ML17199T451

Diagnostic Evaluation Team Rept for Dresden Nuclear Power Station

ML17199T451
Person / Time
Site:	Dresden
Issue date:	11/06/1987
From:	Jordan E, Spessard R NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
To:
References
NUDOCS 8712020252
Download: ML17199T451 (94)

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DIAGNOSTIC EVALUATUION TEAM REPORT FOR

• DRESDEN NUCLEAR POWER STATION U.S. Nuclear Regulatory Commission Office for Analysts and Evaluation of Operational Data Division of Operational Assessment Diagnostic Evaluation and Incident Investigation Branch e71*20202s2 si112s 1 PDR_

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OFFICE FOR ANALYSIS AND EVALUATION OF OPERATIONAL DATA DIVISION OF OPERATIONAL ASSESSMENT Licensee:

Commonwealth Edison Company Facility:

Dresden Nuclear Power Station

• *Docket No.:

• 50-237 /249 Onsite Evaluation:

August 17 through 28, 1987 Exit Meeting:

September 23, 1987 Team Manager:

R. Lee Spessard, AEOD Deputy Team Manager:.

L. Joe Callan, Region IV Team Leader:

Henry Bailey, AEOD Team Members:

.Larry W. Garner, Region II Arthur T. Howell, III, AEOD Thomas Johnson, Region I David J. Lange, Region I Nathan J. Lewis, Jr., AEOD Ronald L. Lloyd, AEOD Robert L. Perch, AEOD Susan F. Shankmann, NRR Thomas Silko, AEOD Dennis, J. Sullivan, Jr., AEOD James E. Wigginton, NRR Submitted by: P/~~~~-

R. Lee spessa'fct~-::

Approved by:

Director, AEOD 1~/?1 Date

e.

EXECUTIVE

SUMMARY

NRC senior management concluded that additional information was needed to make an informed decision on the overall performance of the Dresden Nuclear Power Station.

The information was needed to supplement other findings and inputs, such as those associated with the Systematic Assessment of Licensee Performance (SALP) reports, performance indicator (PI) analysis and the routine NRC

'*inspection prograni.

In this* regard, *sALP and other NRC Observations indicated that the licensee 1 s performance seemed to fluctuate between average and below average, and past improvement programs initiated by the licensee had not resulted in the desired level of performance over the long-term.

To*provide the needed information, the Executive Director for Operations (EDO) directed the Office for Analysis and Evaluation of Operational Data (AEOD) to perform a diagnostic evaluation of the Dresden Station.

To implement the EDO's directive, a diagnostic evaluation team (DET) was eitablished to:

(1) evaluate a number of aspects of Dresden's performance including personnel attitudes toward safety, management i nvo'l vement in station operations, and the effect of recent improvement initiatives on station performance and personnel attitudes; and (2) determine, to the degree possible, the fundamental or root causes underlying performanceproblems.

Based upon the team assessment, it was concluded that the fundamental or root causes of Dresden 1 s frequently 1 ow and fluctuating performance hi story were:

(a) Dresden had not received strong and indepth corporate attention in the

. past, (b) an attitude and approach existed that had not been directed at achieving or maintaining a high standard of safety performance, and (c) past.

improvement initiatives had been largely a reaction to findings by INPO and the NRC, and had not been developed.in a specific and complete way to overcome Dresden deficiencies.

In addition, major weaknesses in maintenance, inservice testing, communications and training were contributing causes.

Some of the current difficulties were believed to be due to past and current resource limitations.

For example, it was found that Dresden's management and staff were overextended and additional management and staff resources were required for long-term*improvement.

This aspect may explain the exi-stence of mixed attitudes of station personnel toward management and the management initiatives for improvement.

The team found that many operating and support personnel did not understand the improvement initiatives and were skeptical of management's commitment to them.

The success of past improvement programs at Dresden has been mixed.

Some present programs had met with a considerable degree of short-term success; for example, there had been a dramatic reduction in contaminated areas, reductions in personnel contaminations, reduction in personnel errors, and a significant improvement in cleanliness inside the plant.

These initiatives, combined with a painting program, had greatly improved plant appearance.: Personnel morale, although generally low overall, had been improved by these initiatives.

The results of other present initiatives such as new management trending tools (weekly and monthly reports), an upgraded modification program, a maintenance assessment, a safety system functional inspection of an emergency diesel generator, and extensive management changes were not yet to the point where a 3

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judgment on effectiveness could be made.

The team found that for the most part the Dresden staff had a positive attitude towards safety.

Despite past and present improvement programs, the team found a number of major weaknesses.

These included maintenance (particularly of motor-operated valves), inservice testing, organizational communication, and operator training.

Because of a history of poor maintenance and testing practices, the

• **. --.team concluded that wear, aging,* and an accumulation of equipment deficiencies*

could cause system and component unreliability.

Further, the team found that communication was poor across the organization; and that the operator requalification program remained unsatisfactory.

As discussed earlier, these weaknesses were significant contributors to Dresden's poor performance history.

. An immediate safety 'concern associated with excessive operator overtime was also* identified by the team.. The team found that a Unit 2 NSO (licensed operator), who was responsible for unit startup, had worked six double shifts (each shift is 8.hours) in a 7-day period. *This overtime, which* was uncontrolled by management, had been occurring on a regular basis sjnce late 198£.

The licensee took ~rompt corrective acti6n on this concern; It was concluded that Dresden's performance was currently on the low side of average with a slowly improving trend.

However, confidence was not high that, without additional major CECo involvement, Dresden's performance would show significant and sustained* improvement.

This view was due to Dresden's fluctuating past performance history, the weaknesses in the present improvement initiatives, a lack of improvement initiatives in several critical areas, and limited financial and human resources.

In summary, the corporate objective of achieving an overall SALP rating at Dresden.of 1.5 by 1990 would require a substantial commitment to additional improvement initiatives by the Commonwealth Edison Company.

TABLE OF CONTENTS EXECUTIVE

SUMMARY

ACRONYMS

' 1. 0 INTRODUCTION

1.1 Background

1.2 Scope and Objective 1.3 Methodology...

1.4 Plant Description.

2.0 EVALUATION RESULTS..

• 2.1 Major Findings and Conclusions 2.2 Specific Findings and Conclusions 2.2.1 Operations....

2.2.2 Maintenance.

2.2.3 Testing.....

2.2.4

• Operator Training 2.2.5 Quality Programs..

2.2.6 Radiation - Chemistry.

2.2.7 Management Overview.

2.3 Fundamental or Root Cause(s) Determination 3.0 DETAILED EVALUATION RESULTS 3.1 Operations...

• 3.2 *Maintenance.

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3.3 Testing.....

3.4 Operator Training 3.5 Quality Programs..

3.6 Radiation - Chemistry 3.7 Management Overview.

4.n EXIT ~EETING.......

APPENDIX A - Exit M~eting Notes APPENDIX B - EDD Direction to Team 5*

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8 9

9 11 12 12 12 13 14

.15 16 17 18 19 21 23 23 33 48 56 59 63 68 76

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AEOD AOP APRM ASCO ASM

• • ASME BOP CAL CE Co CRD OAP DET OMP DOP DPM.

DR DRP DVR EOG EDO EM EO EPRI*

EQ FRV.

FSAR FWCS GE HCU HP HPCI HRA IDLH

.IE IH INPO IRM lST JCO LCO J...

ACRONYMS Office for Analysis and Evaluation of Operational Data auxiliary oil pumps average power range monitor American Switch Company*

Assistant Superintendent for Mainttmance

• American Scici ety. of Mechanica 1 Engineers balance of plant confirmatory action 1 etfer Commonwealth Edison Company control rod drive Dresden Administrative Procedtire

• Diagnostic Evaluation Team

• Dresden 'Maintenance *Proced~re.

Dresden Operating Procedure disintegrations per minute discrepancy record Dresden Radiological Procedure deviation report emergency di~sel generator Executive* Di rector** for Operations electrical maintenance.

equipment operator Electric Power Research Institute environmental qualification feedwater regulating valve Final Safety Analysis Report feedwater control system General Electric hydraulic control unit health physicist high-pressure coolant injection high-radiation area immediately dangerous to life and health Office of Inspection and Enforcement industrial hygiene Institute of Nuclear Power Operations intermediate range monitor inservice test justification for continued operations limiting condition for operation 6

LER LPCI LPRM M&TE MM MOR MOV

• .. -*Ms MSOP N-GET NOE NRR NSO NTS P&ID PI PRV PS QA QC RAD CON RBD RC RI RP RPM RPS RWCU SALP SCRE SE SLCS sos SPVAH SRI SRO SSFI SS OM I TJM licensee event report low pressure coolant injection low-power range monitor measurement and test equipment mechanical maintenance maximum occurrence report

. motor-operated valve.

main steam main shaft oil pump nuclear-general employee training nondestructive examination Office ~f Nuclear Reactor Regulation nuclear station operator nuclear tracking system piping and instrumentation diagram performance indicator(s) pressure regulating valve pressure switch quality assurance quality control radiation control reactof building drains radiation-chemistry resident inspector radiation protection Radiation Protection Manager reactor protection system reactor water cleanup systematic assessment of licensee perfattman~

Shift Control Room Engineer Shift Engineer Standby Liquid Control System Shift Overview Superintendent scram pilot valve air header senior resident inspector senior reactor operator safety system fUnctional inspection Safety System Outage Modification Inspecdtiia:m ((ftff{C,, 119HfD))

total job management 7

1.0 INTRODUCTION

1. 1 Background Over the years, the performance of the Dre5den station has fluctuated.

At times the station has been considered a below average performer, and as a result, -cECo would institute improvement programs.

Subsequently, performance as measured _by ~ALP results and o_ther _NRC_ findi~gs.would be notably better._

Usually the station's performance would lnprove to about "average. II All too frequently, however, past improvements ha1e been relatively short-term rather than permanent.

Performance which improved to "average" would over time slip or regress, until the performance would again become lower than average.

At this point, the cycle would repeat.

The net result was that over the past _

several years of Unit 2 and 3 operation, the expected or desired high level of safety performance never has been sustained.

NRC senior.management concluded in June 1987 that additional information was needed ~o make an informed decision on the overall performance of the Dresden Wuclear Power *station. The information was needed to supplement other findings and inputs, such as those associated with the Systematic Assessment of Licensee Performance (SALP) reports, performance indicator (PI) data and the routine NRC inspection program.

To provide the needed information, the Executive Director for Operations (EDO) directed the Office for Analysis and Evalua_tion of Operational Data (AEOD) to perform a diagnostic evaluation of the Dresden Station.

To implement the EDO's directive, a diagnostic evaluatiOn team (DET) was established to:

(1) evaluate a number of aspects of Dresden's performance including personnel attitudes toward safety, management involvement in station operations, and the effect of recent improvement initiatives on station performance and personnel attitudes; and (2) determine to the degree possible*, the fundamental or-root causes of performance problems.

The Diagnostic Evaluation Program was developed by AEOD in response to an August 6, 1986-, memorandum from the Chairnan, NRC, to the EDO.

The charter provides for a comprehensive assessment of current performance at plants.

designated by the NRC to augment information provided by the SALP and PI programs and other assessment data.

The diagnostic evaluation is characterized by the following:

It is independent of NRC licensing, inspection and enforcement activities, and other NRC assessment programs.

It is performance and safety-oriented.

It responds to specific information needs and typically examines manage-ment involvement and staff actions with regard to plant operation and per"formance.

It attempts to identify and assess root cause(s) for plant performance problems.

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1.2 Scope and Objectives The EDO directed the DET to evaluate the performance at Dresden with a specific focus on:

The attitude toward safety and performance of:

The operating staff, including control rqom operators The plant support staff, particularly maint~nance and radiological controls technicians.

The degree of management's involvement in plant operational activities and its influence on the quality of those activities.

The effect of recent improvement initiatives.

An additional objective was to determine, to the degree possible, why Dresden's

_performance has historically fluctuated, and why past improvement programs have not resulted in long-term, sustained "above average" performance.

1. 3 Methodology The DET combined several methods of evaluation with special emphasis on the conduct of operations and the interfaces between operations and' various functional areas.

The DET:

(1) reviewed documents; (2) observed operations; (3) conducted interviews; (4) attended staff meetings;- (5) held discussions with staff and management; and (6) performed reviews of the functional areas of operations, maintenance, surveillance testing, operator training, quality -

programs, and radiological contrqls.

In addition, a management-overview evaluation included management control and involvement in various aspects of pla~t operation.

The diagnosti~ evaluation began with a visit by the Deputy Team Manager and Team Leader to the NRC's Region III offices and the Dresden site.

The Region III visit included:

(1) reviewing in detail Dresden's SALP and NRC regulatory actions, (2) meeting with the Station Manager and several of his staff, and (3) obtaining selected Dresden procedures.

This visit was followed by two weeks of in-office document review and meetings by the team.

On Monday, August 17, 1987, the team started a 2~week onsite evaluation.

During the onsite phase, -the team held extensive meetings with the licensee and station management, conducted 84 interviews at the first line supervisory level and below, and made a detailed assessment of selected corporate documentation, such as the CECo Strategic Plan.

The scope and nature of the team's evaluation for the six functional areas were as follows:

Operations activities were assessed by reviewing the control of procedures, records and operating logs, temporary modifications, and system tagouts.

The team conducted three days of round-the-clock coverage 9

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of control room activities and had routine daily tours of the control roo_m and the plant during the entire onsite phase.

Maintenance was assessed by reviewing procedures, environmental equipment

_qualification files, vendor manuals, work orders, work practices, the trending program and maintenance corrective actions and by performing a physical walkdown to determine the material condition of the low-pressure

... coolant inject.ion_ (LPCI) _ systel!I. _Maintenance of safety system MOVs was specifically evaluat~d.

Inservice testing (IST) was assessed by reviewing procedures, observing surveillance t~sts, and reviewing related IST documentation.

The IST program for safety system MOVs was specifically addressed. -

. Training was assessed by reviewing proce.dures, the Instructors Manual, simulator scenarios, retraining tests, license examinations, licensed operator training records, and training inquiry feedback files.

Simulator upgrade and retraining sessions were monitored, as well as a simulator upgrade evaluation and classroom retraining sessions mandated by the NRC.

A walkdown of the control board was performed with licensed operators.

Observations included control room activities, three days of mandatory training, and one day of requalification training.

Quality assurance and quality control activities were assessed by reviewing the recen~ changes in plant QC coverage; the stati-0n improvement initiatives (including.the degree of.QA staff involvement in these efforts); the QA audit and'surveillanc~ efforts, and the overall corrective action and*root cause analysis programs, by examination of QA/QC documents, and by observation of QA/QC activities during plant operations.

Radiation control and chemistry activities were assessed by reviewing departm-ental organ*ization and staffing, respiratory protection, industrial hygiene, radiation-chemistry (RC) training, control of high-radiation areas, evaluation of operating experience reports, the chemistry program and the 11 as low as reasonab 1 e achi evab 1 e" (ALARA) program.

Throughout the onsite evaluation, the Team Manager and other team members met daily with the Station Manager and selected staff to discuss team activities.

The team also held daily meetings to discuss and evaluate observations and findings.

The Dresden Senior Resident Inspector (SRI) and Resident Inspector (RI) attended these meetings.

The SRI functioned as a technical advisor to the team during the onsite evaluation.

The team left the site on August 28, 1987 and continued its evaluation activities in Headquarters.

The Director of AEOD, Team Manager, and Team Leader conducted an exit meeting at the Commonwealth Edison Company (CECo) corporate offices on September 23, 1987 (see Section 4 for details).

The NRC Region III Administrator, other Region III managers, and the NRR Project Manager also attended this meeting.

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. 1.4 Plant Description The Dresden Nuclear Power Station (Units 2 and 3) is located in Goose Lake Township, Grundy County, near Morris, Illinois. Construction of Units 2 and 3 was authorized by the NRC by issuance of a construction permit for Units 2 on January 10, 1966 (NRC Docket 50-237) and a construction permit for Unit 3 on October 14, 1966 (NRC Docket 50-249).

Units 2 and 3 were completed and went into commercial service in June 1970 and November 1971, respectively, CECo is-the sole owner.

Units 2 and 3 are essentially identical.

Each unit consists of a General Electric (GE)-designed boiling water reactor (BWR) licensed for operation up to a thermal output of 2527 MWt, equivalent to a net electrical output of 809 tffle.

The primary containment system of each unit is a BWR Mark I design and consists of a dry well, a pressure suppression chamber (wet well), and a connecting vent system between the dry well and the suppression chamber water pool.

Unit 1, which was an earlier BWR design; has been shut down for several years and no longer has an operating license.

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2.0 2.1 EVALUATION RESULTS Major Findings and Conclusions Based upon the background and experience of the team members, the review of extensive documentation, results of over 84 interviews, the direct observation and review of work activities, the team concluded that Dresden's performa~ce

... was on,the low side of.average with a slowly_ improving trend.

However, there was not high confidence that, without additional and major CECo involvement, Dresden's performance would show significant and sustained improvements.

This view was due to Dresden's fluctuating past performance history, the weaknesses in the present improvement initiatives, a lack of improvement initiatives in several critical areas, and limited financial and human resources.

The team found major weaknesses-in maintenance, inservice testing, communication, and operator training.

Although the team identified a number ~f problems and concerns, there were also encouraging signs and evidence of improvement.

For example, for the most part, the attitudes of management and staff were positive and refl~cted a genuine commitment to safety.

There were a number of new or strengthened initiatives which were either beginning to show improvements or showed the potential for improvements.

Foremost in potential were the extensive number of managerial and organizational changes.

Additionally, such initiatives as the reduction in contaminated areas, reduction in personnel contamination, an~ reductibn in personnel errors showed measurable improvement.

Because of a history of poor"ni*aintenance and testing practices, the team concluded that wear, aging, and the resultant accumulation of equipment deficiencies could cause system/component unreliability.

Further, the. team found that communication was poor across the organization; and that the operator requalificatfon.program remained unsatisfactory.

In summary, the corporate objective of achieving an overall SALP rating at Dresden of 1.5 by 1990* would* require a substantial commitment to additional improvement initiatives by the Commonwealth Edison Company.

2.2 Specific Findings and Conclusions In order to properly evaluate the performance of Dresden, particularly with regard to the attitude toward safety, the degree of management involvement, and the effect of recent management initiatives, a number of specific areas were examined in detail.

The results of this examination provided the principal inputs into the major findings and conclusions discussed in Section 2.1 and the fundamental or root cause determinations discussed in Section 2.3.

The specific areas examined were:

operations, maintenance, surveillance testing, operator training, quality programs, radiological controls and management overview.

The findings and conclusions for each area are summarized below.

Additional details involving each concern are found in the appropriate section as indicated.

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2.2.1 Operations

1.

Although the operating staff seemed generally proficient in the use of procedures, a nonlicensed equipment operator (EO) draining water from a

_ CRD system accumulator did not perform this operation in accordance with the procedure.

Inadequate training was believed to be the reason for the operator 1 s failure to follow procedures (Section 3.1.1).

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• The".control room-had un'controlled pipir\\g and instrumentation diagrams (P&ID) and electrical schematics which were used routinely by plant operations personnel.

This was contrary to station procedures and provided a potential for maintenance or operation errors (Section 3.1.1).

3.

The poor physical appearance of the control room represented a poor working environment.

Further, efforts to remodel.the control room did not receive management _priority, and funding had been depleted prior to completion.

Additional management support and attention were needed in this area (Section 3.1.2).

4.

5.

The use of formal overtime by nuclear station operators (NSOs).was routine, and in a number of cases exceeded station limit~.

In at least one case, overtime was clearly excessive to the point of raising an immediate safety concern (a Unit 2 NSO had worked six double shifts in a 7-day period).

NSO staffing seemed deficient and this aspect contributed to a negative operator attitude.

Responsible management was* not aware of the overtime situation.

This matter was communicated to CECo management when identified during the evaluation and was promptly corrected by the licensee (Section 3.1.3).

While the operating staff generally showed a good understanding of the technical specifications (TS), two incorrect interpretations of the TS were noted during the short team visit.

The first involved an LCO for the reactor protection system (RPS) intermediate range monitor/average-power range monitor downscale trip function.

The second involved surveillance testing and operability requirements for the HPCI system.

The first item was apparently inadequately addressed in operator training, and the second item involved an apparent, longstanding TS deficiency (Section 3.1.4).

6. -

Several senior reactor operators (SROs) noted that requalification training was only marginally effective, consisting of only two weeks of self study, and more performance based training on the Dresden simulator was needed.

Further, there was a widespread feeling that there was no effective mechanism for NSOs to comment on the trainin~ they received.

Previous comments had achieved little or no results, which seemed to reflect poor communication and/or cooperation between the Operations and Training Departments (Section 3.1.6).

7.

Shift Engineers (SEs) and Shift Control Room Engineers (SCREs} were knowledgeable about operations activities, demonstrated the proper safety perspective and had adequate command and control of plant operations.

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.';j However, SEs were not routinely informed about the schedule for main-tenance activities that would occur on shift. As a result, SEs did not feel that they were in charge of the plant.

Overall, communications between operators and management appeared weak (Section 3.1.7).

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9.

The NSOs believed that lack of a preventive maintenance program contributed significantly to a lack of trust in the reliability of plant equipment.

For example, recent modifications to the feedwater control

_system (FWCS). had resulted in numerous oscillations within the system (and subsequent reactor scrams).

The NSOs did not trust the FWCS, did not feel there was proper training on it, and did not want to be responsible for its performance (Section 3.1.8).

10.

The results of extensive interviews with principal first~line supervisors and non-supervisory personnel involved with plant operations were:

(a) station management seemed reluctant t6 take firm action with regard to composition of shift personnel.and distribution of overtime hours among shift workers, (b) there was considerable activity before the Institute of Nuclear Power Operations (INPO) and NRC evaluations, but few long-lasting changes; and (c) interviews with operators indicated that while morale had recently improved, it was still generally low, caused in p*art, by an unsatisfactory requalification program, extensive overtime, a perceived l~ck of support from the Training and Technical Support Department and a despairing attitude toward discipline.

Although the operators were pleased with their job security.and were loyal to CECo, they were deeply concerned about the lack of promotion opportunity.

Another con*cern was the lack of response or.feedback from management to inquiries and questions regarding training and plant procedures (Section 3~1.9).

2.2.2 Matntenance

1.

Safety-related equipment has routinely failed because of wear and age, yet, even after these failures, a systematic and comprehensive preventive maintenance program was not instituted.

In particular~ pteventive maintenance of motor-op*erated valves (MOVs) was poor.

The team observed.

that 85 safety-related MOVs have never been periodically inspected or routinely relubricated during their installed life of up to 17 years.

Seventeen drywell MOVs were lubricated with a grease that was apparently unqualified.

The use of this grease has contributed to two instances of LPCI system pump suction MOV failure.

Safety-related MOV torque switch settings were not based on expected design differential pressures, and the setting of MOV limit switches was often inconsistent with the procedural guidance (Section 3.2.1.1 and 3.2.1.2).

2.

