment-1

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) - NGET NP RDS NRC NTS NUMA RC OPEX PACS PAD PIMS PM PMWR PO PRA QA QC RBCCW RCM RCT RPS RWCU RWP SAL SALP SER SIL SMAD SOAD SOER SRV SSMF TJM TS v VOTES WR Nuclear General Employee Training Nuclear Power Reliability Data System Nuclear Regulatory Commissio Nuclear Tracking System . Nuclear Utility Management and Human Resource Committee - Operating Experience Report Project and Construction Services Program Analysis Data Sheet Pool Inventory Management System Preventive Maintenance Preventive Maintenance Work Request Purchase Order Probability Risk Assessment Quality Assurance Quality Control Reactor Building Closed Cooling Water Reliability Centered Maintenance Radiation Control Technician Reactor Protection System Reactor* Water Cleanup Radiation Work Permit Service Advice Letter Systematic Assessment of Licensee Performance Significant Event Report Service Information Letter _System Material Analysi~ Department System Operational Analysis Department Significant Operating Experience Report Safety Relief Valve General Surveillance System Master File Total ~ob Management Technical Specification Volt Valve Operator Testing and Evaluation System Work Request .2-1 I Appendix A

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~ DRESDEN REPORT .50-237/88029 50-249/88030

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