The performance of corrective maintenance on failed equipment was generally adequate, however, the licensee's ability to determine root causes of failure and implement corrective action in the failed equipment and similar equipment was weak.

For example, to prevent "hydraulic lock" of MOV spring packs, the licensee took corrective action to modify MOVs that were susceptible to this phenomenon.

However, the corrective actions were not completed as intended and, in fact, resulted in a HPCI system MOV 14

being repair~d such that it was now susceptible to this phenomenon (Section 3.2.1.3).

3.

Licensee maintenance procedures were weak.

Corrective maintenance procedures did not exist for many safety-related and balance of plant (BOP) system equipment components.

Examples included HPCI room coolers, HPCI pumps, feedwater regulating valves, torus vacuum beakers, and condensate pumps.

Further, other safety-related maintenci.nce procedures

-~ere found to be incomplete (Se~tio~ 3.2.1.4)~

4.

Although work request history has been trended for over a year, the team could find no objective evidence that actions resulting from the trending of failed equipment has improved station maintenance activities.

Equipment failures had been trended only by specific component and not by type and no lubrication and oil analysis trending has been performed.

The new trending procedure has not corrected any of the weaknesses identified by NRC Region III personnel in May 1987 (Section 3.2.2).

5.

Interviews with maintenance supervisors and workers identified several concerns including poor communication between management and non-supervisory staff, incomplete work planning, the perception of disciplinary action

6.

under the rework program, and an increased workload brought on by INPO and NRC inspection findings.

These individuals believed the cleanup program and changes in supervision had improved morale.

The attitude of maintenance workers and supervision appeared to be professional and positive~ and there seemed to be no excessive friction with plant operators (Section 3.2.5).

Because of the maintenance weaknesses identified during the evaluation, the team concluded that staffing may not be sufficient to adequately perform all of the department functions.

Unlike the maintenance organization of many other nuclear stations, Dresden had few maintenance engineers to perform such functions as fire protection coordination, -*

equipment qualification coordination, preventive maintenance coordination, procedures writing and revising, spare parts analysis, equipment/system trending, disposition of maintenance-related deviation reports, and vendor and station technical services interface (Section 3.2.6).

2.2.3 Testing

1.

2.

The second 10-year IST program was submitted by the licensee to the NRC for approval in 1981.

It has not yet been approved (Section 3.3).

Surveillance testing, required by ASME code, has not been properly performed, and there are no administrative procedures to control ASME Section XI testing to assure that all required tests have been performed, evaluated, and trended.

Valves listed in the IST program, but not tested were identified in the following systems:

CRD, RWCU, core spray, LPCI, and HPCI.

Further, two 10-inch HPCI injection isolation valves have been stroke tested in the wrong direction (Section 3.3.1).

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3.

A number of inconsistenc.ies and deficiencies were noted in the IST program compared with the Technical Specifications and ASME Section XI.

These items included an absence or differing stroke times, different "normal" positions, different designations, and lack of evaluation criteria.

Additionally, numerous examples were identified where:

(1) safety system modifications were made without the required changes to the IST program, and (b) the IST program description and the surveillance test procedures were not consistent regarding critical valve parameters (Section 3.3.1).

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Six requests made by the licensee to the ASME for Section XI relief were found to have incorrect valve des1gnation, and an additional request incorrectly noted that manual actuation of specific MOVs was not possible when, in fact, it was possible (Section 3.3.1).

5.

On a number of occasions, p~mp test res~lts were outside the established

• acceptance criteria specified in the test procedures (for ex~mple, problems were found on June 1, June 2, and June 30, 1987 wit~ the LPCI pumps during operability testing and in May, June, and July 1987 with DG cooling wat1!1' pump operability "'testing). However, deviation reports were not written to document the problems nor were documentations of corrective maintenance or modification being performed (Section 3~3.2).

6.

Inservice testing of the HPCI ~ump has not been ~ccomplished at a standard reference value as required by Section XI.

The test procedure requires only a minimum reactor pressure rather than a specific range.

Also in one case, the HPCI test was accomplished at a reactor test pressure below that required by the test procedure (Section 3.3.2).

7.

Interviews with the IST group showed they were committed to effective test programs.

However,.they commented that, at best, minimal improvements could be expected in the near future because of the long years of poor work practices and the negative momentum that was created (Section 3.3.4).

2.2.4 Opetator Training

1.

The team fo~nd an overall lack of plant experience and sufficient staffing in the training department to support an effective overall training program for licensed and nonlicensed operators.

Because of insufficient staffing, both licensed and nonlicensed operators were in the same retraining class and receiving instruction on both a licensed and nonlicensed operator level.

As a result, most of the time one or the other groups was presented material that was not at the appropriate level of difficulty and; thus, a proper learning environment was not established (Section 3.4.1).

2.

The team observed that classroom instructional practices were poor; learning objectives were not communicated to the students as to the expected level of p~rformance; and test questions were too easy and poorly written.

Little emphasis was placed on providing indepth job-required knowledge of systems functions.

Licensed operators appeared attentive, but nonlicensed shift personnel appeared inattentive.

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interaction was not encouraged and instructional*aids were not well integrated into the classroom instruction (Section 3.4.2).

3.

Requalification training focused on specific questions from past Dresden requalification examinations and from the January 1987 NRC requalification examination.

Questions by the students concerning other material were treated as irrelevant.

A comprehensive requalification program appeared

. not to be a goal.

Rather, training s~emed designed to. aid the student to recall specific information on anticipated test questions.

The requalification training program was considered to still. be unsatisfactory and the lack of emphasis on an indepth job-required knowledge of systems, functions and interactions was considered a major weakness in the training program (Section 3.4.2).

4.

Simulator training at the GE Training Center at Morris was adequate.

The instructor, a GE employee; provided good feedback to the trainees with respect to their performance during simulated emergency scenarios.

A 4-day simulator upgrade course adequately emphasized team building, proper communication, use of procedures, board manipulations, and emergency operating procedures.

However the GE simulator had a number of significant differences from Dresden (such as the new rod worth minimizer system, computer digital displays, the modified Standby Liquid Control System (SLCS) controls, and the new digital feedwater controls) (Section

3. 4. 3).

2.2.5 Quality Programs 1..

The QA Department seemed to suffer from high turnover (half the staff had been working. in the Dresden QA Department less than two Years) and understaffing (of 12 personnel, only 6 were available for regularly scheduled QA activities) (Section 3.5.l);

2.

3.

There was no active or direct participation by the QA Department in the development of station improvement initiatives, and the extent of participation in their implementation was limited to routine audit and surveillance activities which had not been defined or scheduled.

QA personnel had little specific knowledge of the nature and direction of the initiatives, but they had observed signs of improvement in plant appearance and performance (Section 3.5.2).

Station improvement initiatives seemed to be fragmented; corrective actions and follow-up were not centrally tracked; and for the most part the initiatives were not directed at improving the functional capabilities of safety systems and most seemed to respond to the results of inspections or evaluations. by NRC or INPO.

Not all of these initiatives were formally established and promulgated and as a result, many plant personnel were not aware of these efforts.

Further, these improvement initiatives did not appear to represent a major commitment of CECo resources (Section 3.5.2).

4.

The licensee's Safety System Functional Inspection (SSFI) on the Unit 3 emergency diesel generator was an excellent initiative which identified 17

• ,... *~ :

.. f.

~.

5.

,a_ -

several serious deficiencies.

This initiative, however, was new and the.

effectiveness of any corrective actions could not be evaluated.

If this initiative were extended to o*ther safety systems and resultant corrective actions were effective, it coultj help to assure their functional capabilities (Section 3.. 5.3).

Licensee QA audits did not find the significant problems the team

• ,,1:.

~-.

. *. -..... identified in the maintenanc~ and inservice testing areas ~ecause of tbe program oriented nature of their audits.

The electrical maintenance instrument calibration records were found to be in disarray and essentially

7.

8.

• not auditable.

The Dresden QA auditor found a similar situation during his audit in February 1987, but did not consider the problem serious enough to make it an audit finding or observation.

Because of the state.of these records, it was not possible to determine if uncalibrated test equipment had been used for safety-related maintenance or surveillance activities (Section 3.5.5).

The Regulatory Assurance Department was charged with tracking internal and

• external commitments and corrective actions.

The tracking system seemed satisfactory with respect to external commitments, but there were a wide spectrum of internal actions.th~t were not identified or tracked.

For exam~le, the status and action required by di~crepancy records and deviation reports were not identified and tracked (Section 3.5.7).

the licensee had no viable, plant-wide root-cause determination and.

analysis program.

For example~ the personnel error reduction initiative was based upon the root cause det~rmination from deficiency reports.

A review of 12 cas~s indicated.that in 7 cases the identified root cause, i.e., of personnel error, was inaccurate.

Although personnel error was involved in these cas~s. the fundamental reason for the. error was not i dent ifi ed.

Notwithstanding, the team found the nu*mber o*f events involving personnel error had been significantly reduced over the last several months (Section 3.5.7).

Interview~ with the QA.and QC groups indicated an ov~rall positive attitude toward their jobs and plant safety.

Howev~r-, the theme of poor communication and poor response from management was evident (Section 3.5).

2.2.6 Radiation Chemistry

1.

Interviews with the radiation and chemistry groups indicated an overall positive attitude toward their jobs and plant safety; corporate support personnel ~ere c~operative and knowledgeable of plant needs; and the level of technician knowledge appeared adequate.

However, the theme of poor communication and response from management was evident (Section 3.6.1).

2.

Administrative duties such as telephone answering and equipment issuance, occupied a large portion of the RC foreman's time and attention, and made him desk-bound (at least on backshift).

Changes were underway to enable RC foremen to spend more time in planning job coverage, providing in-field support, and directing job coverage (Section 3.6.1).

• I J

,'.'-.~...

3.

Individual performance evaluations, recently initiated, were.a good first step in providing a two-way communication/feedback mechanism:

Other management initiatives included the proposed 113 tier" technician progressfon ladder and the split of radiation and chemistry at the technician level.

Both of these initiatives offered additional potential improvements (Section 3.6.1).

.. 4, The. Respiratory Supervisor, although.re.latively inexperienced, had initiated several recent improvements including discontinuing the use of half-face negative pressure respirators and bringing in powered-air-purifying respirators (which provide a high degree of protection).

The acceptance criteriori (fit factor of 50) for an acceptable respirator fit testing was considered too low (Section 3.6.2).

5.

Flexibility appeared needed in the plant requirement for mandatory respiratory protectio2 in work areas having contamination levels greater than 50,000 dpm/lOOcm. Strict adherence to this criterion for all work activities might have resulted in unnecessary wearing of respirators, resulting in less efficient and effective work practices and probable

6.

.increased overall occupationa*l risks (Section 3.6.2).

There was no formal mechanism to track and ensure that recommendations/

corrective actions resulting from investigation or audit findings in the industrial hygiene area were effectively implemented.

For example, the plant safety committee made several hardware and administrative recommendations as a result of a 1984 event where a worker 16st consciousness due to an inadverteht release ~f C07 from the Unit 1 Cardox Tank.

The recommended hardware fixes had not been accomplished.

The governing procedure was modified, but it still contained no worker guidance, hazard warnings of precautions to be taken during specified operations (Section 3.6.3).

7.

A procedure dealing with feedwater-sparger maintenance had been deleted because there were no plans for work in this area.

However, deletion of this procedure also deleted pertinent radiol~gical controls governing work

• inside the reactor vessel, and lessons learned from a 1981 overexposure event.

Such *information should not have been lost; it needed to be continually maintained and available to station personnel (Section 3.6.5).

8.

The plant chemistry program was considered an industry leader.

The ALARA program, however, needed to be implemented station-wide and considered in the planning and practice of every craft project (Section 3.6.7).

2.2.7 Management Overview

1.

The CECo Strategic Plan included an objective that limited additional investment costs to funding of projects mandated by regulation or projects with overall payback periods of less than or equal to corporate guidelines.

It was indicated that investments to meet goals of 19

-~

• -e.**

11excellence 11 were not excluded. and 11might 11 be -approved, but there was no strong commitment to assure the necessary funding to achieve and maintain such a standard (Section 3.7.1).

2.

The overall level of resources available at Dresden (i.e., funding and management and technical staff) was a concern.

The staff levels during the evaluation did not appear adequate to correct past problems, achieve improvements in a number of areas; and sustain.a rate of change in

'performance that would: result in *an average SALP rating of 1. 5 by 1990 (this was a corporate and station goal).

Recent management changes had been made toward.this end, but resources in funding and staff did not appear commensurate (Section 3.7.1).

3.

A number of improvement initiatives had been defined and implemented by CECo.. In many cases, these initiatives were undertaken as a result of findings by the.NRC and INPO, rather than as a result of licensee self-assessm~nt efforts.

Further, not all of these initiatives were*

included in a for~al tracking system to assure timely completion.

Additionally the purpose, nature, and administration of most of these initiatives had not been adequately communicated to non-supervisory personnel.

Although communication was weak across all the functional areas, there were several management initiatives to improve communication, such as:

quarterly awareness/expectation sessions; weekly departmental 11tailgate 11 sessions; walkthroughs before complex operational events; briefing by Assi.s.tant Superintendent Operations during operator training; and a daily station one-page flyer.

Many personnel were skeptical about the lasting effects of these** improvement initiatives (including communications) and the extent of *management's commitment to them (Section 3.7.2).

4.

The effectiveness and completeness of *improvement initiatives had been mixed.

Some initiatives such as plant decontamination had been a clear success (a reduction of 65 1 000 square feet of contamination to 9,000 square feet.was achieved in the year previous to the evaluation).

The painting program appeared successful and had resulted in a cleaner and safer working environment.

The success of some initiatives, such as trending efforts, upgraded modification program, maintenance assessment, safety system functional inspections, and a large number of management changes were not yet to the point where a judgment on effectiveness could be made.

Strengthened or new improvement initiatives were needed to overcome problems in maintenance, in-service testing, operator training, and communications (Section 3.7.2).

5.

The results of interviews with station management indicated:

(a) managers were acutely aware of the deficiencies at Dresden and of the need for rapid, directed improvement; (b) a good start had been made in implementing the necessary improvements; (c) little had been done to improve the attitude at Dresden or to establish new programs because of the demands on resources associated with new post-TMI-2 regulatory requirements; (d) insufficient emphasis had been placed on writing and revising procedures, maintaining safety-related systems, and providing complete and accurate documentation for plant modifications; and 20

(e) changes in the industry were not routinely brought to the attention of plant personnel (Section 3.7.3.2).

6.

Dresden managers believed that the plant was being operated safely, but admitted to difficulties in certain areas caused by a lack of financial and human resources and the constraints of the union agreement.

The managers were knowledgeable about corporate and plant goals, particularly to reach a SALP rating of 1.5 by 1990 {Section 3.7.3.2).

7.

Many personnel commented that communications at the plant were improving.

Tailgate meetings were a help, although they did not provide the 11 right 11 environment for eliciting meaningful comments from workers.

It was also noted that no formal performance appraisal system existed at Dresden before May 1987, and this system, with the exception of radchem technicians, does not apply to bargaining unit personnel (Section 3.7.3.~).

2.3 Fundamental or Root Cause(s) Determination Based upon the team assessment the fundamental or root causes of Dresden's poor performance history were attributed to:

1.

A number of ihdi cations that Dresden had not received strong and i ndepth corporate attention in the past.

This was probably due to the natural priority within CECo to tasks associated with getting new plants on-li-ne and operating routinely.

There were indications that past initiatives were not a major focus of senior management attention and action, and were not supported by a high priority commitment of corporate resources.

Further, there were indications that limited resources had resulted in excessive routine use of operator overtime, training limitations and a

. skeptical attitude by some personnel of whether management was really serious about i~provement programs.

2.

An attit~de and approa~h that had not been directed at achieving or :.

maintaining a high standard of safety performance.

Such a level of*

performance was not demanded, not funded, and not established.as a way of life.

Instead an old "fossil plant"- climate flourished where the minimum was good enough; if it is not required, don't do it; and fix it only when it's broken.

Further, the many years of operating experience had given the Dresden personnel a sense that they knew the nuclear power business.

This aspect coupled with a lack of recruitment of senior knowledgeable managers and engineers from outside of CECo tended to impede the routine transfer of industry experience and good practices to Dresden.

As a result, over time in the 1970's, the station seemed to have developed an operating attitude and level of performance that were not commensurate with expected levels of nuclear plant operations in the late 1980's.

3.

Past improvement initiatives had been largely a reaction to findings by INPO and the NRC, and thus had not been developed in a specific and complete way to overcome Dresden deficiencies.

In other words, such initiatives were directed at showing responsiveness and a willingness to correct identified problems but were not directed at achieving fundamental improvements in station performance.

21

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'.. ~*:.* \\

The above causes resulted in a number of major weaknesses as described below..

These weaknesses were considered significant contr1buting causes for Dresden's poor perform~nce.

1.

Maintenance and inservice testing of plant equipment had long been neglected.

There had been no effecti~e preventive maintenance programs; corrective maintenance had been delayed, sometimes based on incomplete ro~t ~ause analysis, and usually limited to the specifi~ item that failed; and the inservice testing program had numercius defici~ncies.

As a

2.

result, there was a lack of trust by the plant operators in the reliability of plant equipment and a general attitude that maintenance at Dresden had historically been poor.

This situation was evidenced by the fact that:

(a) maintenance and test procedures were frequently found to be incomplete, missing, or incorrect; (b) trending of equipment failures

. by type or model and lubrication analysis were not performed; (c) some motor-operated valves had neverbeen inspected or relubricated since iristallation more than 17 years ago; and (d) torque switch settings on safety-related motor operated valves were not based upon a documented analysis or comprehensive test program.

Thus, the basis for confidence in the reliability of safety and nonsafety equipment under credible off-normal conditions was brought into question.

Communications between management and staff seemed to be poor.

Staff personnel did not appea~ united or even particularly knowledgeable about efforts to overcome known problems.

There was a widespread concern about a lack of feedback and response from management about inquiries and questions on matters of importance to the worker.

Supervisors for operations were not informed about what was going to happen on their shifts, and the entire QA Department seemed not to be directly involved in or knowledgeable about performance improvement p~ograms. The lack of good communications and feedback among station personnel seemed to have a negative impact on:

staff morale; worker effectiveness; and the degree of staff commitment and respect for achieving improvement.

3.*

Training programs had not provided the desired level of knowledge and skill.

There had been inadequate staffing to provide for a full week of training to nonlicensed operators, resulting in classes being conducted with both licensed and nonlicensed operators in the same class.

Some instructors lacked plant experience which caused a lack of respect by operators.

The requalification instruction seemed focused on previous and potential requalification test questions r~ther than providing an indepth knowledge of systems functions or characteristics.

As a result, operators complained about inadequate training on plant modifications (e.g.,

modified feedwater controllers); there were indications of frustration with qualification and requalification training; and there was a need for additional training on following procedures and the proper interpretation of the plant Technical Specifi~ations.

22

3.0 DETAILED EVALUATION RESULTS 3.1 Operations 3.1.1 Operators' Adherence to and Control of Procedures Dresden Administrative Procedure (OAP) 23, "Operation and Control of the Satel-1 it~ Files, 11 Revision 3, required that only-contrblled drawings be used for operational and maintenance activities.

The controlled set of drawings was kept on the Unit 1 side of the control room in the Shift Control Room Engineer's (SCRE's) file.

However, the control room had several sets of uncontrolled piping and instrumentation diagrams (P&IDs) and electrical schematics that were being used for certain operational and maintenance activities.

The team observed several instances were the control room operating staff used uncontrolled P&IDs and electrical schematics in the control room and in the Shift Engineer's office. The team questioned several licensed reactor*

operators and senior reactor operators regarding the use of uncontrolled drawings.

The operators agreed that the critical (controlled) drawings should be used; however, they admitted that the uncontrolled drawings were used routinely for infor~ation.

During the sustained control room observation, the team found that shift turnover procedures were implemented efficiently with minimal disruption to plant operation.

The nuclear station operators (NSOs) responded to alarm conditions according to procedures ~nd appeared to be attentive to the control room panels.

During this observation period, a reactor scram occurred and the operating shift responded satisfactorily.

The team observed several operator activities and found one. instance of an..

operator not following established procedures.

The evaluator accompanied a.

nonlicensed equipment operator (EO) during his dayshift round of the Unit 2 reactor and turbine buildings.

The EO was directed to clear the accumulator high-level alarm on control rod hydraulic control unit (HCU) 06-31.

The EO

• went to the HCU, determined that the alarm was caused by high water level and proceeded to drain the water.

The evaluator watched the EO close charging*

valve 113.

This action was not in accordance with Dresden Operating Procedure (DOP) 300-11, Revision l, "CRD System Accumulator Water Removal Procedure."

The operator did reopen.the valve when the draining was complete.

When the evaluator questioned the EO about the apparent noncompliance with DOP 300-11,

• the EO said that he felt this was a routine evolution and that he had not reviewed the. procedure before the evolution.

Although the evaluator agreed that this was a routine evolution, the EO had not followed procedure.

The EO said that his "on-the-job training tau~ht him this method of HCU draining and that closing valve 113 was an added precaution.

The team found no e.vidence of specific problems associated with the use of the uncontrolled drawings.

However, the team believed the.potential existed for maintenance or operating errors if the uncontrolled drawings were used for critical activities.

The team believed that the control room operating staff 23

~

(",*

~-.. ;.

e*

. *~** ~.

was generally proficient in the use of procedures and control room drawings.

The control room activities that.the team observed were satisfactory, except for the instance described above which was ascribed to inadequate training.

3.1.2 Control Room Environment The team observed that the control room lighting was low and.the noise level

• .. was high.

The control room board -mimics were. designed with little.attention to human factors engineering.

Numerous caution tags and uncontrolled and sloppy operator aid diagrams contributed to the overall poor appearance of the control room board from a human factors engineering standpoint.

Painting of the control room boards also was in progress.

The licensee had a remodeling effort under way to address these concerns and had instituted a control room Professionalism Committee to review this area.

A

• discussion with ~ Shift Enginee~ (SE) indicated that the remodeling effort had been hin.dered by negotiations to determine which craft p*ersonnel would perform the work.

By the time this was resolved, funds.had been depleted ~nd activity was limited to painting arourd the annunciator reset buttons.

• The team believed that:

the poor physical appearance of the control room represented a poor working environment; the remodeling efforts had been slow; and additional management support and attention were required.

3.1.-3 Management Control of Overtime The team revie.wed overtime -records dating from No.vember 1986 through July 1987, observed work activities of operators, and held individual interviews with operators during the evaluation.

OAP 7.1 governed the control of overtime.

This procedure followed the NRC Commission. guidelines contained in a policy statement issued on February 11, 1982, regarding the working hours for nuclear power plant staff.

The team found numerous instances, during.periods of dual unit outages and/or plant startup and special testing, where the operators' working hours approached and occasionally exceeded the OAP 7.1 limits. During the week of August 17, 1987, three NSOs had worked hours in excess of Dresden and NRC guidelines without documentation to justify the reasons and to indicate corrective actions to be taken.

This represented a deviation from OAP 7.1.

The team found, through their interviews with operators, that numerous instances of forced overtime had occurred since November 1986.

The team also discovered instances of NSO overtime during the Unit 3 uncontrolled heatup from cold shutdown conditions on February 27, 1987, and the Unit 2 event during the containment purging process on November 28-29, 1986.

The limi.ts of OAP 7.1 were apparently not exceeded during these latter two events.

During the week of August 24, 1987, the team observed that a Unit 2 NSO, who was responsible for unit startup, had worked six double shifts (each shift is 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) in a 7-day period. This represented a deviation from the OAP 7.1 limit, which specified that licensed individuals shall not work more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in 24

• • • ~..

.)

• • • • e e***

any 48-hour period.

The Assistant Operations Superintendent had not been aware of this situation and, when notified, immediately corrected the situation by removing the individual from shift.

The team held meetings with facility management personnel when this issue surfaced.

As a result, immediate corrective actions were taken, including the addition of a requirement for prior management approval for any extension of overtime beyond the limits of OAP 7.1.

Management personnel indicated that long-term corrective actions

~ould incJude a revision to.OAP 7.1, along with plans for negotiations with union officials regarding staff composition and working hours.

The team noted that th~ Assistant Superintendent of Operations did not have a staff to assist him in matters such as the control of operator overtime or other.day-to-day activities.

The team also found that the typical shift rotation at Dresden was backwards in terms of circadian (biological) rhythm.

The August 3 to September 13, 1987 schedule that was given to the team indicated that the crews rotated as follows:

7 afternoon shifts, 2 days off, 6 day shifts, 2 days off, 7 night shifts, 2 days off. Research reported i.n NUREG/CR-4248, 11Reco11111endations fo!'

NRC Policy on Shift Scheduling and Overtime at Nuclear Power Plants," has demonstrated a better rotation pattern would be from days to afternoons to nights, with sufficient time between nights and days to "reset the biological cl ock 11 (i.e., about 4 days).

Moreover, this research recommended that th~

• length of time in a given shift be either 2 days or a month.

This same research indicated that the least productive shift rotation occurs with a pattern similar to that found at Dresden because an individual barely has time to adjust to the.shift before being rotated to the next shift. With a weekly rotation, a person is always 11out of synchrony" with their work schedule.

The Operations Department seemed to be adequately staffed at the senior reactor

• operator level, but inadequately staffed at the NSO level.

Consequently, NSOs were routinely required to work excessive overtime during periods when Units 2 and 3 were not at steady state operation. *This was particularly true on t~e day shift following their normally scheduled 2300-0700 shift.

During inter-views, at least four NSOs had reported that they had called in sick because they were too tired to work.

Further, this practice was not being controlled in accordance with OAP 7.1.

Overall, there did not seem to be a shortage of licensed reactor operators.

In fact, niany licensed operators were assigned as 11811 operators to work on balance-of-plant equipment.

However, establishing more NSO positions would have helped to alleviate the overtime problem.

The team believed that this issue was a negative contributor to the operators' attitudes and inhibited

• licensee management's ability to positively influence the quality of operational activities; Operations management personnel had not adequately controlled the overtime* being worked at the operator level.

Additionally, management of day-to-day operating activities could have probably been improved by providing a support staff to the Assistant Superintendent of Operations.

3.1.4 Compliance With Technical Specifications The team observed that the control room operating staff had adequate knowledge of the Technical Specifications (TS) for Dresden Units 2 and 3.

However, 25

. '~. -

• • .9_.***

e**.

during the evaluation period, two examples of. improper interpretation of the p~ant Technical Specifications were found.

The first instance involved the TS limiting condition for operation (LCO) for the reactor protection system (RPS) intermediate range monitor (IRM)/

average-power range monitor (APRM) downscale trip function.

The second instance involved the surveillance testing and operability requirements for the high-pressure coolant injection (HPCI) system.

The team brought both items to the attention of facility *management.

The licensee attributed these situations to vague RPS requirements and erroneous HPCI requirements that could not be attained.

Acco~ding to the Assistant Superintendent of Operations, several changes were needed in the TS to clarify the requirements and conditions for system operability.

In the case of the HPCI testing issue, this situation was known by the licensee for a period of several years and had been a 11 owed to exist.

Both TS issues are discussed in detail below.

Coincident IR/APRM RPS Trip lluri ng a control room tour on August 18, i9'87 at about 0800 hours0.00926 days <br />0.222 hours <br />0.00132 weeks <br />3.044e-4 months <br />, with Unit 2 at 93 percent power and in. the run mode, team members identified the following

.conditions associated with the neutron monitoring system:

• APRM-4 bypassed with the manual bypass (joystick)

• IRM-16 bypassed with the joystick

• IRM-17 out of service because.of erratic response (caution tagged)

APRM-4. was bypassed at 0019 o*n August 18, 1987, as a result of a low-power range monitor (LPRM) that failed high.

This condition caused a half scram on the RPS channel 8.. The operators bypassed the APRM, declared it inoperable because.of erratic response, and logged the event in the Unit 2 degraded equipment log.

There was no apparent reason for IRM-16 to be* bypassed.with the joystick, and.the condition was not logged in the Unit 2 NSO log book.

At 0922, the operators placed IRM.,.16 back into service and bypassed IRM-17.. This was done after the evaluator.brought the condition to the attention of the operating shift. There was no apparent reason for IRM-16 to be bypassed other than suspected 11at wil1 11 bypassing of an IRM that occasionally spikes *high.

Such action is permitted by procedures; however, the condition should be logged in the NSO log book per OAP 7.5.

The evaluator reyiewed TS Table 3.1.1 and RPS electrical schematics 12E-2464 through -2467.

IRMs are companioned to APRMs in each RPS channel for the APRM downscale trips.

The IRM/APRM pairings listed below were established for RPS channel B.

The.

notations explain the condition of the neutron monitoring system as found by

• the evaluator.

26

~

. *1RM 15 16 (bypassed) 17 (out of service) 18 APRM 5

6 4 (bypassed) 4 (bypassed)

.. ~

.The APRM downscale trip is required to be operable when the.reactor is in the ruri mode.

This APRM downscale trip function is automatically bypassed when the companion IRM is operable and not high.

However, in th~ condition that existed, as described above, only the IRM-15/APRM-5 downscale trip f~nction was operable, because the other three pairings in RPS channel B.were bypassed.

TS 3.1.1 states that the minimum number of operable channels for this function is two. *Having only one operable APRM downscale trip function in RPS channel B is an apparent violation of TS 3.1.1.

• If the required minimum number of APRM downscale trip functions cannot be met, the TS requires either (1) insertion of all control rods within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or (2) reducing power to the IRM range and placing the mode switch to start up within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Neither of these actions was taken by the licensee.

The evaluator brought this condition to the attention of the licensed operators on shift and to the licensee* operating management.

The licensee agreed that the situation appeared to be a violation of TS 3.1.1.

The licensee stated that this TS requirement for APRM downscale trips was apparently inadequately addressed in training and that the control of the IRM.bypass switches when the reactor was in the run mode was not adequate.

The licensee initiated a devia-tion report (DVR) and will submit a licensee event report (LER) for this con-dition. *The above-mentioned training concern and control of. the IRM bypass.

switches was immediately made known to all operating personnel by the licensee.

HPCI Operability and Surveillance Testing During discussions with licensed control operators, the team determined that a problem existed with the testing of the HPCI system because the HPCI system is not tested at the minimum reactor pressure specified in surveillance requirements.

The team reviewed TS 4.5.C.l and determined that the HPCI system is required to deliver 5000 gpm at reactor pressures ranging from 1150 psig to 150 psig.

TS 3.5.C.l requires the-~PCI system to be operable when reactor pressure is greater than 90 psig.

In addition, the Dresden updated Final Safety Analysis Report (FSAR) Section 6.2.5 states that a low reactor pressure of 165 psia (or about 150 psig) is an HPCI controlling design parameter.

Operators stated that the HPCI system is not tested at 150 psig reactor pressure because the General El~ctric HPCI turbine cannot achieve rated flow at this low pressure.

The HPCI system is tested at about 350 psig during unit startup ~nd heatup.

The team reviewed Surveillance Test Procedures DOS 2300-1, -3, -7 and determined that the HPCI system was tested at about 300-350 psig reactor 27 d*.

',*l

pressure after each refueling outage.

A review of DOS 2300-3, Revision 13, performed on Unit 3 on March 14, 1987, indicated that the licensee did test the HPCI system at the rated flow of 5000 gpm and at a reactor pressure of 300 psig.

Discussions were held with licensee management regarding this apparent incon-sistency.

The licensee stated that testing of the HPCI system at 300-350 psig in liel,l_of 150 psig was a common practice and believed that it was acceptable.

Thi~ interpretation is riot consistent with TS; however, the ev~luato~ ~as not able to find any written and approved TS position or a safety evaluation for this condition.

The team understands that some plants have revised their TS to allow testing similar to that being conducted at Dresden.

Both of these TS issues have been referred to the Office of Nuclear Reactor R~gulation for resolution.

3.1.5 Operations-Maintenance Interface

'During a pl ant tour, it was noted 'that major eff arts were under w~y to paint and clean numerous areas of the turbine and reactor buildings.

This led the team.to inquire.about the operability of the standby gas treatment system (SGTS).

The Dresden Technical Specifications require that three specific.

surveillance tests be completed on the SGTS charcoal filters if any areas from which the system takes suction are painted.

• The team brought this matter to the attention bf the Shift Control Room Engineer (SCRE), the Shift Engineer (SE), and the Assistant Superintendent of Operations.

All three licensed individuals indicated that this item was tracked by the Technical Services Department and that they 11assumed 11 that the SGTS was operable.

The team found no documentation that could verify coordination between operations and

• maintenance personnel to.track painting activities and SGTS operating runs.

The fo 11 owing day, the Operating Engineer indicated that it was his responsibility to track the painting activities and SGTS surveillance activities.

However, the control of activities in this* area, appeared to be poor.

The team interviews with NSOs indicated that they were not kept informed of maintenance activities that were to occur on their shifts on a routine basis.

Additional operations-maintenance interface problems existed for equipment needing repairs.

Some examples are listed below:

(1) When emergency diesel generators (EDGs) were taken out of service for repairs, a 7-day TS LCO was entered.

However, maintenance personnel were not instructed to place a high priority in returning the EDG's back to operable status by initiating around the clock coverage to complete the repairs.

(2) Unit 2 IRM channels 11, 15, and 16 were constantly spiking high during both shutdown and power operations. Although the problem was suspected to be caused by faulty signal cables located under the vessel, management did not plan to replace these cables during the present outage.

When inter-viewed, operators indicated a reluctance to start up Unit 2 with this 28

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problem uncorrected.

This indiscriminate practice of bypassing spiking IRMs led to the apparent TS LCO violation previously discussed.

(3) In Units 2 and 3, the scram pilot valve air header (SPVAH) high-pressure alarm annunciated on a half scram signal. This alarm was a nuisance for the operators.

The apparent problem, which was under investigation, was caused by air leakage around the ASCO (American Switch Company) solenoid valve stems.

Vibrations around -the packing adjustment screws cause them, to loosen, allowing leakage.

Management had not scheduled any trouble-shooting activites with regard to this problem.

(4)

Interviews with NSOs indicated that some senior plant managemeni placed a higher priority on painting equipment than repairing it. Several 118 11 operators strongly suggested that various oil leaks be repaired b~fore equipment was painted, but they were told that painting was a higher priority item because of an upcoming Institute of Nuclear Power Operations (INPO) evaluation.

TS)

As mentioned in (2) above, spiking high lRMs was a constant nuisance.

On one occasion, the evaluator noted a half-scram condition was immediately reset and was thought to be another spiking high IRM.

The operating crew subsequently determined that the half-scraa was caused by maintenance activities on an instrument rack.

The operating crew was aware of the work going on, but it was unaware of the specific task being conducted (i.e., tapping out a broken drill bit) on a sensitive safety-related instrument rack.

Overall, the Operations and Maintenance Departments seemed to display poor communication and poor control of work between their groups.

A specific example was the communication between the control room staff and the main-tenance staff on activities affecting the operability status of safety-related equipment.

3.1.6 Operations-Training Interface An NRC confirmatory action letter had been issued to the licensee on February 27, 1987 as a result of the poor perfor11ance on the NRC-administered requalification examinations.

The letter stated that shift advisors would be placed on shift to supplement the licensed staff.

The Dresden requalification program allows licensed individuals who are assigned to the station but who have not performed licensed duties for 4 months or longer to fully assume licensed responsibilities after an evaluation by a review board.

The evaluator noted that on February 27, 1987, two individuals who had not stood an SRO watch in over 4 months had been placed on shift and assumed SRO responsibilities*

without additional training or parallel watch standing with a second SRO who had current on-shift experience.

During this watch, the Dresden reactor heatup event occurred.

This event was described in LER 87-003-0.

These events occurred before the issuance of revised 10 CFR 55, which requires 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of parallel watch standing for licensed individuals who have not been actively performing licensed duties.

29

.'._{

c

.r

• • ~-

f;**

This issue concerning the lack of training for individu~ls w1thout recent on-shift experience was discussed with the Operations Training Supervisor and the Assistant Operations Superintendent.

Both agreed that this represented a poor decision by management, but that these cases were allowed by the Dresden requalification program.

The training supervisor was aware of the new require-ments of 10 CFR 55.

During a followup discussion with the Operations Training Supervisor the ~eek of September 21, 1987, the evaluator determined that

., OAP 7 ~ 1. had been revised to comply with the requirements of -the recently issued 10 CFR 55 rule change.

The team interviews with NSOs indicated that no effective mechanisms were in place to allow NSOs to comment on the training that they receive.

Licensed operators who had participated in the 1987 NRC-administered requalification examinations indicated that a 2-week period of self-study was the only training and preparation allowed them. *Several NSOs indicated that the licensed operator training was not individualized and only marginally effective, and that more performance-based training on the Dresden simulator was needed.

All persons interviewed indicated that these changes had been addressed during

~l!tings ~'lm!n t>pera:t-TI:ms 1)el'sonnel and faci1ity management and during.

_classroom training, but little or no results had been achieved.

Control room observations and interviews conducted with Unit 3 NSOs also indicated that the operators had not been adequately trained on the modified feedwater level controllers.

Specifically, the operators had not been informed about the automatic swap between level controllers if* the RPV water level signal fails.

3.1.7 Operating Shift Control and Oversight A Shift Engineer (SEY noted that he had not been informed of the Unit 2 startup activities that were scheduled to begin on* his shift., and** had* not received any information concerning the scheduled maintenance activities.

The team interviews with several SEs indicated that they were frustrated about decisions concerning maintenance activities and operating schedules being made by management at planning meetings without SE input.

This practice, although a management prerogative, in combination with a lack of feedbackto the SEs on the decisions made had a negative impact on the overall quality of operation.

The team observed that operating shift oversight, including that by the on-shift SROs (i.e., SE and SCRE), the senior manager on shift (when stationed), and the shift overview superintendents (SOSs), appeared to be functioning adequately_ to ensure quality operations.

The team observed that the SE and the SCRE were knowledgeable about operations activities, demonstrated the proper*safety perspective, and had adequate command and control of plant operations.

The team was concerned about the SCRE function during an operational transient or plant emergency.

The SCRE assumes the shift technical adviser function when relieved by the SE as the SRO in the control room.

The SE may not be able to assume SRO duties quickly if there should be a problem in the plant because of his/her physical location (i.e.,

the SE may not always be in the control room) and because he/she may not be 30

aware of. the latest up-to-date plant status.

The team interviewed selected SEs.

and SCREs and discussed this is~ue with management and although this SE/SCRE relationship seemed.awkward, it appeared to be working satisfactorily.

'The licensee has instituted additional management oversight on shift as follows:

(1) In 1984, a Shift Overview Superintendent (SOS) position was created to provide oversight and management presence on the backshifts.

Although no formal SOS program or implementing procedure existed, the. licensee

• inairltained *the SOS on selected shifts to review safety issues and to monitor evolutions.

(2) Recently, a senior manager on shift was added during plant startups and shutdowns to provide oversight for the SE.

This senior manager on shift was in charge of all shift activities, with a special focu~ on compliance with procedures and licensed operator activities.

The team observed the SOS and senior manager on shift during the evaluati6~

period.

Overall, these positions appeared to have a positive effect on overall operations.

The team noted that the SEs were competent and knowledgeable of plant operations.. However, interviews with selected SEs indicated that the SEs did not feel that they were in charge of the plant, nor did they feel that they had a good career path because of the lack of a baccalaureate degree (required for positions above SE).

There did not appear to be any specific program to address these SE concerns.

3.1.8 Influence of Dresden Improvement Initiatives on Operations*

The NSOs believed that the scram reduction, error free operation, and personnel error reduction initiatives mean time off without pay for unavoidable mistakes that are caused primarily by eq~ipment malfunctions.

As a result of these perceptions, the team evaluated the records and documentation of the.

disciplinary action taken for calendar year 1987 under these initiatives. *The team evaluation does not support the NSOs 1 perception.

The NSOs ~lso believed that.the lack of a preventive maintenance program*~

contributes significantly to a lack of trust in the reliability of their*'*

equipment.

Further, recent modifications to the feedwater control system (FWCS), which included installation of digital level controllers, have resulted in numerous oscillations within the system and subsequent reactor scrams.

The NS-Os did not trust the FWCS, did not feel there was proper training on it, and did not want to be held responsible for its performance.

Operators indicated that there is still a problem with the maintenance-operations interface concerning safety-related equipment.

Generally, the operators believed

• that the improvement initiatives were instituted as a reactive effort to either NRC or INPO findings and did not address the root cause of the operational problems, i.e., poor maintenance of plant equipment.

The operators noted the positive effort of the personnel contamination reduction program in reducing personnel exposure.

However, several operators indicated that the extended radiation work permits (RWPs) should allow normal, routine manipulations and minor equipment repair.* They believed the current 31

.. ~

• • -r

~:***

• "T*'

policy forces the operators to leave the area covered by.the extended RWP and generate a new RWP for the additional work.

This process could cause excessive delays of up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and affects the efficiency of job performance.

This matter appears *to be only a communication problem between operators and their management, since this interpretation of RWPs was agreed to by radiation

• controls and operations management.

.. 3.1. 9 Interviews The team interviewed 27 operators; all were shift workers except one.

These interviews-revealed that the control room personnel had a positive attitude toward their assigned duties, but that there is low morale among the operators.

The low morale resulted from primarily the unsatisfactory requalification program results and was made worse by the pressure of extensive overtime and the perceived lack of adequate support from the Training and Technical Support Departments.

Operators expressed the following concerns:*

The effect of overtime on the safe operation of the plant was cited by the operators as a major problem.

(Several sought out team members to express their concerns.) Operators commented on excessive demands that often included being held over for the next shift; being called in early; working, as a inatter of course, two double shifts* in 2 days; and, in one case, working six double shifts (each shift is 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) in 7 days.

Many operators believed that they could not be promoted.

Although the operators were pleased with their job security and were loyal to CECo, they discussed in detail the lack of promotion opportunity.

At the.

management level, the lack of a 4-year degree was believed to be a con-tributing factor.

Generally, only shift control room engineers (who are engineers with degrees) are promoted.

The operators *noted.that the slow personnel turnover and the strict seniority rules hindered the promotion*

process.

Operators were discouraged by the lack of formal response from management to changes they initiated.

Because no response was routinely provided to the operations personnel after they had*submitted inquiries and change requests regarding training and plant procedures, operators believed that the inquiries were 11 lost 11 or had been disregarded.

The team considered the inadequate response in these areas to be a major cause of low morale.

Some operators believed that the control room improvements were being done primarily because of an INPO commitment and not to improve the work.

environment for operators.

In particular, operators noted that the plans for control room improvement had been "on the drawing board 11 for.4 to 5 years, but were being continually delayed until the most recent INPO evaluation.

This was an example of personnel skepticism about the plant improvement initiatives and management's commitment to them.

32

• • • !:~

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'"-1*

3:2 Maintenance 3.2.1 Preventive/Corrective Maintenance Activities 3.2.1.1 Lubrication Program for Motor-Operated Valves The team reviewed the licensee's lubrication program for motor-operated valves (MOVs) and noted the following discrepancies: - -,, *. - **

(1) The team became concerned about the present ability of MOVs to operate as designed.

The team noted that there had been no periodic program in the past to inspect or relubricate MOV actuators even though Limitorque rec-ommends that the main gearbox lubricant be inspected at intervals of approximately 18 months or 500 cycles, whichever occurs first, and the **

geared.limit switch lubricant be inspected at intervals of approximately 36 months or 1000 cycles, whichever occurs first.

The licensee partially addressed this concern as a result of the environ-mental equipment qualification program.

This program resulted in the qualification of 85 MOVs, which were placed on a surveillance frequency schedule of every-:-other refue 1 i ng outage in accordance with Dresden~*

. Maintenance Procedure (DMP) 040~17, Revision 0, "Limitorq~e Environmental Qualification Surveillance.

11 This surveillance required, in part, the

• inspection of MOV main gearbox and geared limit switch lubricants.

The 85 remaining safety-related but non-environmentally qualified MOVs were not inspected or relubricated at periodic intervals.. A review of the licensee's records revealed that there was no engineering evaluation that justified not following the vendor's lubrication recommendations for these

• MOVs.

The team was particularly concerned with this lack of preventive maintenance of non-envirorvnentally qualified MOVs because a review of the licensee's work request history revealed that numerous environmentally qualified operators that were refurbished as a result of the equipment qualification program had experienced harden~ng and separa-tion of main gearbox grease.

(2) The team noted that 17 limitorque MOVs inside_ the dry well were lubricated with an apparently unqualified grease.

The Limitorque vendor manual.

states that Exxon Nebula EP-0 and EP-1 are the only approved lubricants for MOVs inside the containment (drywell).

However, licensee records indicate that the main gearboxes of the MOVs, listed below, were filled with Mobil Mobilux EP-0.

. -~;....

Valve Number

~~

• ~

M0-~-1001-18 M0-2-1201-1 M0-2-1201-lA

.M0-2-1301-1 M0-2-1301-4 M0-2-2301-4 M0-3-202-SA shutdown cooling reactor water cleanup reactor water cleanup isolation condenser isolation condenser high-pressure coolant injection recirculation

33.

. ~..

Valve Number M0-3-202-58 M0-3-220-1 M0-3-1001-lA M0-3-1001-lB M0".'3-1201-1

.. M0-3-1201-.lA M0-3-13011 M0-3-1301-4 M0-3-2301-4 M0..;3-3706 A

System

• reci rcul at ion main steam shutdown cooling

. shutdown cooling reactor water cleanup

. reactor water cleanup*

isolation condenser isolation condenser high-.pressure coolant injection reactor building closed cooling water Dresden Equipment Qualification (EQ) File 015890, Revision 4, "Environmen-

• tal Qualification of Mobilux EP-0, EP-1, EP-2 and Mobil Grease 28 Mobil Oil Company," notes that Exxon Nebula EP-1 was environmentally qualified for BWR service on the basis of Limitorque Test Report 600376A.

This EQ file also notes that Limitorque Lubrication Data Form LC8 dated October 6,

• 1979 and Limi torque Cata 1 og, pages. 11 and 12, i ridi cate that Mobil ux EP-0 is an acceptable substitute for Exxon Nebula EP-1 because they have niany identical properties.

On the basis of this information, the licensee environmentally qualified Mobilux EP-0 because of its similarity to Exxon

.Nebula EP-1. - The Limitorque Catalog, page 12, however, notes that no lubricant is an acceptable substitute for Exxon Nebula EP-0 or EP-1 for containment (drywell) MOVs.

A further review of earlier revisions of EQ File 015890 indicated that traceability of Mobilux EP-0 back to its original testing was not adequate.

Discussions with industry personnel revealed that the traceability was not adequate because the formula for Mobilux EP-0 that was originally tested was slightly different from the

. formula. for the commercially available Mobilux EP-0 that is being used by the licensee.

The licen$ee also noted in EQ File 015896, Revision 4, Section 4.9 of the "Maintenance and Surveillance Schedule," that another utility, American Electric Power (D.C. Cook), had obtained interim approval by the NRC to

• continue using Mobil lubricants for EQ applic~tions until* the requalifica-tion was complete.

[Note:

discussions with NRC headquarters personnel confirmed that a justification for continued operations (JCO) was granted in 1985 to allow the use of Mobil lubricants (the types were not specified) at D.C. Cook in environmentally qualified components until the lubricants were qualified or replaced with already qualified lubricants.]

A review of licensee records revealed that there was no NRC-approved JCO on record that provided for the use of Mobilux EP-0 in drywell MOVs. * (NRC headquarters personnel also noted that no known qualification of Mobilux EP-0 was currently available.) The Mobil Corporation is conducting an environmental test program to qualify Mobil lubricants, but the test results were not available during the evaluation. *The team, therefore, could not determine the acceptability of using Mobil Mobilux EP-0 for drywell MOVs and referred the matter to the Office of Nuclear Reactor Regulation for resolution.

34

(3) Because Mobilux EP-0 is less viscous than the qualified Exxon Nebula EP-1, it is more likely to migrate fr6m the gearbox to the Belleville spring*

pack.

Grease in the spring pack can contribute to a hydraulic lock phe-nomenon and subsequent MOV failure. A review of licensee records indicated two instances where LPCI pump suction MOVs in Units 2 and 3

. failed because a hydraulic lock in the spring pack prevented torque switch operation and subsequent deenergization of the motor.

In one case

• (M0-2-1501-2B), the motor

• overtorqued and cracked the operator, and in the*

• other case (M0-3-1501-5A), the 480-V ac supply breaker opened on thermal overload.

• Contributing to this phenomenon was the orientation of the MOVs so that the spring pack was at a lower elevation than the gearbox.

(4) The team reviewed OMP 040-17, Revision 0, "Limitorque Environmental Quali-fication Surveillance," and OMP040-18, Revision 0, 11 Limitorque Environ-mental Qualification Maintenanc*,

11 and found that the guidance regarding MOV lubrication was inadequate.

(a) Checklist 2 of DMP 040-17 indicates that the licensee planned to lu-bricate MOV main gearboxes with Mobilux EP-0 whenever the MOVs re-quired repairs that necessitated the disassembly of the gearbox, as opposed to the Limitorque-recommended lubrication interval as st.ated in Section 3.2.1.1(1).

The team considered this approach to lubricating the MOV main gearboxes inadequate because improper lubrication or lack of lubrication may be the cause of MOV failure.

Immediately following the onsite period, the team noted an instance of such an MOV failure caused by inadequate lubrication.

The Unit 3 high-pressure coolant injection (HPCI) pump minimum flow bypass to torus MOV M0-3-2301-14 failed because of a damaged Belleville spring pack that caused the HOV to seize.

The licensee's investigation revealed that there was hardened grease in the spring pack and water in the gearbox.

The team noted that this MOV had apparently never been relubricated or inspected during its installed life of approximately 17 years.

(b). Step 7 of Checklist 1. of OMP 040-17 provides for the inspection of the MOV limit switch assemblies.

Part of this step calls for an in-spection of the lubricant in the geared limit switch compartment, and lubrication of the geared limit switches, as necessary, in accordance with Checklist 2.

A review of Checklist 2, however, revealed no dis-cussion of geared limit switch lubrication.

Step 8 of the Limitorque

• EQ data checklist of OMP.040-18 also provides for the lubrication of environmentally qualified MOVs and instructs the technicians to refer to Checklist 2 of OMP 040-17, but the procedural guidance does not differentiate between the main gearbox and the geared limit switch.

Although Checklist 2 of OMP 040-17 does not specify what type of lu-bricant is to be used for MOV geared limit switches, a review of the licensee's work request history revealed that the licensee was using the Limitorque-recommended lubricant,.Mobil grease 28.

' 35

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3.2.1.2 MOV Torque Switch and Limit Switch Setpoints The team rev1ewed the li~ensee 1 s control of MOV ttirque switch and limit switch setpoints.and identified the following weaknesses:

(1)

(2)

The settings of torque switches for safety-related MOV operators did not appear to be ba~ed on expected design differential pressures.

In a letter

_from Limito~que to Bechtel Power Corporation dated April 24, 1985, Lf~itorque provided a tabulation of torqu~ switch settings for 18 environmentally qualified MOVs for Units 2 and 3.

However, the bases for these setpoints were not discussed.

The team could not find evidence that the remaining safety-related MOV torque switch settings were based on expected design differential pressures.

In its response to Office of Inspection and Enforcement (IE)Bulletin 85-03, 11Motor-Operated Valve Common-Mode Failure During Plant Transients Due to Improper Switch Settings, 11 the licensee did not document a listing of the design differential pressures at which these valves are expected to operat~, as required by the bulletin.

Furthermore, in its response to the bulletin, the licensee stated that the current method for establishing the proper torque switch setting was adequate, even though the design differ-ential pressure at which these valves.are expected to operate was*

apparently not considered.

The team considered this response to be inadequate~ The team did note, however, that ~ubsequent to the submittal of th~ licensee 1s response to IE Bulletin 85-03, the licensee decided to determine correct torque switch settings and adjust the valves accordingly.

At the time of the evaluation, licensee records revealed that for three of six HPCI system MOVs tested (M0-2-2301-6, M0-2-2301-35, M0-2-2301-36), the manufacturer 1 s recommended maximum design thrust had been exceeded and the torque switch settings had to be changed.

Additionally, testing revea 1 ed incorrect 1 i mi t switch settings for M0-2-2301-35 and M0-2-2301-36.

In view of these results, the team raised the concern that similar conditions might exist for the 154 safety-related MOVs that are outside the scope of IE Bulletin 85-03.

The team noted that setting MOV limit switches was often inconsistent with the procedural guidance.

The open and closed limit switches for.

Limitor~ue MOVs were set as described_in DMP 040-9, Revision l, 11 Limitorque Valve Operator Maintenance.

11 As a guideline, it states that the limits should be set 1/4 inch of shaft travel from the full-closed position and 1/4 inch to 1/2 inch of shaft travel from the full-open posi-tion.

Discussions with licensee maintenance technicians revealed that there was no consistent method of setting the geared limit switches; Li-censee personnel stated that in some cases they would set the switches from 1/4 inch to 1 inch of shaft travel from the full-open or full-closed positions, and at other times they would set the limit switches at a certain percent of valve stem travel.

These settings would be determined

• by discussions with maintenance foremen and Operations Department personnel, review of the maintenance work packages, or personal knowledge based on previous work on a particular MOV.

Although the licensee 36

• ,£:

• • e.**

...... :A

-~

typically verified the limit switch settings with current/limit switch signature data obtained during post-maintenance testing, discussions with licensee personnel and a review of corrective maintenance work requests revealed that MOVs were still failing because of improper limit switch settings.

The team noted that MOVs occasionally became stuck on their back seats and subsequently failed to close.

Setting the open limit switch too close to the open seat may result in a valve becoming stuck on its back seat.

The team considered the procedural guidance for establishing limit switch settings to be weak because this* activity is not considered by the team or general industry practice to be within the skill of the trade for maintenance technicians.

(3) The team's review of DMP 040-9 revealed that the licensee did not control torque switch settings for non-safety-related MOVs, but rather instructed the technicians to set the torque switch to the "as-found" setting follow-ing MOV switch maintenance.

The governing procedure provided no means for changing the switch settings of non-safety-related MOVs even though there may be instances when a change in torque switch setting is necessary.

3.2.1.3 Maintenance Corrective Actions The team noted instances of equipment failure in which the resulting corr~ctive action was applied only to the component that failed and not to components of a similar type, lessons learned were not reflected in the appropriate procedures, and the effectiveness 6f the corrective action was negated beca~se of a lack of communication and coordination between station departments.

Several examples of these weaknesses are given below.

(1)

Licensee Event Report CLER) 87-018-00 documented the inoperability of the Unit 2 HPCI system room cooler on June 6, 1987, because of the failure of the fan motor belts.

The failure was attributed to wear and age of the

.belts.

The team noted that preventive maintenance procedure, OMP 5700-3, Revision p, "LQ. Surveillance and Maintenance of LPCI Room Cooler Fan Motors," accomplished, in part, the periodic inspection and replacement of the LPCI system room cooler fan motor belts.

No similar preventive maintenance activities were systematically performed for the HPCI room cooler even though licensee records revealed that there was a previous instance of HPCI room cooler inoperability caused by problems with the fan motor be 1 ts.

(2) The licensee performed an in-depth functional inspection of the Unit 3 emergency diesel generator (EOG).

Preventive maintenance deficiencies were among the licensee's findings.

The licensee noted that EOG relief valves were not inspected, cycled, or tested periodically.

Additionally, EOG instrumentation used to*monitor eng1ne performance and determine pro-per operation *was not periodically calibrated.

The team noted similar types of preventive maintenance deficiencies associated with the HPCI tur-bine control oil systems in Units 2 and ~-

The team noted four separate instances, spanning a 2-month period, where the HPCI system turbine control oil auxiliary oil pumps (AOPs) were prematurely tripping.

This condition was detected by the licensee while conducting monthly operating 37

surveillance 2300-1, 11 HPCI Motor-Operated Valve and Pump Operability Test.

11 The AOP delivers control oil for HPCI turbine control valve operation until the turbine has attained the requi~ed speed of 2000 to 4000 rpm and the main shaft oil pump (MSOP) can deliver sufficient discharge pressure to operate the control valves.

The licensee's investi-gation of the problem revealed that the pressure regulating valves (PRVs) in both control systems had worn diaphragms, the lower piston head of one

• . PRV was complete)y unthreaded, pressure relief valves.were not set to. the

~rescribed setp6ints, and the pr~ss~re switches (PS4) that trip the AOP for each HPCI turbine were not set to the prescribed setpoints.

Discussions with licensee personnel revealed that none of these components

. were routinely inspected or calibrated.

Although the licensee ~ad not determined the root cause at the time of the-evaluation, it had ruled out component failure or out-of-calibration components and instruments. *The team noted~ however, that if preventive maintenance had been performed on these components, the problem with premature tripping of the ADPs might have been detected much earlier--something that the monthly operability surveillance testing had not accomplished in several years of station operation.

(3) The team reviewed the licensee's internal written evaluation of IE Information Notice 85~22, "Failure of Limitorqlie Motor-Operated Valves Resulting From Incorrect Installation of Pinion Gear.

11 In its evaluation, the licensee noted that the electrical maintenance personnel repair Limitorq~e valve operators following instr~ctions outlined in the vendor's manual.

In additio~, the licensee not~d that the maintenance personnel document the sequence used todisassemble machinery and that a pictorial representation of the machinery before disassembly also is required.

The

~

team reviewed work requests associ~ted with MDV motor removal and instal-lation and noted that the Limitorque vendor manual was not referenced and

~-

that no sequence of motor remo~al and fnstallation was documented, other than a genera 1 step to 11 remove" and 11 insta11 11 the motor.

The licensee had proc~dures f6r the repair of Limitorque operators, but the section for motor and motor pinion gear removal and installation had been omitted.

Discussions with maintenance staff revealed that these personnel.*

considered the remova 1 and i nsta 11 at ion of MDV motors and pinion gears to be within skill of the trade for maintenance technicians..

(4) The team's review of licensee records and discussions with Maintenance De-partment personnel revealed that MDVs in three different systems had failed because the MDV pinion gear setscrews vibrated loose.

These failures occurred because there was no lock wire installed to secure the setscrews in place.

The team noted that none of the licensee procedures had been revised to ensure that pinion gear lock wire was installed following maintenance, nor did the licensee have a program to ensure that safety-related MDVs.were inspected for pinion gear lock wire installation in spite of the previous MOV fa1lures attributed to this phenomenon.

(5) The team's review of licensee records revealed that hydraulic lock caused by excessive grease accumulation in the Belleville spring pack had caused 38

iJ (6) a.. *

• • e.*****

the 480-V ac breaker to trip for LPCI pump A suction MOV M0-3-1501-SA, and a motor overtorquing condition for LPCI pump B suction MOV M0-2-1501-SB.

In both cases, the MOV spring packs were at their lowest vertical orienta-tion relative to the gearbox and were lubricated with less viscous Mobilux EP-0, thus facilitating grease migration.

For a Limitorque MOV, torque is transmitted as a linear compression force to the Belleville springs when the valve is seated.

The compression in the spring pack assembly then

• operates the torque switch.

The operation of the torque switch. opens con-tacts *in the valve control circuit and de-energizes the motor.

Excessive '

grease in the spring pack assembly caused a hydraulic lock in these two instances and prevented the compression of the spring.

To prevent further recurrence of this phenomenon, the station technical staff checked all the MOVs that were susceptible to migration and performed one or more of the following corrective actions:

changed the orientation of the MOV by 180° to place the spring pack at the highest possible vertical position relative to the gearbox, installed an external grease relief, installed new MOVs that are equipped with a premachined notch in the spring pack.

The team noted that for four safety-related MOVs (M0-2-2301-3,

• M0-2-2301-10, M0-2-1001-2A, and M0-2-1001-2B), rio action was taken because these MOVs were lubricated with the more viscous SUN OIL 50EP.

Because SUN OIL 50EP is more viscous than Mobilux EP-0, it is less likely to mi-grate into the Be 11evi11 e spring pack.

The team raised a. concern about the adequacy of this corrective action because it is the licensee's ~rac tice to relubricate all MOVs that are dissembled for corrective maintenance with the less viscous Mobil~x EP-0.

A further review of licensee's records reveaied that the technical staff had intended that maintenance staff install external grease reliefs on these MOVs when the*

grease relief kits became available.

This corrective action, however, was not directly communicated to the Maintenance Department.

A subsequent review of licensee records revealed that the maintenance personnel relubricated the Unit 2 HPCI system test bypass to condensate storage tank MOV M0-2-2301-10 with Mobilux EP-0, even though none of the other types of corrective action to prevent hydraulic lock had been performed.

The licensee has had a history of material problems associated with the feedwater regulating valves (FRVs) of both units.

While the team was on site, Unit 2 scrammed on low level.after the 2A FRV stem failed and sepa-rated from the disc, causing a loss of feedwater flow.

FRV 2A had been disassembled less than 2 weeks before because it had stuck at approxi-mately 55 percent of the full-open position.

The sticking FRV was caused by a feedwater check valve holddown bolt that had become wedged in the valve body and restricted stem movement.

Discussions with licensee per-sonnel revealed that the stem was cracked and should have been detected by visual examination.

The cracked stem apparently was not detected and the FRV was subsequently reassembled.

The team considered the lack of an ade-quate nondestructive examination of the FRV stem inconsistent with good industry practice.

Additionally, the team noted a previous instance of FRV failure.

The stem for Unit 3A FRV became separated from the disc be-cause of another failure mechanism in late 1984.

Although the licensee.

39

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(7)

~

A

~

inspected the oth_er FRVs, the team noted that the licensee had not estab-1 i shed a periodic inspection program for the FRVs, nor had it written a correctjve maintenance procedure to repair FRVs in a consistent manne~.

The team reviewed the licensee's 1986 and 1987 maintenance QA audits and surveillance reports.

The team found that the QA Department's involvement in maintenance was primarily limited to spot-checking the implementation

. effectiveness of the work request system.

For example,. QA Audit 12:-87,..62, "Preparation and Use of Work Packages, 11 was based on the review of approximately 12 completed work requests.

This audit noted that approved maintenance instructions for work on safety-related systems were frequently not followed, and that some work that was performed as.

corrective maintenanc~ were actually plant modifications.

The NRC SSOMI team inspectors noted similar findings in 1986.

The response to the audit

• findings was due on AOgust 20, 1987, but the team was unable to assess the adequaty of the Maintenance Department's.response to the~e audit findings because the response was still. being drafted.

The team was concerned about the lack of timeliness of this response.

The licensee had known about these types of findings for well over a *year, but had.not implemented corrective action.

Although QA Audit 12-87-62 noted significant weaknesses with the implemen-tation effectiveness of the work request system, the team could find no evidence that the QA Department had identified maintenance weaknesses that were ~imilar to those of the team.

The team did find that a QA audit of the maintenance program was scheduled for the latter part of 1987, but the team wa~ unable to ascertain the scope of this audit.

3.2.1.4

~aintenance Procedures The team reviewed maintenance activities associated with MOVs and other safety-related and balance-of-plant (BOP) equipment components and identified the followihg procedural weaknesses:

(1)

DMP 040-16 (Revision O) and DMPs 040-19 and 040-23 (Revision 1) are used to repair MOV operators, sizes SMB-000 through SMB-5.

None of these pro-cedures, however, provided guidance for the removal and installation of MOV motors and pinion gears.

This guidance is essential for the following two reasons:

(a) Improper installation of the motor pinion gear can result in MOV failure.

If the gear is installed incorrectly, the gear teeth will not fully engage with the worm shaft and clutch gear teeth, resulting in failure of the gearing.

This failure mechanism is discussed in IE Information Notice 85'." 22, 11 Failure of Li mi torque Motor-Operated Valves Resulting From Incorrect Installation of Pinion Gear.

11 For certain types of MOVs, the pinion gear is installed in a reverse direction.

Clear procedural guidance for pinion gear installation will significantly reduce the chance of incorrect pinion gear installation.

40

(b) For certain types of MOVs, the pinion gear setscrews must be secured with lock wire.

If the lock wire is not installed, the pinion gear setscrews may vibrate loose.. This condition may lead to MOV failure.

A review of the licensee's records revealed that the setscrews for M0-3-4402D, a nonsafety-related main circulating water system flow reversing v'alve, vibrated loose because lock wire was not installed; The MOV failed and caused a low main condenser vacuum condition, and Unit 3 subsequently scrammed on low main_condenser vacuum.

Discus-sions with licensee personnel revealed that MOVs in the feedwater and recirculati-0n syste~s failed by the same mechanism.

The team was con-cerned that this lack of procedural guidance might lead to MOV fail-ures in station safety systems.

(2)

DMP 040-17, Revision 0, is used to perform maintenance, in part, on envi-ronmentally qualified MOVs that are operated by. direct. current (de) motors.

Thes~ MOVs require additional maintenance to ensure that the motor brushes are not excessively worn, the brush tension is satisfactory and the brush is free in the brush holder, and the commutator is not grooved or pitted.

Similarly, DMP8300-4, Revision 2, "Unit 2/3 Inspec-tion of DC Motors.and Brushes, 11 is performed for other safety-related de motors at the end of a refueling cycle to prevent safety-related de motor failure. *The team reviewed both of these procedures and found that :

neither procedure encompassed the safety-related (non-environmentally qualified) MOV de motors listed on the following table.

Valve Number M0-2(3)-1001-2A M0-2(3)-1001-28 M0-2(3)-1001-2C M0-2(3)-1301-10 M0-2(3)-2301-3 M0-2(3)-2301-6 M0-2(3)-2301-9

. M0-2(3)-2301-10 M0-2(3)-2301-14 M0-2(3)-2301-15 M0-2-2301-36 M0-2(3)-2301-48.

M0-2(3)-2301-49 System shutdown cooling.

shutdown cooling shutdown cooling isolation condenser htgh-pressure coolant injection high-pressure coolant injection high-pressure coolant injection high-pressure coolant injection high-pressure coolant injection high-pressure coolant injection high-pressure coolant injection high-pressure coolant injection high-pressure coolant injection The team raised the concern that a lack of de motor preventive maintenance for these MOVs may lead to premature motor failure.

(3)

DMP 040-11, Revision 1, "Electrical Backseating of Limitorque Operated

Valves, 11 is performed to electrically back seat MOVs to eliminate or reduce valve packing leaks that cannot be repaired without taking the affected system out of service.

The team reviewed this procedure and noted that there was no CAUTION STATEMENT to ensure that a valve is back seated at its normal operating temperature.

If a valve is bac~ seated while the system is relatively cool and then subsequently heated, the valve disc may become wedged on the back seat as a result of thermal binding.

This condition could lead to MOV failure.

41

• e****.*.. *

(4) Recirculation system pump suction valves M0-2(3)-202-4A and M0-2(3)-202-48.

are equipped with motor brakes.. These motor brakes overcome stem inertia after the valve has been stroked, thus preventing the valve disc from becoming wedged in the main seat or on the back seat.

However, no preventive maintenance p~oced~res or requirements had been established to periodically inspect the brake rotating friction disc for excessive wear even though_ such inspections are tecommended by the motor brake vendor.*

(S) - Th-e team's review of. th~ licensee Is mai nte~ance procedures re~eal ed thaf the licensee did not have maintenance procedures for many safety-related and BOP system equipment components.

Examples included HPCI room coolers, HPCI pumps, FRVs, torus vacuum breakers, and condensate pumps.

Some of the components, such as the FRVs, had been repaired several times during the past several years and still no corrective maintenance procedure had been developed.

Discussions with licensee management revealed that the licensee had been aware of the lack of corrective maintenance procedures and had started to draft new procedures.

3.2.2 Maintenance Trending The team reviewed the Maintenance Department's component failure and l~brication and oil analysis trending ~rograms. Component failures were trended by use of maximum occurrence reports (MORs), which were generated*

automatically from the completed work request files whenever a component's failure rate reached a predetermined limit.

The limit was set at two failures in 6 months.

The team noted the following weaknesses in the trending of MORs and the trending of the lubricati6n and oil analysis program.

(1) Dresden Administrative Procedure (OAP) 4-10, Revision 0, "Post Maintenance Review and Trending of Nuclear Work Requests, 11 is the governing procedure*

for trending work requests.

It was issued in July 1987 and superseded OAP 4-3, Revision 1, uEquipment History and Trending," which had been in effect si nee** May 1986.. The* team found the fo ll~owi ng weaknesses.

(a) The governing procedure provides for trending only specific equipment component failures rather than trending by equipment component type or model number.. If equipment failures are not trended by component type, the effectiveness of the corrective action might be reduced because generic failure mechanisms might not be recognized and therefore not corrected for all components of a similar type.

Discussions*with licensee corporate personnel revealed that failures of equipment com-ponent types were being trended at the corporate level for CECo nuclear stations. lhis trending was accomplished by the use of CECo Report Y30TJM, "Nuclear System Manufacturer/Model Number Work Request Summary."

The team noted that this report was ineffective as a trehding tool because a significant percentage of the equipment component model numbers to be trended had not been entered into the total job management (TJM) system data base.

As a result, failures of these components would 42

. e.

not be reflected in the report.

Additionally, the report did not list the nomenclature of the equipment to be trended, but rather the vendor name and model number, making it difficult to determine exactly what type of component had failed:

Discussions with licensee corporate personnel revealed that they were aware of these weaknes-ses.

However, the licensee indicated that it would require a signi-

• ficant resource commitment to upgrade the report.

At the time of the evaluation, no resources had been committed to improve the corporate

• trending report. * *

(b)

MORs were generated automatically from the work request history that had been inserted into the TJM system computer.

These data were ex-tracted from ~ompleted hard copy work requests.

The licensee plans to solely rely on the computer-based work history for trending and*

will only retain the complete work request history on microfilm, which is not easily accessed by maintenance technicians.

An e~sen-.

tial element of effective trending is to c*onipletely record on the work request.the cause of the failure and what was done to correct the problem.

A review of licensee work requests revealed, however, that the cause of equipment failure was not consistently recorded, nor were the details of the work performed.

Additionally, the team

. noted that electrical maintenance personnel, and to a lesser degree mechanical maintenance and instrument mechanic maintenance personnel, had highlighted only portions of the work performed section for inclusion in the TJM data base.

This practice further reduced the amount of information available for equipment failure trending.

Discussion~ with licensee personnel revealed that this practice was common because the computer field for work performed was originally very limited:

However, the field size had been subsequently expanded, but the Maintenance Department had not been informed of the change.

It was the team's understanding that the Maintenance Department was now aware of this practice and was taking steps to correct it.

(c)

OAP 4-10 provides no means of tracking the status o.f the recorded trending corrective actions that afe assigned to the Maintenance Department.

Additionally, it does not provide for a periodic review by the Maintenance Department heads to ensure that actions recorded

. on the trending worksheet log are being completed, nor does it provide for corrective actions oversight by the A~sistant Superintendent for Maintenance.

(2)

OAP 4-2, Revision 2, "Preventive Maintenance Program," requires, in part, that the Preventive Maintenance (PM) Coordinator monitor and trend data provided by the lubrication and oil. analysis program.

Discussions with licensee personnel revealed, however, that no trending of the data from the lubrication and oil analysis program had been performed because the program was viewed as inadequate and had to be significantly upgraded before trending would be meaningful.

43

• • ~'...

• ~

~..

. e.

The team could find no objective evidence that the trending program has improved station maintenance activities.

The new trending procedure has not corrected any of the weaknesses identified by NRC Region III personnel in May 1987.

These weaknesses included not trending identical component failures and a lack of documentation of MOR reviews by the Maintenance Department heads.

The team is concerned that the current trending program will not be any more effective than the licensee's past efforts.

3. 2. 3 Measuring ahd Te.st.Equipment.

The team reviewed the methods for calibration and control of measuring and test equipment (M&TE) for electrical maintenance (EM) and mechanical maintenance (MM).

M&TE is used to properly maintain the station's equipment.

The team did not find any instance where uncalibrated M&TE was used during the performance of safety-related maintenance activities.

However, as noted below, the EM M&TE log sheets were found to be not auditable.

The team identified the following weaknesses with the EM and MM M&TE program.

(1)

(2)

(3)

(4)

DMP 100-2, Revision 2, "Control of Measuring and Test Equipment,"

• requires, in part, that a log be maintained for electrical test equipment.

This log documents the instrume~t description, serial number, mechanic's name, and a brief job description.

EM M&TE log sheets were maintained on several clipboards.

These sheets were filled out randomly by mechanics checking out tool~ from the tool crib and were not placed in.chronological or sequential order.

As a result there was no method to ensure accountability of the sheets and, therefore, the accountability of the tools that were issued for use.

EM M&TE log sheet's were not completely filled out.

Signatures were m-issing on MM calibration re.port sheets*.

There was no evi den-ce that' the EM sup*ervi s*or was verifying that the tool crib log was being properly maintained as required by the governing procedure..

(5) Discrepancy Report 87-083 documented that torque wrench, serial number 44277, was out of tolerance; however, this torque wrench was found in the tool crib and ready to be issued.

(6) Several other administrative discrepancies were noted, including missing as-found data, a missing calibration record sheet, an outdated EM M&TE list, and errors with the calibration record index.

On the basis of M&TE findings, the team developed concerns about the effective-ness of M&TE quality assurance (QA) audits.

The team's review of completed 1987 QA audits revealed that the licensee's QA organization conducted an audit of the M&TE program in February 1987.

The team found, however, that Audit Report QAA 12-87-05 did not reflect the fact that the Electrical Maintenance Department's M&TE calibration record sheets were not being satisfactorily maintained (See Section 3.5).

44

~

• .**e 3.2.4 Material Deficiencies The tea~ conducted a detailed walkdown of portions of the Unit 2 LPCI system to verify that the system layout was as depicted in the system piping and instrumentation diagrams and that the system was aligned as required by licensee procedures, and to evaluate the material condition and cleanliness of the system.

The following deficiencies were noted during the walkdown:

• (1)

• Limitorque operator stem p*rotector cap was missing'for*M0-2-1501-llA:

(2) Grafitti was noted in the Unit 2 D-28 corner room.

(3) Handwheels for valves on LPCI 28 pump pressure sensing lines were missing.

(4) Several local MOV cont~ol stati~ns had burned-out lights.

(5) Reactor water cleanup surge tank l~vel/pressure gauges and the Unit 2 A corner room keep fill pump were not labeled.

(6)

An electrical cord was lying on the Unit 2 standby liquid control system pump motor..

(7) Needle valve adjustment caps for the Unit 2 control rod drive hydraulic control units were missing.

The team found that the system layout was as depicted in the system drawings and the system was aligned as required by the procedures.

Cleanliness was average in the vicinity of the LPCI components as well as throughout the station.

The technicians favorably viewed the improvements in station clean-1 iness and we~e generally optimistic that management would keep the.station clean.

3.2.5 Maintenance Department Communications The team conducted several interviews with Maintenance Department personnel, including management, supervisory, and craft personnel.

Overall, Maintenance Department personnel s.eemed competent and had a hi.gh regard for personnel and equipment safety.

The team identified, however, several barriers to effective interdepartmental and.intradepartmental communication.

The following are examples:

(1)

Some maintenance technicians felt that their work efforts were unneces-sarily hampered because of a lack of sufficient job planning.

Technicians stated that work was delayed because of a lack of coordination with Radiation-Chemistry and Operations Department personnel even though jobs were scheduled well in advance.

They cited several indicators of poor job planning.

These included incomplete work request packages, little ~r no job briefings or mockup training, unwritten radiation work permits (RWPs) and system outages (danger tagouts), and improper plant or system initial conditions.

Maintenance techniCians stated that they had communicated these concerns to their foreman in the past, but had not seen 45

any improvements and had nq explanations why improvements had not been made.

(2) Maintenance technicians generally believed that management's efforts to track and prevent material failures caused by maintenance personnel errors was nothing more than a mechanism to identify and punish individual tech-nicians, instead of a method to identify root causes and apply lessons learned within the department.

Discussions with Maintenance Department management revealed that it was aware of the technida*n* s perception of the "rework" program even though no technicians had been given disciplinary time off without pay for causing personnel errors.

At the time of the evaluation, the licensee was studying another utility's

- maintenance trending and lessons learned program in an attempt to improve the effectiveness of its program and to resolve the technician's misperception.

(3)

Licensee operators noted several instances of poor communication and inadequate Maintenance Department support.

(See Section 3:1.4 for further details.)

Intervie~s _with maintenance technicians revealed, however, that the maintenance technicians believed that they had good working relations with individual operators.

Some technicians were aware of friction between the two departments, but attributed this to individual personality conflicts.

(4) The team noted thatsome Maintenance Department supervisory personnel be-lieved that they did not possess sufficient latitude in assigning work to

.their groups.

They attributed this to union contract rules.

Additionally, an Electrical Maintenance (EM) Department foreman felt that his efforts to spend more time performing preventive maintenance was hampered by the union's insistence on performing work that, in his view, fell outside the purview of the EM Department.

He cited several examples that.included fire protection maintenance, security system maintenance, facility.maintenance, and.construction jobs, that would-normally have been assigned to contractors or other station departments.

He -felt that these additional activities ti~d up resources that could have otherwise been spent on performing much needed safety-related preventive maintenance.

(5)

Some EM technicians did not understand the benefit of documenting BOP maintenance acti~ities. They stated that BOP maintenance instructions were now incorporated into BOP corrective maintenance work requests, but that they felt this was unnecessary.

They believed that they had per-formed adequate BOP corrective maintenance in the past without work instructions or documentation; therefore, there was no need to start doing it now.

They viewed the practice as an additional barrier to performing work.

The team raised the concern that the benefits of planning and documenting BOP corrective maintenance had not been adequately communi-cated to EM technicians.

The team attributed the poor working relations and communications between the Operations and Maintenance Departments to the operator's perception that 46

operational events were primarily caused by material failures because the Maintenance Department personnel were not adequately performing their assigned duties.

This perception seemed valid insofar as the lack of an effective preventive maintenance program and often ineffective maintenance corrective actions.had led to equipment failures causing numerous challenges to plant safety systems.

Interdepartmental communication also seemed to be negatively impacted by an apparent lack of departmental coordination, which, at Dresden, was overseen by the P~oduct ion Department.. _

Overall, the recent management changes within the Maintenance Department seemed to be a positive step toward improving maintenance activities at the station.

The new Assistant Superintendent for Maintenance and the three new department heads were we 11 received by the technicians.

Al though the technicians were mindful of problems with work planning, they noted improvements in other areas and viewed the.weekly 11tailgate 11 meetings as an effective forum for.voicing union and ~ariagement issues and concerns.

3.2.6 Maintenance Department.staff An evaluation of the Maintenance Department staff resulted in the following observations:

(1) The team found that of the recent changes in Maintenance Department management, the most significant was the new Assistant Superintendent for Maintenance (ASM).

This ASM had held the same position at the Quad Cities Station and is one of the most experienced of CECo ASMs.

The ASM had been at Dresden for approximately 5_months at the time of the evaluation.

He was familiar with the problems in the department, but had not implemented programs to solve them.

The team attributed this to his lack of familiarity with Dresden and the considerable time and resources he had to expend to accommodate a CECo maintenance assessment, an INPO evaluation, and the NRC diagnostic evaluation.. The team also found that the ASM~was waiting for corporate direction for the implementation of a preventive maintenance program.

On the basis of discussions with the ASM, the team was impressed with his ability.

The team had the impression that this ASM could signifi~antly improve maintenance activities at the station if he were given the resources to do so.

• Three new Maintenance Department heads also have been assigned.

The new Master Mechanic and Master Instrument Mechanic were transferred from other station departments, while the new Master Electrician had been the previous Master Instrument Mechanic.

The new Master Instrument Mechanic and Master Electrician were in the process of assuming their new duties and the Master Mechanic had only been in his job for a short time at the time of the evaluation.

As a result, the team was unable to fully assess the i~pact of these management changes, but did find that these changes were well received by the technicians.

(2) There were approximately eight technicians for every foreman in the department.

The team considered the span-of-control of the maintenance foreman to be adequate. *However, the team noted that Dresden's maintenance organization, unlike the maintenance organization.of many other nuclear stations, was staffed with few maintenance engineers.

In other organizations, 47

• ,... 9.:

• • e

~-

these maintenance engineers perform such functions as fire protection coordination, equipment qualification coordination, preventive maintenance coordination, procedure writing, spare parts analysis, equipment/failure trending, dispositioning of maintenance-related deviation report~, and ~endor and station technical services interface.

Some of these functions were being performed by the recently instituted ASM staff while other functions were being performed by maintenance personnel as a secondary or collater.al.duty.

Because.. ofweaknesses in.

the areas of preventive ~~intenance, eq~ipmerit trending, corrective actions, and interdepartmental communication, the team raised the concern that the staffing might not be sufficient to perform these functions.

The team was particularly concerned that significant additional resources would be needed to implement an effective preventive maintenance program.*

3.3 Testing The team found that the second 10-year IST program, which was.submitted to the NRC in 1981, had not been re~iewed and approved.

This as~ect and other concerns with the IST program has been thoroughly discussed with the lic;:ensee and has been referred to the Office of Nuclear Reactor Regulation for

. resolution.

3.3.1 ASME Section XI Valve Testing.

the licensee did not have administrative procedures in place to control ISTs and ensure that all required tests were performed, evaluated, and trended.

During the evaluation, the licensee indicated that IST administrative proce-dures were being developed.~

The team reviewed surveillance test procedures to determine if any ASME*Section XI valves listed in the second 10;.;.year !ST.program were not being tested.

The team found that many valves.were not tested; examples include those listed below.

Valve Number 2-301-94 2(3)-1201-158 2(3)-1402-4A(B) 2(3)-1402-28A(B) 2(3)-1402-38A(B)

Valve Size and Type, System, Concern 4-inch manual gate *isolation valve, control rod drive (CRD), no tests performed 8-inch check valves, reactor water cleanup (RWCU), no tests performed 8-inch motor-operated gate valves, core spray, stroke/

timing tests not performed 2-inch relief valves, core spray, no tests performed 1~-inch motor-operated gate valves, core spray, stroke/timing tests not performed 48

.. ~.

Valve Number 2(3)-1501-13A(8) 2(3)-2301-14 2(3)"'.'1501-17A(8) 2(3)-2301-20

e.

Valve Size and Type, System, Concern 3-inch motor-operated gate valves, low-pressure coolant injection (LPCI), stroke/timing tests riot performed 4~inch motor-operated globe valves, high-pressure coolant injection (HPCI), stroke/timtng tests not performed~ Note: "The Unit 3 valv~ ~as d~clared i~

operable on September 19, 1987, because of hardened grease in the motor operator.

A properly implemented

!ST program should have discovered the problem and ensured operability.

2-inth relief valves, LPCI, no tests performed 16-inch check valves, HPCI, no test performed The team found that the HPCI injection isolation valves 2(3)-1402-24A(8), which are 10-inch motor-operated gate valves, had been stroke tested in the wrong direction (closed rather than open).

ASME Section XI, Article IWV-3000, re~

quires that valves be "exercised" to the position required to fulfill their safety function.

The licensee took immediate action to revise Surveillance Procedure DOS 1600-1, "Quarterly Valve Timing," to ensure that stroke testing would be performed in the proper direction.

New reference values for stroke timing will have to be established for the valves for trending purposes.

The team found inconsistencies between the requirements of the Technical Speci-fications, IST program, and the surveillance testing of ASME Section XI; examples include those listed below.

(1)

Maximum valve stroke times for valves 2(3)-2301-35, 2(3)-2301-36, 2(3)-4720, and 2(3)-4721 required by the !ST program conflicted with those mentioned in the Technical Specifications.

(2:)

"Normal" valve positions (open/close) required by the Technical Specifica-tions were different from those required by the !ST program.

Valves 2(3)-

220-1, 2(3)-220-2, 2-1501-lBA, and 2(3)-1601-59 were an example of this problem.

(3) Table 3.7.1 of the Technical Specifications listed the core spray injection valves as 1401-24A, 248; the correct designation should have been 1402-24A, 248:

(4) Surveillance Procedure DOS 1600-1, Revision 12, "Quarterly Valve Timing,"

did not list the full stroke time for each valve as required by ASME 49

Section XI.. Only 54 of 128 valves had stroke times listed.

took immediate corrective action to revise the procedure.

The licensee (5)

Evaluation Of test data and corrective action required by ASME Section XI (e.g., variation of stroke times and leak rate) was weak.

The test procedures generally did not record 11as-found 11 or 11as-left 11 information necessary to determine if additional testing would be required.

'Plant modifications were performed on safety..:related sys.terns whfCh involved the addition or deletion of Section XI valves.

Following any safety-related modification, Dresden's administrative procedures controlling plant modification requires appropriate revisions be made to update drawings, progr~ms, procedures, training, etc. affected by the modification.

However, the !ST program has not been revised to reflect modifications since it was submitted to the NRC for approval i~. 1981.

Examples of this problem include those listed below.*

Valve Number 3-301-94 3-202'"7A(B) 3-301"'-95 3-301-98 2(3)-302-21A(B)*

2(3):..1201-lA 2-301-157A(B) 3-302-156A(B) 2-301-158A(B)

Valve Size and/or.Type, System, Concern 4-inch manual gate valve, CRD, listed in the !ST program (removed during 85/86 outage) 4-inth motor-operated gate valves, recirculation, listed in the !ST program (removed during 85/86 outage) 4-inch Check valve, CRD, listed in the. !ST program (removed during 85/86 outage) 4-inch check valve, CRD, listed in the !ST program (removed during 85/86 outage) 1-inch air-operated globe valves, CRD, listed in the

!ST.program (removed during 82/83 outage) 2-inch motor-operated globe valves, RWCU, not listed in the IST program (added during a previous outage) instru.ment drain valves, CRD, not listed in the IST program (added during a previous outage) instrument drain valves, CRD, not listed in the IST program (added during a previous outage) instrument drain val~es, CRD, not listed in the IST

_program (added during a previous outage) 50

-... ~..

Valve Number Valve Size and/or T~Ee 1 S~stem 1 Concern 3-302-157A(B) instrument drain valves, CRD, not listed in the !ST program (~dded during a previous outage) 2-301-160A(B) scram volume vent valves, CRD, not listed in the !ST program (added during a previous outage)*

3:-302-160A(B) scram volume vent valves, CRD, not listed in the !ST program (added during a previous outage) 2-301-161A(B) scram volume vent valves, CRD, not listed in the !ST program (added during a previous outage) 3-302-161A(B) scram volume vent valves, CRD, not listed in the !ST program (added during a previous outage)

The team found that the !ST program and surveillance test procedures contained incorrect information regarding critical valve parameters; examples of this problem are listed below.

Valve Number 2(3)-1402-BA(B) 2(3)-1501-28A(B) 2(3)-1501-27A(B)

• 2(3)-1501-lBA(B) 2(3)-1501-19A(B) 2(3)-9206A 2(3)-8501-5A(B) 2(3)-9205A(B)

Valve Size and Type 1 System 1 Concern

• 12-inch stop che~k valves, HPCI, listed ~s 12-inch check valves 16-inch motor-operated gate valves, LPCI, -stroke direction not 1 iSted as 11open 11 16-inch motor-operated gate *valves, LPCI, stroke direction not listed as 11open 11 6-inch motor-operated globe valves, LPCI, stroke~

direction not listed as 11open 11 6-inch motor-operated gate valves~ LPCI, stroke direction not listed as iropen"

~-inch flow ~ontrol valves (FCVs), pressure suppression, DOS 1600-1 listed valves as air operated instead of solenoid operated

~-inch FCVs, pressure suppression, DOS 1600-1 listed valves as air operated instead of solenoid operated

~-inch FCVs, pressure suppression, DOS 1600-1 listed valves as air operated instead of sol~noid operated 51

"*. I Valve Number 2(3)-8501-3A(B) 2(3)-8501-lA(B) 2(3)-9208A(B}

• 2-2301-3 2(3)-2301-28 2(3)-1601-31A(B) 2(3)-305.;.114 2(3)-305-126 2(3)-305~127 2-1501-13A(B) 3-1601-20A(B) 2-202-7A(B)

• 2-2301-29 Valve Size and/or Type, System, Concern.

~-inch FCVs, pressure suppression, DOS 1600-1 listed valves as air operated instead of solenoid operated

~-inch FCVs, pressure suppression, DOS 1600-1 listed valves as air operated instead of solenoid operated

. ~.:.*i n~h FCVs, -pres'sure 'suppress1on,. DOS 1600-1 1 i sted valves as air operated instead of solenoid operated

~-inch FCVs, pressure suppression, DOS 1600-1 listed valves as air operated instead of solenoid operated

... ~

10-inch motor-operated gate valves, HPCI, stroke direction to fulfill safety function not indicated in.

IST program 1-inch air.;.operated globe valves, HPCI, stroke direction not listed as 11open 11 in IST program 20-inch check valves, pressure suppressi.on, stroke direction not indicated as 11open 11 and 11closed 11 in IST program 3/4-inch check valve, CRD, IST test mode did not indicate 11operation 11 3/4-inch air-operated gate valves, CRD, IST test mode did not indicate 11operation 11 3/4-inch air-operated gate valves, CRD, IST test mode did not indicate 11operation 11 3-inch motor-operated gate valve, LPCI,. IST program did not indicate valve category or test mode 20-inch air-operated butterfly valves, pressure suppression, IST program incorrectly indicated group 2 isolation 4-inch motor-operated gate valve, recirculation, IST program did not indicate test mode as 11 CS 11 1-inch air-operated globe valve, HPCI, IST program did not indicate normal position as 11open 11 16-inch check valve, HPCI, IST program did not indicate stroke direction as 11open 11 and 11closed 11 52 I*:.

Valve Number 3-203-lA,B,C,D A

Valve Size and/or Type,* Syst~m. Concern 20-inch air-operated globe Valves, main steam (MS),

• IST program did not i~dicate group 1 isolation 3-203-2A,B,C,D

. 3-2001-105 2-262-2-58 2-262-2-6.B 20-inch air-operated globe valves, MS, IST.program did not indicate group 1 isolation 3-inch air-operated gate valve, reactor building drains, IST program did not indicate group 2 isolation inch check valve, recirculatiorr, not listed in IST program 1-inch check valve, recirculation, not listed in IST

• program The team reviewed several requests for relief from ASME Section XI inservice testing requirements that the licensee had submitted to the NRC for approval.

The team discovered seven requests containing inaccurate information.

Relief requests VR-4, -5, -8, -13, -14, and -15 listed check valves that perform a containment isolation function and are located in various systems (such a3 neutron monitoring, pressure suppression, feedwater, core spray, LPCI, HPCI, recirculati6n, and standby liquid control).

The relief requests categorized the valves as 11 C, 11.which includes check valves as defined in ASME Section XI, Article IWV-2100(c).

However, since the valves also perform an isolation function, the valves should also have been designated as 11A 11 per Article IWV-2100(a).

11 A 11 valves require leak rate testing.

Relief request VR-9 addressed 10 motor-operated valves installed in the core spray, LPCI, and HPCI.systems.

Relief from IST requirements was based on the premise. that the valves were actuated only by a fl ow switch signal and that manual control was not possible; consequently, stroke testing had not been conducted for these valves.

The team discovered that remote operation was possible.

The licensee informed the NRC that the relief request would be withdrawn and that procedures would be revised to conduct the stroke testing

. required by ASME Section XI.

3.3.2 ASME Section XI Pump Testing The licensee did not have any administrative procedures in place to control Section XI pump testing and to ensure that all required testing was performed, evaluated, and trended.

During the evaluation, the licensee indicated that IST administrative procedures were being developed.

After the evaluation, addi-tional corrective action was proposed to improve the IST program so that it would be in compliance with ASME Section XI.

Test results were signed-off.as satisfactory even though test acceptance criteria were violated. It was not clear t6 the team wh~ther the corrective actions taken to correct test defi-ciencies were adequate because the documentation the team reviewed.was vague or otherwise inadequate.

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The team reviewed completed surveillance test procedures to determine if the data were acceptable and proper action was taken if test data failed to meet established criteria.

Instances were found where test acceptance criteria were not met, although the test was signed-off as acceptable.

Examples of this problem include those listed below.

(1) Test Procedure DOS 2300-6, 11Monthly HPCI System Pump Test for the IST

Program, 11 did not.establish t.he reactor pressure required for the test.

Section E of the procedure ( 1 i mi tat ion and actions) indicated th.at 11 to verify that the HPCI pump is operable... previous surveillances have shown that reactor pressure must be at least 950 psig.

11 For the Unit 3 test conducted on May 14, 1987, the test procedure was annotated to indicate that reactor pressure was increased to 931 psig to pass the test.

The same test performed on the same unit on June 11, 1987, was performed at a reactor pressure in excess of 1000 psig'.

ASME Section XI, Article IWP-3110, requires that reference values be established that can be duplicated during subsequent tests to determine the operational readiness of a pump.

It appeared_ that firm reference values did not exist for the HPCI pump in that reactor pressure could be varied as required to pass the test.

Vibration readings were erratic, although within acceptable limits.

Pump differential pressure was not a criterion for acceptability. The team could not determine if the HPCI pump fulfilled Surveillance Requirement 4.5.C.1 of the Technical Specifications, which states that the 11 HPCI pump (2)

. shall deliver at least 5000 GPM against a system head corresponding to a reactor vessel pressure of 1150 psig to 150 psig.

11 On the basis of the above test results, itwa~ doubtful that the technical specification requirement could be achieved at reactor pressures as low as 150 psig.

The team found that similar concerns exi~ted for the Unit 2 test.

Test Procedure DOS 1500-:10, 11Monthly LPCI System Pump Operability Test With Torus Available for the IST Program, 11 as performed on Unit 2, did not appear to adequately address those test results that did not meet the a*cceptance criteria.

For example, on June l, 1987, vibration levels for LPCI pump 2A were in the alert range, and the differential pressure was out of range for pumps 2C and 20.

The followup test that was performed on June 2, 1987, only recorded~ revised suction and discharge pressure for pumps 2C and 2D.

This test indicated that the differential pressure across pump 2C was acceptable; however, pump 2D was still unacceptable.

The test was next performed on June 30, 1987.

Vibration levels for pump 2A were still in the alert range, and the differential pressure was.

out of range for pumps 28 and 2D.

Shortly thereafter, the test was rerun with an *unknown valve lineup (valve alignment checklist was marked 11 N/A 11

)

with data recorded only for pumps 28 and 20.

The data indicated that the differential pressure across pumps 28 and 2D was now acceptable.

Deviation reports were never written to document the problems described above.

It was not apparent from available documentation what corrective action, if any, was scheduled, to resolve vibration problems with pump 2A.

Each test performed was signed-off as satisfactory, and the corrective action required by ASME Section XI, Article IWP-3230, was not accomplished.

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(3) Te_st Procedure DOS 6600-8, "Monthly D. G. Cooling Water Pump Test for the

!ST Program, 11 as performed on Units 2; 2/3, and 3, did not fulfill the requirements of ASME Section XI, Article IWP-3230 (Corrective Action).

The team reviewed the monthly tests for May, June, and July 1987.

Inade-quate corrective action was taken on the Unit 2 and 3 pumps to resolve erratic flow indication that persisted for over 3 months.

Deviation reports were not written to document the problem, testing was not increased, and corrective maintenanG~ or modifications had not been

• performed.

3.3.3 Plant Performance Monitoring/IST Section Staff The team evaluated the personnel in the Plant Performance Monitoring (PPM)/IST Section to determine their level of expertise and expectations.

Three impor-tant observations resulted:

(a) Dresden recently created a new PPM/IST Section to monitor and control surveillance testing activities; (b) background experience was low; a total of less than 19 staff years, despite the fact that -

the group consiste~ of five people including one supervisor; and (c) the PPM/IST Section was not aware of the types and extent of IST progrannnatic and implementation processes* that existed at other CECo nuclear sites.

The team noted that an excellent system was established to maintain survell-lance testing status; however, only_ one individual, the PPM/IST Surveillance -

Engineer, was*assigned to this task.

The PPM/IST supervisor was planning many improvements including the.development of administrative procedures to control IST, corrective actions and trending of ASME Section XI testing.

In this regard, the team believes that the lack of a cohesive IST program has contributed to the widespread concerns involving valve testing and programmatic issues, and in fact, it may be appropriate to perform a thorough review of the IST program to (1) assure the availability of adequate

!ST administrative procedures to provide control over required pump and valve testing, including corrective action requirements; (2) add pumps and valves

• that were erroneously omitted from the program; (3) correct information con-tained in the program; and (4) perform applicable tests to verify operational readiness of equipment and trend test data to ensure compliance with Section XI of the ASME Code.

Additionally, an associated concern raised by the team is the apparent failure of the QA audit process to discover the significant

• deficiencies associated with IST.

3.3.4 Interviews Interviews with the engineering professionals of the newly organized inservice test group revealed their commitment to an effective test program and a desire to contribute to safe plant operations in a meaningful way.

Most viewed the recent decontamination and cleanup efforts as actions that would *help restore lost pride in the Dresden plant and would generally improve morale.

However, they cons1dered that, at best, minimal improvements could be made _in the near future because of the many years of poor work practices.

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3.4 Operator Training

• 3.4.1 Training Staff

~

The licensee's Training Department personnel expressed concerns about the lack of plant experi~nce of the training staff and the inadequate staffing to support 5 days of nonlicensed operating personnel training during the 6-week shift rotation period.

__ Th,ese concerns seemed. to be the major causes of the poet-learning e~vironment in.classroom~ ~nd the lack of respect ~f some licensed operators toward the training staff. *The licensee told the team that it had already taken measures prior to the team visit that were expected to

• lessen or reduce the effect of the above inadequacies.

The team observed that presentation of training material to operators was often a.monotonous reading of lesson plans with little encouragement of student interaction.

The authorized staffing lev.el was 26 positions; 23 were filled.

Three of these positions had recently been filled.

• Two nuclear station operators (NSOs) had been transferred to the Training Department-on July 6, 1987, and were to assume duties in the initial operator licensing and retraining programs after comp_let-

. ing a 2-week instructor's course.

The other recent transfer was a former radiation-chemistry (RC) technician who was to be involved in support services training.

Of the three remaining authorized positions, two were about to be filled (one electrical and one RC) and the other was to be filled by either an operations or a maintenance staff member.

Ten of the 23 instructors had Dresden in-plant experience.

Nine of these instructors were assigned to operator training. Three-of these 9;, h~v.e Dresden experience (1 foreman, 2 NSOs) and the remaining 6 llacf;nuclear' experience in the military.

The licensee

. anticipated that this*addition of personnel with plant experience would round out the training staff and result in a better learning experience for oj:>~rators.

During its interviews with litensed personnel, the team found that one instruc-tor was repeatedly singled out as being a poor instructor.

The training supervisor indicated that steps had been taken to improve this individual's

. teaching techniques and the situation was still under review.

The Training Supervisor had been lead instructor of operations until he was

.promoted to his new position on June 8, 1987.. This change was made to provide

• new direction to the Training Department.

Although the Training Supervisor and amember of the staff had occasionally attended meetings such as the MidWest Nuclear Training Association Meeting, there was no involvement in industry-sponsored activities such as Institute of Nuclear Power Operations (INPO) peer visits.

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Because of inadequate staffing, both licensed and nonlicensed operators were in the same retraining classes.

During the interviews, the team was informed that.

half the material was presented at the licensed level and half at the nonlicensed level.

As a result, part of the time the licensed operators were instructed in material they already knew.

Similarly, the nonlicensed personnel were being presented material that was not appropriate and thus were bored.

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In ari attempt to improve the overall quality of retraining, management decided to provide separate training for licensed and nonlicensed operators.

However, staffing levels could only support 2 days of meaningful training every 6 weeks for the nonlicensed operators.

The remaining 3 days of each week might be dedicated to shift work or activities.

At the time of the evaluation, imple-mentation of the split training was to begin during the next 6~week cycle, that is~.the second week of September.

However, union concurrence was needed to implement this change.

~.

3.4.2 Regualification Program for Licensed Operators A confirmatory action letter (CAL) dated February 27; 1987, to the licensee from Region III stated that the Dresden requalification program for licensed operators was unsatisfactory and that mandatory training* should be conducted.

The team found it significant that although previous regulatory constraints had been removed and INPO guidance (86-026) had been issued, the Training Manager reported that the licensee did not have any immediate plans to revise the requalification program using a systematic approach to training to develop a performance-based program.

However, revisions to 10 CFR 55, effective May 25, 1987, had removed the constraints of 10 CFR 55, Appendix A, under which tbe NRC had approved the Dresden requalification program described in the "Commonwealth Edison Company Requalification Program for Licensed Operators, Senior Operators, and Senior Operators Limited" (February 10, 1986).

As a member of the National Academy for Nuclear Training, Dresden station would be expected to change from its Appendix A program to a program based on INPO 86~026 guidance.

Subsequently, CECo corporate management indicated that it planned to upgrade its program to meet INPO guidance.

The team observed that learning objectives, as distributed to the students, did not indicate the standard of performance expected of the learner; and the questions asked on the quizzes were too easy and poorly written.

License~

operators appeared-attentive, but non 1 i censed shift personnel appeared inattentive and undisciplined (i.e., they appeared to be sleeping).

The four instructors that the team observed did not encourage student interaction and wanted to adhere verbatim to prepared lesson material.

Another example of the poor level of instruction was the presentation on the Bailey feedwater controllers in which the instructor appeared not to have a lesson plan.

This training was being conducted as part of scheduled modification training during the normal requalification cycle.

The instructor brought a part task (partial) simulator of the controllers into the room; howe~er, no instructional materi~l was distributed, nor were specific activities planned for the students.

The team had previously questioned whether there would be training on the new controller.

The controller simulator presentation appeared to be a hastily arranged ad hoc event.

The instructors emphasized specific questions to be asked on the Qresden requalification examinations, as well as material from the January 1987 NRC requalification examination.

Questions by the students *concerning other material were treated as irrelevant.

Because of this type of teaching, the team believed that the conclusions drawn from the comprehensive requalification 57

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examinations might not be valid because they would not verify the competency _of the test taker but only his/her ability to answer specifically taught test questions.

The test should be a sample from which inference can be drawn about the total knowledge of the test taker.

One perceived weakness in the requalification program was the overall handling of student inquiries during training (OPP Form 115, Revision 3, January 1987).

Students expressed concern about the lack of response in this area.

• Because of this concern; the team reviewed training inquiries generated during 1984, 1985, and 1986.

A random sample indicated that only a small number of inquiries had not been addressed in the training material.

According to Training Department Policy 14, once training is complete, the inquiry is to be returned to the originator.

The lack of response on inquiries could not be substantiated.

One NSO who had submitted two inquiries indicated that he had received a response for one of them.

The long time to complete the cycle may be contributing to thii feeling of lack of re~ponse.

The team observed that the simulator training was adequate.

The instructor, a GE employee, provided good feedback to the trainees with respect to their performance during simulated emergency scenarios.*

• As a result of the upgrade program conducted in accordance with the CAL, the.

problem regarding the requalification of licensed operators at Dresden was being addressed.

However, the team observed that instruction was still poor and may have contributed to the unsatisfactory performance by licensed operators on the NRC requalification examinations administered during the week of January 26, 1987.

On the other* hand, the. team observed that the 4-day simulator upgrade course, developed in response to the NRC findings of January 1987, adequately emphasized team building, proper communication, use of procedures, board manipulations, and emergency operating procedures.

Observa-tions of control room activities revealed that communicat.ion-and the*use.of procedures, as presented in the simulator courses, were being implemented.

This was further supported by interviews with operations personne-1 who indicated that there had been an increased use of procedures and pre-briefings by the NSOs concerning compl~x iasks for the equipment operators.

Review of the simulator upgrade course critiques indicated an overwhelmingly positive response.

The Training Department was planning to add the upgrade training to the existing program by 1988.

The existing 4-day program will be expanded to provide 8 days of training at the simulator facility.

In addition, the Training Department was considering adding 2 more days to make a total of 10 days.

The additional 2 days would be used for training regarding normal operations of systems or normally experienced transients.

During the team interviews, two NSOs expressed the need for such training.

The team reviewed a sample of the retraining quizzes and three license examina~

tions.

The team's opinion was that these examinations relied too heavily on the memorization-of such items as set points, trip and initiation signals, definitions, and standardized bases and placed too little emphasis on indepth, job-required knowledge of system functions or interactions.

However, discus-sions with NSOs on the control board revealed that they had a generally ade-quate knowledge of plant design and operation, with one notable exception.

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of three operators questioned did not know that it was* important to have the

• cross-connect valves open between low-pressure cotilant injection loops.

The lead instructor of operations indicated that this had not been covered in the training material and that GE would evaluate the need for incorporating it into future lesson plans.

The team concluded that overall training was weak.

The requalification program

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- for 1 icensed operators was st i 11 unsatisfactory and represented the weakest

~

portion of the training program.

The team believed simulator training was adequate, although there were many differences between the Dresden station and the simulator at Morris.

The lack of emphasis on in-depth, job-required know-ledge of system functions or interaction was a major weakness and more student involvement in the classroom and separate learning activities for licensed and

.nonlicensed op~rators was needed to improve student attentiveness and discipline.

3.4.3 Simulator Facility Simulator trainin'g is provided under contract by GE at the Morris Operations Training Center.

As a result of the promulgation of the revisions to 10 CFR

. 55, "Operators 1 Licenses, 11 effective May 26, 1987, p 1 ans were in progress to purchase the simulator from GE by January l, 1990, and a number of simulator updates were scheduled for 1988 and 1989.

These included the relocation of anticipated transient without scram pushbuttons and the addition of individual rod indication on the full core display, video display system, and scram *vent and drain valve controls.

Items not* currently scheduled for upgrade included the new rod worth minimizer system, the computer digital displays, the modified standby liquid control system controls, and the new digital feedwater controls.

The.licensee was in the process of determining which nonscheduled items were to be added, and on what schedule~ At present, significant differences exist

.between the simulator and Dresden Unit 2 and it is not known whether th~

licensee will be able to certify the simulator facility in accordance with 10 CFR 55.45(b) by the required deadline of May 26, 1991.

3. 5 Quality Programs 3.5.1 Quality Assurance of Operations The Quality Assurance Department had a strong commitment to oversight of day-to-day plant operations. This included daily (including backshifts) observation and evaluation of control room activity and examination of logs, records, and other pertinent documents.. The technical credibility of this effort was strengthened by the fact that one QA auditor had a current senior reactor operator (SRO) license and that there were two others in licensed operator training.

However, the team was concerned that this dedication to operations oversight and training might result in insufficient staff to carry out the other duties of the QA Department.

With two auditors in operator training, two on back-shift coverage, and an average of two on off-site detail, there appeared to be insufficient staff to accomplish the traditional QA surveillance and audit

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functions, much 1 ess to cover new areas.such as station improvement programs and SSFI.

• In addition, there was a high turnover rate among QA staff; more than half had been at Dresden in QA for less than two years.

The team was conc~rned that this did not permit auditors sufficient time to learn the plant and its characteristics and also weakened the impact of QA findings in the Dresden environment where most operations and trade personnel had worked many years.

Interviews with the QA Supervisory and staff supported the observation

.. that the department was undermanned and limited by resources.

3.5.2 Licensee Improve~ent Initiatives During the team's evaluation, the licensee provided a list of 10 ongoing Dresden management improvement initiatives that had been developed to improve plant performance.* The team examined QA personnel involvement in station im-provement initiatives and the overall qual1ty of the initiatives.

On the basis of document review and interviews, the team discovered that there was no active

~r direct participation by the QA Department in the development of the station improvement initiatives.

The QA Supervisor revealed that there was no planned participation in these improvement initiatives other than routine audit and surveillance activities, which had not yet been defined or scheduled.

Ttie team

• interviews with QA staff members revealed that they had little specific knowl-edge of the nature and direction of the improvement initiatives, even though all agreed that plant appearance had improved considerably over the past year.

The team found that, although the individual improvement initiatives seemed to*

have been well conceived in most cases* there was no collective thrust or di-rection to the improvement ~ffort as a'whole.

The initiatives did little to enhance the material condition of plant hardware or to evaluate the functional c~pabilities of safety systems.

It appeared to the team that the initiatives.

d1d not represent. a major commitment of the.Commonwealth Edison Company (CECo) resources to Dresden station improvement~ The initiatives were recent in many

. cases and their long-term effect on safe operation could not be evaluated.

• ~I.

The team observed that the di~ection and control of the improvement initiatives seemed to be fragmented.

All were under the cognizance of the Station Manager; however, corrective actions and followup were not centrally tracked, *They had

• not been made part of the Dresden nuclear tracking system (NTS), which identi-fied and tracked external Dresden commitments.

It appeared that most of the i~itiatives were reactive; that is, they were prepared in response to insp~c t1ons or evaluations from the NRC or the Institute of Nuclear Power Operations (INPO).

No improvement initiatives had been designed to prevent possible future problems.

The _team found that not all the improvement initiatives were

• formally establishep, published, and promulgated.

For example, there was no document setting forth the purpose and administration of the personnel error reduction plan.

Team interviews revealed that most*plant personnel were not aware of the individual initiatives or the depth and extent of the improvement actions required at Dresden.

3.5.3 Safety System Functional Inspection (SSFI)

The QA Department, with the assistance of CECo engineers and contractors, completed a safety system funtional inspection (SSFI) of the Unit 3 diesel 60

generator (DG) in July 1987.. Since the licensee had not completed the SSFI report, the team reviewed the executive summary which had been published.

This showed that the Dresden SSFI team had conducted an in-depth, critical inspection that identified some significant safety concerns in the DG and anci 11 ary systems.. The licensee stated that corrective action.for SSFI defi-ciencies in the DG were in progress or had been completed.

The team observed that this was a licensee QA initiative that; if extended to other safety systems, could help provide assurance of the functional capabilities of other safety-related sys terns..

3.5.4 QA Involvement in SALP Response The team also observed another area where the QA Department 1s lack of involve-ment was evident--the area of the improvement activity outlined in the CECo response to the NRC report of the sixth Systematic Assessment of Licensee Performance (SALP).

In the SALP 6 CECo response to NRC Region III (l~tter from D. L. Farrar to A. 8. Davis, dated May 13, 1987), the licensee committed to perform many actions to improve station performance.

Among these, in Attach-

• ment A of the letter, were several actions specifically directed at the area of quality programs, including SSOMI followup, resolution of environmental qualification inspection deficiencies, assessment of the station modification program, and other actions to ensure quality and to exercise control of *c*.

day-to-day operations.

Team interviews with the Dresden QA Supervisor revealed that he was generally unaware of the quality program improvements addressed in_

the SALP 6 response and that there was no formal participatio~ by the QA staff.

Additionally, the team review of documents indicated that the response was forwarded to the corporate QAManager and the Dresden QA Supervisor on May 22, 1987, with the notation that 11 no specific action or response by Commonwealth Edison is required at this time.

11 It appeared that this lack of direction and.

emphasis in forwarding the document may have contributed to the lack of response by the QA Supervisor and staff.

3.5.5 Audit and Surveillance Program The-team reviewed QA Department audits and surveillances that had been conducted during 1986 and 1987 in the maintenance and inservice test (!ST)

• areas to determine why the issues uncovered by the team were not previously identified by the licensee.

The team concluded that QA reviews were extremely program-oriented in the maintenance area and concentrated on the correctness of documentation (such as maintenance work requests and modification packages) rather than emphasizing correct work activities and sound engineering practices.

As a consequence of the 1986 NRC SSOMI, Dresden management had recently identified the need for the greater emphasis on the !ST surveillances required by Technical Specifications and*ASME Section XI and had committed to a more defined and better controlled program by creating a new Plant Performance/IST group.

However, the team found that many problems identified by the SSOMI still existed because the !ST program had been deficient for many years.

The team believed that the QA audit process should have uncovered the IST problems.

The QA Department may need to revise its audit check lists to include a more comprehensive look at the !ST area.

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The team identified one example of a weak au~it in the measuring. and test equipment (M&TE) area.

Audit QAA 12-87-05 of the calibration of portable test and monitoring equipment was performed in February 1987.

The audit report did not reflect the fact that the Electrical Maintenance (EM) Department calibration record sheets were not being satisfactorily maintained.

The team found the electrical maintenance calibration record sheets in disarray and essentially not auditable.

Interviews with the QA auditor, who performed the Dresden audit, revealed that the electrical maintenance record sheets were in the same condition during *the February audit~ but the auditor did not consider

• the record problem serious enough to make it an audit finding or observation.

Th~ team found that because of the poor recordkeeping practices of electrical maintenance personnel, it was not possible to determine whether any defective or.uncalibrated electrical test equipment had been used for electrical ma1ntenance or surveillance activities.

3.5.6* Quality Control Department The team evaluated the program changes in the QC Department that resulted from

~he Safety Systems Outage Modification Inspection (SSOMI) performed by*the NRC in 1986.

The number of QC inspectors had increased from 6 to 10, and further personnel increases were planned with a projected total of 18.

A QC Supervisor with an extensive background in QC and nondestructive examination had been appointed recently.

He had reorganized the QC staff along functional lines to increase coverage in areas such as chemistry, operations, and radiation protection..

Interviews with QC inspectors indicated a professional demeanor and a strong, positive attitude toward safety.

QC personnel involvement in plant modifica-tion and maintenance activities had increased as a result of the Plant Modifi-cation Program, Dresden Administrative Procedure (OAP) 5-1, Revision 15~ May 1,

. 1987, and new QC checklists developed to correct deficiencies found during the 1986 SSOMI.

The team observed that QC hold points continued to be bypassed occasionally, although not. as frequently as in the past.

The team found that gc person~el, in an effort to improve the hold-point process, had become more involved 1n work package preparation and review.

3.5.7 Corrective Actions and Root Cause Analysis The Dresden Regulatory Assurance Department was charged with tracking commit-ments and corrective actions.

The department had recently been strengthened with the assignment of additional personnel and the appointment of a new super-visor.

Duties of the group included tracking external commitments to INPO, the NRC, and others.

Inspection report open items, responses to NRC bulletins, INPO action items, ~nd information letters on* the nuclear steam supply system were tracked in a newly developed automated system termed the nuclear tracking system (NTS).

The NTS also tracked some internal actions such as formal QA

• audit findings.

The team* found that the tracking system seemed satisfactory wit~ respect to external commitments, but there was a wide spectrum of internal actions that were not identified or tracked.

For example, the status and action required by discrepancy records (DRs) and de,viation reports (DVRs) were 62

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not identified and tracked in the NTS.

These were tracked manually by differ-ent plant personnel.

(In some cases, the team experienced difficulty in deter-.

mining the precise location and status of DVRs and DRs.) Another deficiency in the NTS was that the status of actions required by plant improvement initi-atives was not identified and tracked.

Corrective actions for such initiatives as scram reduction and personnel error reduction were not considered part of the NTS.

The fact that significant internal commitments and. actions were not identified and tracked i_n the NTS. was coris.id~red a, we_akness...

The team determined that root-cause analysis and followup were not accomplished as one coordinated, cohesive activity and did not constitute a separate, strong, plant-wide program.

Instead, root-cause determination depended on what level of report was ultimately generated and what specific initiative was involved.

There appeared to be no attempt to identify or track similar events and their fundamental causes on a plant-wide basis.

The team evaluated the root cause analysis aspect of the personnel error reduc-tfon plan, includin_g l2 events that resulted in deftcienc;y reports (-licensee event reports or similar reports) to determine the accuracy and effectiveness of root-cause identification and analysis.

The team's evaluation was based on the description of the event in the deficiency reports and the subsequent followup action.

The results of the evaluation were:

~~-

(1) The root cause for the personnel error was appropriately identified in two cases.

(2) In seven other events, the 'licensee's finding of personnel error as the root cause was rejected by the team as inaccurate.

Although personnel error was involved in most cases, the real reason for the error should have been i dent i fi ed as the root cause.

An examp 1 e was DVR 12-2-.87-30 in which personnel error was identified as the root cause; however, a lack of communication between operators was the fundamental problem.

An example of an event that was inadequately analyzed by the licensee was con-tained in DVR 12-2-87-49.

The licensee had determined that the root cause of this event was personnel error and placed a disciplinary letter in the file of the equipment operator i nvo 1 ved.

However, the fo Tl owup action to prevent recurrence was to rewrite the operating procedure involved.

The team could not reconcile the apparent contradiction between the personnel disciplinary action and the need to rewrite the operating procedure as corrective action.

3.6 Radiation-Chemistry 3.6.1 Radiation-Chemistry Organization and Staffing The team observed that; the overall attitude of RC personnel was positive and the staff wanted to continue improving the program; the corporate support personnel were cooperative and knowledgeable of plant needs; and the techni-cians' level of knowledge appeared adequate and should improve when the retraining program is in place.

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The team also observed that the*position of foreman was not properly utilized; for example, the backshift "desk-RC foreman" was performing many of the shift administrati.ve duties (e.g., telephone answering, equipment issuance). These duties occupied a la~ge portion of the.foreman's time and attention and made him desk~bound. The team noted that the RC Department had proposed to elimi-nate the 24-hour, 7-day coverage by foremen (starting with the elimination of weekend duty), thus freeing the foremen so that they cou.ld spend more time in

, planning job coverag~,: providing more**in-f.ie.ld support, and.directing ongoing job coverage by RC technicians.

This change also could have a positive spinoff effect by placing the technicians covering the backshift.in more responsible, decisionmaking positions, thereby -helping in their development.

The team also found that RC management staff should continue its efforts to improve communication with the technicians.

During interviews, the theme of poor communications persisted, as it had with other groups.

The performance evaluations of personnel just under way are a good first step in providing a

• two-way communication/feedback mechanism that should increase worker perform-ance and have a po~itive effect on attitude. Other managem~nt initiatives including 'the proposed 113-t'ier11 technician progression ladder and the spTit ot radiation and chemistry at the technician level should also be pursued.

The team observed that the staffing levels of health physicists, chemists, foremen, and technicians appeared to be adequate and that*the organizational structure was functional and should become more effective when planned changes are implemented.

Given the frequent turnover of RC supervisors, the team believes that a period of stability is needed for this position and that the administrative duties performed by*the backshift desk-RC foreman could best be delegated to the onshift technicians.

Continued plant management support for the identified improvement initiatives is necessary because this support is a critical factor in fostering and sustaining a successful RC progr-am.

3.6.2 Respiratory Protection Program The Respiratory Supervisor had recently attended a 1-week training course.spe-cific to applied respiratory protection at nuclear power plants--a course the licensee planned to offer at the Dresden site to improve the overall knowledge level of the RC staff._ Although relatively inexperienced [but working under a lead health physicist (HP) who had been qualified as a radiation protection manager], the Respiratory Supervisor had initiated several progrannatic improvements including discontinuing the use of half-face negative pressure respirators and bringing in powered-air-purifying respirators (which provide a high degree of protection) and encouraging their use.

Another ongoing improvement initiative included the purchase of a breathing air compressor for filling self-contained breathing apparatus air bottles on site.

Based on a review of implementing procedures and discussions with RC techni-cians and the RP supervisor, the acceptance criterion (fit factor of 50) for what constitutes an acceptable fit during quantitative respirator fit testing 64

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appeared too low.

Industry experts generally agree that a respirator that fits properly will provide a significantly higher fit factor.

The program for checking used respirator filters before they are.reused will be significantly improved when aerosol~penetrator leak checks of the filters are initiated at the station.

A concern focused on a recent RP program change that requires mandatory respiratory protection for workers when they enter work areas wher~ contamina-:

tion levels resulting from loose surface material* are greater than 50,000 disintegrations/minute/100 cm2.

Although the basic intent of the change is to reduce the intake of radioactive material by personnel, more operational flexi-bility and allowing (at the discretion of the RC foreman or qualified tech-nician) some relief may be appropriate for certain job activities. Strict adherence to the 50,000 criterion for all work activities may result in the unnecessary wearing of respirators (wearing respirators burdens workers and leads to less efficient and effective work practices and probably causes increased overall occupational risks).

Overall, the ~P program at Dresden seemed to provide adequate protection for the workers and that the ongoing and planned initiatives will improve the program.

The planned 1 week of commercial onsite training of RC personnel in respiratory protection is a very positive step to further upgrade the proQram.

3.6.3 Industrial Hygiene

~-:.

The team examined the controls for specific areas that are considered as being immediately dangerous to life and health (IDLH).

The team reviewed the indus-trial hygiene (IH) procedures and policy statements and the corporate IH.policy manual, interviewed the onsite IH advisor, toured the facility, discussed IDLH hazards of specific areas with general plant workers, *and reviewed a 1984 inci-dent and the resultant plant corrective actions.

The team observed that the onsite IH advisor was well-motivated and knowledgeable and had received recent formal IH training.

The licensee had an effective asbestos controls program that identified and quantified the hazard (original steam piping insulation was a source of airborne asbestos).

As evidenced by the onsite support given during the recent Unit 3 feedwater transient (which caused widespread piping vibrations and resultant potential asbestos airborne problems), the corporate supportof IH activities seemed positive and effective.

A confined-space entry procedure that when implemented would formalize pre-entry and surveillance requirements governing work in potentially hazardous spaces was undergoing onsite review.

The team noted that there was no formal mechanism to track and ensure that recommendations/corrective actions resulting from the investigation of acci-dents or negative findings in the IH area were effectively implemented.

For example, in 1984 during the routine fi 11 i ng of the Unit 1 Cardox storage tank

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(which supplies carbon dioxide for the plant's five suppression.systems), a plant equipment attendant assisting in the fill operations lost ~onsciousness when carbon dioxide was inadvertently released.

The plant safety committee made several hardware and administrative recommendations for corrective actions to prevent a recurrence.

According to the IH advisor, the recommended hardware fixes were never accomplished.

However, as a result of the accident, the site administrative procedure governing carbon dioxide filling operations (DAP-4001-1; 198-5) was modified, but the procedure contained no worker guid-

.. ance, hazards warnings, or precautions to be taken during the operation.

Overall, the team believed that the IH program provided adequate protection for workers but could be improved by a formalized mechanism to ensure corrective actions are taken when programmatic deficiencies are identified.

The team also believed that personnel need to become aware of regulatory and industry docu-ments discussing industrial nonradiological hazards [e.g., Institute of Nuclear Power Operations (INPO) and NRC generic notices].

3;6.4 Radiation-Chemistry Training Programs The team observed that the instructors conducted themselves as qualified.pro-fessionals and their lesson plans were of high quality.

The addition of two field-experienced RC technicians to the staff of instructors will provide more "plant, hands-on" experience to the program.

Ongoing development of 11 hot-particle11 training for the technicians will better prepare them to deal with

• Dresden's hot-parti~le problems.

The team found s.everal consistent, negative comments in the written course.

evaluations by the students; all of these comments focused on one instructor's poor attitude, demeanor and preparation. Discussions with the RC instructors group leader indicated that proper management action had been taken to correct the problem.

The team's review of the students' written course-evaluations/critiques of the training during ~ 4-month period showed that the response from the students was fair to poor.

An active, formal interface between the trainer and the trainee is vital to the success of any training program--student feedback and proper instructor response are crucial ingredients that must be maintained.

The team found that the systems lesson plans for the RC technician retraining program were well written and focused on the specific aspects and hazards of each system.

However, the team observed that the systems lesson plans in the course book used for the initial training of RC technicians failed to capture this important focus on the specific radiological aspects and hazards of each system.

Overall,. the team believed that the onsite RC technician training program (which is accredited by INPO) was of good quality and that the nuclear-general employee training (N-GET) program (general employee training according to 10 CFR 19) was adequate.

The effective integration of experienced RC technicians into the training staff should be a positive force in improving the RC training programs.

The team also believed -that:

(a) the RC foreman/retraining program 66

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should be fully implemented; (b) "general awareness" hot-particle training should be added to the N-GET program and the ongoing training programs for crafts personnel; (c) the importance of keeping the quality of student critiques high should be emphasized; and (d) the systems lesson plans used in the initial training of RC technicians should be improved so that they are of the same quality as those used in the retraining of the technicians.

3.6:5 Control of High-Radiation Areas The team found that the licensee had recently implemented improved controls over locked high-radiation areas by adding administrative and physical controls (which require a special key) over areas. where whole-body dose rates greater than 15 R/hr are possible.

Special authorization was required for work in a*

high-radiation area where dose rates are greater than 3 R/hr at 1 foot.

The team found that Dresden Radiological Procedure (DRP) 1610-5, "Radiological Protection Procedure for Reactor Feedwater Sparger-Related Maintenance," had been formally ~le.teLI b_y the licensee because the li.cens.ee had no future..plans for work in this area. This procedure contained pertinent radiological con-trols governing work inside the reactor vessel.

The DRP also.contained lessons learned from the 1981 radiation overexposure of a workman (21.2 rem whole-body dose), which was caused by an undetected loss of reactor water level compounded by a lack of proper radiological controls~

Overall, the team believed that the. licensee's control program for high-radiation areas was adequate and had been significaritly strengthened by the addition of administrative and physical controls.

However, as was discussed in a Region III routine inspection report (50-237/87021), and further discussed during this evaluation, the licensee should consider incorporating the routinely practiced speci a 1 dry-we 11 access and shi e 1 ding controls i.nto plant procedures to prevent personnel overexposures during spent fuel movements.

3.6.6 Review of Industry Operating Experiences Reports The *team reviewed the administrative procedures and the plant actions in response to selected information notices and INPO safety evaluation reports and significant operating event reports, interviewed the lead engineer (regulatory assurance) associated with the review of industry operating experiences reports (OPEXs) that are related to health physics, and discussed the effect of the OPEX program on the RC department.

The team found that the OPEX program had improved since 1986 as a result of a program modification.

The licensee had previously recognized that more direct involvement, review, and oversight by appropriate technical specialty groups *

(e.g., r_adiation chemistry) were needed and agr~ed to formalize this ongoing improvement initiative by revising the governing OPEX procedure to reflect the current technical review process.

The team noted several excellent responses by regulatory assurance personnel to various OPEXs.

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Overall, the team believes:

(a) that the administrative system for reviewing O~EXs was adequate for ensuring 1 es sons learned from industry ev.ents are properly identified and translated into corrective actions; (b) the system is currently in transition, and once the modifications are fully implemented, the program should improve; and (c) adequate resources should be available to reasonably expedite the transfer of OPEXs from the technical staff to the regulatory assurance group (including the backlog of OPEXs assigned to the

... tec_hnical_ staff).

3.6.7 Chemistry Although the team did not examine this area in depth, the team did review procedures and recent NRC inspection reports, performed a broad survey of program performance, and held discussions with the lead chemist who was highly_

. motivated and actively involved in improving the program.

Based on this information, the plant chemistry program seems to be an industry leader.

3. 6. 8 ALARA Program The team did not critically examine the ALARA dose reduction program.

However, the evaluator did discuss the program and planned improvements with the ALARA coordinator*(ex-maintenance foreman} who was trying to integrate the ALARA concept and philosophy into the craft work program.

Overall, the team believes that plant management should continue to support the RC department's integration efforts so that the ALARA concept is implemented station-wide arid is considered in the planning and practice of every crafts project.

3.7 Management Overview 3.7.1 Strategic Plan (5-Year) and Station Goals The CECo Strategic (5-Year) Plan for Excellence. in Nuclear Operations dated July 27, 1987, provided information-for the evaluation of corporate management commitment and involvement at the Dresden Station. This plan contained 12 objectives pertaining to safety and 6 pertajning to human resources.

Four of the human resource objectives were directly related to safety.

The more significant aspects of this plan were:

a cormnitment that all CECo nuclear power stations, including Dresden, achieve an average SALP rating of 1.5 by 1990 a conunitment to establish an* objective pertaining to safety system unavailability (the guidelines from the Institute of Nuclear Power Operation (INPO) for this objective are expected in 1988) an objective (added in 1987) to achieve a level of excellence in the.

performance of maintenance activities two objectives pertaining to cost-effectiveness 68

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.,l maintain total operations and maintenance expenses (taking into account inflation) equal to or less than the levels budgeted for 1985 through 1988 limit additional investment costs to the funding of projects mandated by regu 1 at ion or projects* with over a 11 payback periods of 1 ess than or equal to corporate guidelines (This objective was modified by addition of the statement that.investments-to meet the goal of excellence may be approved outside the current corporate guidelines.)

The Strategic Plan required that the objectives be implemented by one or more station goals for each objective.

The team reviewed the Dresden Station Goals an~ found several discrepancies:

Not all.Strategic Plan objectives were reflected in the Station Goals.

For example, the team found no goals to implement objectives A.4, 11Timely re so 1.ut ion of the recommendations from the manager of nuclear safety 11 and Al2 11Achieve a level of excellence in t.he performance.of maintertance.

11 Some station goals addressed an objective, but were at variance with,the objective.

For example, the station goals for objective A.2.a, 11 NRC:

Regulatory Performance, 11 exceeded the numbers of sanction *points and "LE Rs per unit a 11 owed in the Corporate Strategic Pl an.

The goals did not address all -0f the improvement initiatives, and seemingly were not coordinated with these initiat.ives.

For example, ah initiative on maintenance assessment was not addressed in the safety goals.

In addition, initiatives on the error free operation plan and personnel error reduction plan did not appear to be coordinated with each other or with the station goal for zero personnel errors (objective A.Lb).

The Strategic Plan and the Station Goals generally reflected a significant management commitment and involvement in the Dresden station.

Progress toward achieving these station goals was reviewed semiannually by corporate management (Vice President) with ~he Station Manager at the pJant site~

The team was concerned that the cost-effectiveness objectives indicated there was no real corporate commitment to excellence.

Subsequently, at a meeting with corporate and Dresden management, the team learned that CEC0 1s Chief Executive Officer shared the team's reaction, but emphasized that CECo management was in fact committed to providing the necessary resources to Dresden.

CECo planned to revise the Strategic Plan to reflect this commitment.

Notwithstanding the above, the team remained concerned about the overall level of resources available for management and technical support at the Dresden station. Dresden management and the technical staff were overextended because of ongoing efforts to correct performance problems, and the additional level of attention required to sustain an improving trend in performance.

In addition, because the NRC and INPO had reacted negatively to Dresden's performance, 69

additional resources had been required.

For example, additional efforts were.

necessary to respond both to an NRC augumented inspection team (AIT) sent to Dresden in response to a main feedwater transient a week before the arrival of the team at the site, and to a confirmatory action letter from Region III regarding the number of personnel who had failed the operator requalification examination.

Several re~ent management changes, expected to have long-term benefit, had a short~term disruptive impact on these managers and their staffs.

Further, the team observed_ that the Assistant Superintendent of Operations did not have his own staff to assist in managing routine day-to-day activities; only a normal staff of line personnel was available.

The maintenance manager also had too few maintenance engineers on his staff to assist in developing and implementing a maintenance program.

In addition, the Station Manager did not have. a staff ~edicated to the various improvement initiatives. All of these factors contr*i buted to the team 1 s concern regarding resources.

When *the excessive operator overtime occurred during the second week of the evaluation, station management was apparently too overextended to recognize and respond to the situation.

This event served to substantiate the team's concern

-addressed above.

3.7.2 Improvement Initiatives CECo and Dresden management generated most of the present improvement initiatives follo~ing an INPO evaluation in 1985. - However, since that time, there had been a number of NRC actions which had resulted in incfeased demands on CECo; These included: (a) Region Ill's confirmatory action letter of February 27, 1987, fo 11 owing the NRC requa l ifi cat ion examinations; (b) Region III Master Inspection Plan for Dresden, and (c) an NRC safety systems outage modifications inspection (SSOMI) team report *iisued in 1986.

These actions had resulted in a need for*new and expanded improvement initiatives by CECo.

The team evaluated the Dresden improvement initiatives from the perspective of management involvement and the effects of these initiatives.

Several initiatives (e.g., the area decontamination program) had resulted in a significant short-term improvement in a particular aspect of plant performance.

Although the initiatives were reactive to external (NRC and industry) evaluations of CECo and Dresden, Dresden management supported the need for these improvement initiatives.

Although CECo management was significantly involved in these initiatives, they shared some of the team's concerns regarding shortcomings in these initiatives.

Improvement initiatives included error free operation, personnel error reduction, outside cleanup, personnel contamination reduction, shipping error reduction, high radiation area control, and assessment program~ for maintenance and chemistry.

The assessment programs were INPO assisted and had not been initiated when the team was on site.

The assessment program for maintenance was only recently initiated.

70

• Notwithstanding the above, the team had the following ~ajor concerns regarding the improvement initiatives:

These initiatives were not integrated into the CECo Strategic Plan and the Dresden Station Goals and appeared to be an uncoordinated effort.

Additionally, there was no formal tracking system for monitoring the actual improvements achieved as a result of the Strategic Plan and the

. Station Goals.

Onsite and corporate quality assurance (QA) personnel were not involved in the impro~ement initiatives. Further, the root cause analysis pertaining to the personnel error reduction in~tiatives often cited personnel error as the root cause when in fact the personnel error was a reflection of a root cause.

The purpose and objectives of most of these.initiatives had not been ade-quately communicated to nonsupervisory personnel.

As a result, many of these personnel were skeptical about the lastin_g effects of these initia-tives and the commitment of management to implement them. *This skepticism did not extend to the outside cleanup initiative and parts of the personnel contamination reduction initiative. This latter initiative included a decontamination of various areas in the plant, which resulted in a reduction of the contaminated plant area from more than 65,000 square feet to about 9,000 square feet in the last year.

The team found that the painting program *was not identified as an improvement initiative, but rather was included in the Dresden Station Goals.

This program appeared successful ahd had resulted in a cleaner and safer working environment.

It also received many favorable conunents from plant personnel, who believed that it had contrib~ted significantly to improved moral~.

Many of the initiatives were relatively new, and it was too soon to tell what the long-term effects would be.

This was a concern because the,team noted that previous improvement programs did not achieve long-term results.

The initiatives did not address all areas requiring improvement.

Addi-tional improvement initiatives and programs were needed in the areas of maintenance, inservice testing, operator training, and organizational communication.

Although communication was weak across all the functional areas, there were several management initiatives to improve communication,.

such as:

quarterly awareness/expectation sessions; weekly departmental "tailgate" sessions; walkthroughs before complex operational events; briefings by Assistant Superintendent Operations during operator training; and daily station one-page flyer.

In addition to the above improvement initiatives, the team observed that.other initiatives (e.g., changes in key personnel in the last year) had contributed to overall station improvement.

The personnel changes included new personnel in the following positions:

Station Manager, Quality C<;>ntrol (QC).Supervisor, Assistant Superintendent for Maintenance, Master Mechanic, Master Instrument 71

Mechanic, Master Electrician, Assistant Superintendent for Operations, Training Manager, and Radiation Chemistry Supervisor.

New positions for.an additional operating engineer and an INPO Coordinator were established.

A new safety system functional inspection (SSFI) program had been initiated at CECo stations.

An SSFI of the No.. 3 emergency diesel generator was recently completed by the QA department at Dresden.

This SSFI appeared to be comprehen-

.. sive, and several.safety concerns. ~ere. identified.

CECo reporied plans to evaluate the results of one or two SSFis at each station before. proceeding.

further with this program.

The licensee had recently initiated a weekly and a monthly reporting system for various performance indicators, including some improvement initiatives. These reports were seen as a positive indication of improvement in management 1s con-trol and involvement.. Interviews with the Station Manager.indicated that he was very familiar with the information in these reports.

However, there were indications of a lack of followup.

For example, these reports showed an iru:reasing amount of operator overtime that was* also above the bud9eted amount.

to l1 owup o*f these monthly reports could have made* management aware of the excessive operator overtime.

3.7.3 Meetings and Interviews 3,7.3.1 Corporate Management During meetings, with corporate officials, a very positive, safety-conscious, and'professional attitude was projected, as well as a genuine dedication to improving the performance of Dresden.

A major CECo reorganization in June 1987 was described as intended to provide better corporate support to the operating plants. This reorganization placed CEC0 1s pressurized-water reactors (PWRs) and BWRs under separate vice presidents reporting to the Senior Vice.President.

The overall knowledge and understanding of CECo senior management was evident as they de*scri bed the other improvements either in p 1 ace or p 1 anned for Dre~den. It was also apparent that the General Manager was spending a large percentage of time at Dresden and was actively involved with the improvement programs.

However, it was equally apparent that other corporate managers having program* responsibility, e.g., maintenance, testing, QA, were not actively involved to the same degree in Dresden's activiti*s or improvement programs.

The team was sensitive to the fact that the attitude voiced by management might be skewed because of the onsite presence of the team.

The team, therefore, considered both it's observations of management actions and the results of meetings and interviews in it's evaluation of attitude.

The team concluded that the various improvement initiatives were an indication of management's positive attitude, although improvement initiatives were recent and the long-term effects were not yet apparent.

On the basis of these meetings, a review of the improvement initiatives, dis-cussions with NRC Region III personnel, and a review of relevant CECo corre-spondence to the NRC (such as responses to SALP and SSOMI reports), the team 72

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concluded that for the most part, CECo managemeht had an improved, positive attitude.

• 3.7.3.2 Plant Management The Team Manager and Team Leadei met daily with the Station Manager and members of his staff.

These meetings allowed the team to understand some of the causes of past problems, and to evaluate the reactive posture and response of management to safety and performance issues.

Duririgthese meetings, the Station Manager projected a positive attitude and was well informed and very involved in the operation of the station.

For instance, the team found that the Station Manager conducted quarterly se~sions with the entire station as a mechanism for communicating to the staff.

The senior staff and key managers in the Production and Services Departments were interviewed.

The objective of the interviews was to provide the team with insight into management 1 s attitude toward safety, involvement in plant opera-tions, and commitment to the improvement initiatives.

The team asked standard*

and specific questions that were appropriate for the particular manager 1s posi-tion.

The team 1 s conclusions as a result of these interviews are summarized below:

Management involvement in plant operations appeared limited in certain areas.

Management seemed reluctant to take forceful, positive action with regard to the composition of shift personnel and to the distribution of o~ertime hours among shift workers.

Managers were acutely aware of the deficiencies at Dresden and of the need for rapid, directed improvement.

The managers considered that a good start in implementing the necessary improvements had been made.

Managers believed that little had been done to change attitudes at Dresden or to establish new programs to meet the increased r~gulatory requirements in the post-TM! era.

They also believed that insufficient emphasis was placed on writing and revising procedures, maintaining safety-related systems, or providing complete and accurate documentation for plant modifications and equipment maintenance actions.

It was also noted that plant management was exposed to broad changes in the industry only through some outside influence such as a transfer to corporate offices or protracted involvement with INPO.

Managers were convinced that the plant was being operated safely, but admitted to difficulties in certain areas caused by a lack of financial and human resources and the union agreement.

Managers were cognizant of the corporate and plant goals outlined in the Strategic Plan; the most common goal cited was that of achieving an overall SALP rating of 1.5 by 1990.

Managers appeared to agre~ with problems identified by the team such as problems with communication, a poor interaction between operations and maintenance personnel, and weak plant management in the past.

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The team believed that Dresden~s management had a positive attitude toward

• safety, but were overextended and limited in resources.

The team conducted 84 interviews at the first-line supervisor level and below to evaluate the attitude toward safety exhibited by the workers the perceived effectiyeness and imp~ct of plant-wide improvement programs management.involvement in plant operations Standard interview questions and an evaluation format to be used by all inter-viewers were established during team meetings before the evaluation. *During the evaluation, interviewers were free to ask followup questions to ensure that they understood the responses. *In addition to the standard questions, each interviewer prepared and used a set of questions specific to the functional area..

The fo 11 owing fi rst-1 ine supervisor and wor.ki ng 1eve1 personnef were interviewed:

licensed and nonlicensed operating staff; electrical, mechanical, and instrument control maintenance.technicians; radiological control technicians; surveillance and inservice test technicians and engineers; and quality assurance (QA) and quality control (QC) inspectors and auditors.

The team's observations based oh these intervi~ws were as follows:

Most workers were aware that improvement initiatives existed, but they were not aware of specifics and most workers also were aware that there had been considerable activity-before the recent INPO and NRC evaluations, but there had been little change in their assigned areas or job duties.

(Exceptions ~ere the decontamination ~nd cleanup programs.)

Most workers had a positive attitude, but the interviews revealed low morale; poor communication; lack of feedback from mariagement; frustration with qua'lification and requalificat.ion training; and a depairing attitude toward discipline, performance evaluation, educational opportunity, and promotion potential.

Personnel expressed a commitment to the safe operation of the Dresden plant, but the negative factors summarized above may have detracted from stable and safe performance at the working level._

During interviews, maintenance supervisors and workers generally cited the same problems and expressed the same frustration as did the operations staff, such as inadequate communication between management and the nonsupervisory staff, incomplete work planning, and the increased workload brought on by INPO and NRC activities.

As positive factors, most pointed to improvements in morale because of the cleanup p~ogram and the recent changes in supervisors. _ Inter-views also revealed that there was no excessive friction between maintenance workers and operators.

Tbe general attitude of maintenance wo~kers _and super-visors seemed positive and safety oriented.

Interviews with the engineering professionals of the newly organized inservice test group revealed their commitment to an effective test program and a desire 74

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to.contribute to site plant operations in a meaningful way.

Most viewed the recent decontamination and cleanup efforts as actions that would help restore lost pride in the Dresden plant and would generally improve morale~ However, they considered that, at best, minimal improvements could be made in the near future because of the many years of poor work practices.

Although bargaining unit employees made evident their strong loyalties to the union and their crafts, this did not seem to have a negative effect on their attitude toward safety.

Additionally, many personnel commented that communi-cation at the plant was improving, such as use of management staff 11tailgate 11 meetings held Monday at 12:30 p.m. following the 10:30 a.m. management meeting.

The traditional safety instruction tailgate session for craftworkers was expanded to include management communication concerning procedures, station goals, improvement initiatives, and INPO and NRC visits.

However, the team observed that the tailgate meetings of approximately 30 to 40 craft workers.did not have the right environment for eliciting meaningful comments from many of the workers.

The team also noted that no performance appraisal system existed and in fact there was no formal process to assess the performance of plant workers, with the exception of the Radiation-Chemistry Department appraisal system which had

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just begun.

The management appraisal system was begun only in.May 1987 as a CECo initiative.

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4.0 EXIT MEETING The Director of AEOD, Region III Administrator, team Manager, team Leader, and other NRC pe*rsonne l met with CE Co and Dresden management officials at the CE Co offices on September 23, 1987, to brief them on the results of the Dresden diagnostic evaluation.

The list of attendees is given at the end of this section.

• The briefing which consisted of the teanis preliminary findings and conclusions

• was led by E. Jordan, Director, AEOD.

A copy of the briefing notes used during*

the meeting is included as Appendix A to the report.

The CECo response at the exit meeting, which was very receptive and positive, reinforced.the team's preliminary findings and conclusions regarding upper 11ana_gement' s attitude, involvement, and commitment.

C. Reed, Senior Vice-President, CECo, led the CECo response.. He_ acknowledged and accepted the NRC's findings, conclusions, and root causes and stated that he wanted to assure V. Stello, the Executive Director for Operations"(EDO),

that CECo is committed to putting resources in place to achieve the goal of excellence at Dresden and at the other CECo facilities.

It.was agreed that a meeting would be set up between Mr. Reed and Mr. Stello.

Mr. Reed was surprised by the team findings with regard to the operator requalification training program.

D. Galle, Vice President-BWR Operations, commented that CECo was put:ting changes in place to meet the 1986 INPO guidelines.

This was contrary to what the team had been to*ld*at.Dresden.

The team concluded that this corporate initiative had not yet ~een communicated to Dresden management.

Mr. Reed atkhowledged.,:that resource limitatfons have pl~ye~_ a part in Dresden's cond.ition and past performance.

However, he reported th:~t.the Ore.s.d~n 1987 budget expenditures w.ill exceed the guidelines of the CECo Strat5!giq P.l.an.

According to Mr. Reed, many of the team's preliminary findings were parallel to INPO findings, and this served to emphasize the urgency of augmenting the Dresden organization with additional staff.

He then went on to highlight the following recent INPO corporate assessment results.

CECo was urged to look at how other nuclear utilities conduct business as a way to reduce a parochial perspective at CECo.

There are plans for corporate/station managers to visit other utilities in response to this INPO assessment.

Outside management development was recommended.

The strategic plan is good, but lacks accountability.

• Management is ineffective in communicating objectives and expectations to the lower levels of personnel.

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Mr. Reed then committed to provide the INPO corporate.assessment results for

. Dresden, Zion, and CECo to the ~RC when CECo makes a final decision on how it will respond to the results.

At the conclusion of the meeting, Mr~ Reed indicated that CECo intended to re-

• spond formally to the NRC and to address actions to be taken as a result of the team (and INPO) findings.

INPO and CECo teams were performing a maintenance assessment at the time of.the exit meeting.. CECo is committed to determine root causes of problems and to develop appropriate corrective actions.

Maintenance programs from other nuclear utilities will be studied for possible improvements to be made by CECo..

CECo wants to make a "step change" to address equipment/material problems at Dresden.

An aggressive plan that includes the following actions is already under way.

Additional personnel with systems expertise (6-10 people) were to be hired by the end of October 1987.

A new position will be created to oversee an integrated improvement pro-gram.

The person filling this position will report directly to the Station Manager, will have a staff of 15 to 20 people, and will interact with the line organizations implementing the improvement initiatives.

A n~w lnservice Testing (IST) Manager at Dresden will be hired from out-side CECo.

An upgraded motor-operated valve preventive maintenance program.will be expedited.

A technical specification review and improvement program will be initiated.

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ATTENDEES

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Dresden Diagnostic Evaluation Meeting - September 23, 1987 Name NRC H. Bailey R. w. Cooper, II A. B. Davis

w. L. Forney M. Grotenhuis E. Jordan H. J. Miller

c. E. Norel ius M. A. Ring

l. Spessard CE Co J. s. Abel J. D. Brunner L. 0. Del George E. D. Eenigenburg D. Gal le N. F. Kalivianakis

c. Reed R. w. Stobert M. S.

T~rbak G. P. Wagner Organization Office for Analysis and Evaluation of Operational Data (AEOD)

Office of the Deputy Director for Regional Operations Region III, Regional Administrator Region III~ Projects Branch 1, Chief Office of Nuclear Reactor Regulation, Project Manager (Dresden)

AEOD, Director Region Ill, Division of Reactor Safety, Director Reg.ion II I, Divis iOn of Reactor Projects (DRP), Direc.tor Region Ill, DRP, Dresden Section Chief AEOD BWR Engineering Manager Assistant Suprintendent-Technical Services (Dresden)

Assistant Vice President-Licensing and Plant Support

• Services Station Manager.(Dresden)

Vice President~-BwR Operations General Manager Senior Vice President Director of Quality Assurance (Operations)

Licensing Assistant Manager Production Services Manager 78

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DRESDEN DIAGNOSTIC FINDINGS DRESDEN PERFORMANCE SLOWLY IMPROVING I

I IMPROVEMENT PROGRAMS BEGINNING TO WORK I

I ATTITUDE OF STAFF IMPROVING IMPROVEMENT IN PERFORMANCE' MAY BE SHORT-TERM

,

• DRESDEN PERFORMANCE HISTORY HAS BEEN CYCLIC I

I SAFETY SYSTEM FUNCTIONALITY CONCERNS I

I IMPROVEMENT PROGRAMS INCOMPLETE I

I RESOURCES LIMITED

.!i;-

APPENDIX A

UfROVEtQT PROGIW§ BEGJNllll& TO MORK WIDE SPECTIUt OF PERSOllE. CHMGES AND CORPORATE OFFICE SHIFTS PAINT-UP FIX-UP PROGRAMS U1PROVIN6 APPEARANCE AND MORALE DRAMTIC REDUCTIONS IN*CONTAMINATED AREAS REDUCTIONS IN PERSONNEL CONTAMINATIONS

.

• IMPROVED fl>D IF I CAT I ON PROGRAPt REDUCTION IN PERSONNEL ERRORS

---**--*~

• • M***-****-***--*

,~

'

• I:'.

ATTITUDE OF STAFF IMPROVING PLANT MANAGEMENT ATTITUDES POSITIVE CORPORATE ATTITUDES SHOW IMPROVEMENT PLANT NONSUPERVISORY PERSONNEL ATTITUDE MIXED.

..;1,: *

(*_

. ~....

CORPORATE/DRESDEN ORGANIZATIONAL CHANGES

. NEW POSITION OF VICE PRESIDENT BWR'S I

NEW PLANT MANAGER NEW ASSISTANT SUPERINTENDENT MAINTENANCE ADDITIONAL OPERATING ENGINEER I

NEW MASTER MECHAN I c I MASTER INSTRUMENT ME CHAN I c I.. MASTER ELECTR I c I AN

, ASSISTANT SUPERINTENDENT OPERATIONS AND ASSISTANT SUPERINTENDENT WORK PLANNING ROTATED *

• NEW TRAINING MANAGER

• INPO COORDINATOR POSITION CREATED

, TECHNICAL STAFF REORGANIZATION

~'.

LIST OF IMPROVEMENT PROGRAMS I

ERROR FREE OPERATION PLAN PERSONNEL ERROR REDUCTION PLAN

. OUTSIDE CLEANUP ACTION PLAN PERSONNEL CONTAMINATION REDUCTION ACTION PLAN REDUCE SHIPPING ERRORS MAINTENANCE ASSESSMENT CINPO ASSISTED>

"CHEMISTRY ASSESSMENT SSFl/SSFT

<NO. 3 EDG>

. NEW MANAGEMENT TRENDING TOOLS.

,

• WEEKLY REPORT <SCRAMS, ERRORS, DEVIATION REPORTS, CONTAMINATIONS>

I I

MONTHLY PLANT STATUS REPORT

~*..

l.',

• DRESDEN CYCLIC PERFORMANCE SALP FUNCTIONAL SALP SALP SALP

• sALP SALP AREA

~ -2....

_4

_L

• __2_

PLANT OPERATIONS 2

2 2

2 3

• • • e RADIOLOGICAL CONTROLS 2

2 3

• 2 3

MAINTENANCE 2

2 3

3 2

SURVEILLANCE 2

2 1

2 2

FIRE PROTECTION/HOUSEKEEPING 3*

2 2

2 3

EMERGENCY PREPAREDNESS.*

2 1

1 2

1 SECURITY 2

2 2

1 1

OUTAGE 2

1 1

1 1

e QUALITY PROGRAM AND 3

2 2

2 ADMINISTRATIVE CONTROLS LICENSING ACTIVITIES 1

1 2

1 1

• ,:**j "..

~

(

SAFETY SYSTEM FUNCTIONALITY CONCERNS EXAMPLES

• HPCI - AUXILIARY OIL PUMP, MOVSJ ROOM COOLER ISOLATION CONDENSER - SPURIOUS ISOLATIONS

. MOV'S - RESPONSE TO IEB 85-03J LUBRICATION

• BOP INTERACTIONS --MFW REG VALVES <WITH PIPING FAILURES>

CAUSES NEGLECT.OF SYSTEMS <POOR MAINTENANCE>

AGING - WEAK PROGRAM TO ADDRESS I

POOR SURVEILLANCE - POOR IST>PROGRAM I

FAILURE TRENDING WEAK.

ROOT CAUSE ANALYSIS WEAK

'I:.... *,'.:.

~J e.*

IMPROVEMENT PROGRAMS INCOMPLETE MAINTENANCE PROGRAM WEAK

. * *VALVE OPERATOR PROGRAM POOR

.. PREVENTIVE MAINTENANCE PROGRAM INCOMPLETE

• INSERVICE TESTING PROGRAM WEAK

• CORPORATE OVERVIEW.. - DEFICIENT I

PLANT IMPLEMENTATION *- POOR COMMUNICATIONS WEAK

,, BETWEEN SUPERVISION AND STAFF I

ACROSS ORGANIZATION

.. OPERATOR TRAINING PROGRAM WEAK I

I INADEQUATE INSTRUCTOR STAFFING

• INSTRUCTORS LACK PLANT EXPERIENCE

... *\\ :

~.

. ~*.....

( :

MOTOR OPERATED VALVES I

I LUBRICATION MAINTENANCE PROGRAM WEAK I

I TORQUE AND LIMIT SWITCHES CORRECTIVE MAINTENAN.CE I

I HPCI ROOM COOLER, AUXILIARY OIL PUMP, VALVE I

I PINION GEAR INSTALLATION, IN 85-22.

I I

PINION GEAR SET SCREWS I

I FEEDWATER REGULATING VALVES PROCEDURES I

I EQ SURVEILLANCE

~

I MOV BACKSEATING TRENDING I

I TRENDED ONLY BY SPECIFIC EQUIPMENT, NOT BY EQUIPMENT TYPE OR:

MODEL I

I LUBRICATION AND OIL ANALYSIS MEASURING AND TEST EQUIPMENT I

I RECORDS WERE CONSIDERED UNAUDITABLE

'~'.

I

e.

.*e*

.*\\...

• INSERVICE_TESTING eROGRAM WEAK

• LACK OF PROCEDURES.FOR ADMINISTRATIVE CONTROL

. VALVES LISTED IN 10-YEAR IST PROGRAM NOT ACTUALLY TESTED HPCI VALVE STROKE TIMING TESTED IN WRONG DIRECTION

• INCONSISTENCIES BETWEEN TECHN.ICAL SPECIFICATIONS, IST PROGRAM, AND ASME SECTION XI TESTING

. MODIFICATIONS TO SAFETY SYSTEMS NOT REFLECTED IN IST PROGRAM

• IST PROGRAM CONTAINED INCORRECT CRITICAL VALVE PARAMETERS

• ASME SECTION XI PUMP TEST RESULTS SIGNED OFF AS SATISFACTORY EVEN THOUGH TEST CRITERIA WERE VIOLATED

• INADEQUATE CORRECTIVE ACTION TAKEN TO RESOLVE E~RATIC FLOW INDICATION ON EDG COOLING WATER PUMP

~

• • e' *'

-)

(

I*

i*

COMMUNICATIONS POOR MANAGEMENT-TO-NONSUPERVISORY COMMUNICATION

.

• STAFF SKEPTICAL OF IMPROVEMENT PLANS

• OPERATIONS BELIEVES THEY WERE NOT CONSULTED OR ADVISED ON CONTROL ROOM AND EQUIPMENT CHANGES

• NONSUPERVISORY-TO-MANAGEMENT COMMUNICATION

• NO PROVISION FOR OBTAINING/ASSESSING CONE-ON-ONE> INDIVIDUAL NONSUPERVISORY FEEDBACK.

• PROCEDURE/TRAINING INQUIRIES APPEAR TO BE LOST MANY TIMES CNO FEEDBACK>

• TAILGATE MEETINGS ARE NOT SEEN BY PERSONNEL AS PROPER FORUM FOR MANY INDIVIDUAL/PERSONAL VIEWS

. HORIZONTAL COMMUNICATIONS

• SHIFT ENGINEER LEARNS OF PLAN*s TO START PLANT UP FROM LOAD DISPATCHER

• MAINTENANCE WORKING ON CRITICAL EQUIPMENT AND CONTROL ROOM PERSONNEL UNAWARE

'I.

• r. *.

OPERATOR TRAINING PROGRAM WEAK

• INADEQUATE STAFFING FOR FULL WEEK OF TRAINING OF NONLICENSED OPERATORS.

INSTRUCTORS LACK PLANT EXPERIENCE.

CAUSES LACK OF RESPECT FROM OPERATORS

. LICENSED AND NONLICENSED OPERATORS IN SAME.CLASS INSTRUCTORS APPEAR TO BE UNDULY STRESSING PREVIOUS REQUALIFICATION EXAMINATION QUESTIONS LACK OF INTERACTION WITH STUDENTS

,. EXAMINATIONS DO NOT APPEAR TO TEST INDEPTH ~OWLEDGE.OF SYSTEMS FUNCTIONS OR SYSTEMS INTERACTIONS

..... ~

• ~.*.

~*

... :;.*. (

. ~* :

'I

BE$QIRW LlftlTED INCOMPLETE PROGRAMS.MAY BE ATTRIBUTED TO LIMITED RESOURCES COST EFFECTIVENESS OBJECTIVES

• MAINTAIN TOTAL O&M~ 1985

• , LIMIT INVESTMENT COSTS TO REGULATORY MANDATED PROJECTS.

INVESTPIENTS TO MEET EXCELLENCE GOAL MAY BE APPROVED OUTSIDE OF GUIDELINES.

'*.).*.*

.. ~

ROOT CAUSE

. DRESDEN NEGLECTED IN FAVOR O~ NEW PLANTS

• • TIGHT FISCAL.PROGRAMS

• DRESDEN STAFF MAINTAINED A FOSSIL PLANT ATIITUDE I

INITIAL ATIITUDE,, LOW.TURNOVER

• OVERCONFIDENCE BASED ON EXPERIENCE, SIZE OF UTILITY

• LACK OF RECRUITMENT OF OUTSIDE NUCLEAR EXPERTISE ABOVE ENTRY LEVEL

• PREVIOUS IMPROVEMENT PROGRAMS FRAGMENTED I

LIMITED SCOPE, NOT LONG-TERM

-~

~

. iJ

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• L,\\**. *

~...

. ~<.

--~

.... :..c

"";16:-.:;:.

~ >1

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RECOMMENDATION REQUEST LICENSEE SUBMIT INTEGRATED IMPROVEMENT PROGRAM WITH SCHEDULES, GOALS, OBJECTIVES,, ACTION PLANS WITH MILESTONES, TRACKING/ASSESSMENT METHODS, ETC.

PROGRAMS WOULD INCLUDE:

EXISTING PROGRAMS VERIFICATION OF SYSTEM FUNCTIONALITY

. IMPROVED MA I NTENANCE I MP ROVED I ST..

• IMPROVED COMMUNICATIONS IMPROVED TRAINING PROGRAM

• COMMITMENT OF RESOURCES

• .a I*.'

I.

MEM)RANDllt FOR:

Edward L. Jordan, Dtrector Offtce for Analysts and Evaluatton of Operatfonal Data FROM:

Victor Stello. Jr.

Executive Director for Optrattons.

SUBJECT:

DIAGNOSTIC EVALUATION OF DRESDEN IULW POWEi STATION aY thfS mUM>randlll you art directed to conduct

• diagnostic evaluation of-the Dresden Nuclear Power Station. Support for the dtagnosttc evaluation teu will be provided as necessary by NRR and the regional offtces.

I (

As you know. Dresden was one of the fact11ttes discussed durfng the NRC senior

.anagers 11eeting held June 2-3, 1987 in Region IV.

Fro11 these dtscussions, which *addressed the regulatory and operational perforunce history of Dresden, ft became apparent that additional fnforution would be needed to uke an adequately fnfor9ed decision regarding the overall perfonaanct of*the Dresden plant. I have detenained that a diagnostic evaluation of Dresden h the *st effective *ans of obtaining this inforaation. The evaluation should place special emphasis on assessing:.

o The attitude towards safety and the professfonalf sa of the operating staff. including the decorum of the operators fn the control rooa.

o The degree to which aanagement ts involved in plant ~rational activities and ts able to positively influence the quality of those activities.

• o The attitude toward safety and professfonalfS11 *exhfbited by 1afotenance and radiological controls* technicians-.

You shou1d*schedule the diagnostic evaluation to ensure that the evaluation report is COllpleted before the next. NRC senior managers aeetfng (scheduled 10/87). I would like to be inforMd of your specific plans regardf ng schedule, teu composftfon. and evaluation *thodology when t.hiy are completed.

cc:

A. B. Davf 1 1 NRC/RIII E. L. Jordan. NRC/AEOD J. M. Taylor, NRC/EDO T. E. Murley, NRC/NRR Or111nal Slped IJa.

James If. T1yto; Viet.or Stello, Jr.

Executive Direct.or for Operations Appendix B

.. 1;0,..

• .. ~..

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