ML20098B001
| ML20098B001 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 09/02/1994 |
| From: | NEBRASKA PUBLIC POWER DISTRICT |
| To: | |
| Shared Package | |
| ML20094C015 | List: |
| References | |
| FOIA-95-262 NUDOCS 9510020025 | |
| Download: ML20098B001 (100) | |
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NEBRASKA PUBLIC POWER DISTRICT COOPER NUCLEAR STATION + DIAGNOSTIC SELF ASSESSMENT TEAM P.O. Box 98 + Brownville, Nebraska 68321 I
September 2,1994 1
Mr. Ronald W. Watkins, President and Chief Executive Officer Nebraska Public Power District P O. Box 499 Columbus, Nebraska 68601
Dear Mr. Watkins:
This letter forwards the Diagnostic Self Assessment Team (DSAT) report of the Nebraska Public Power District's (NPPD) Cooper Nuclear Station (CNS) assessment. This self assessment was conducted at your direction and that of the District's senior nuclear officer, Mr. Guy R. Horn, vice president -
nuclear. The team members observed activities and reviewed records at CNS and the NPPD general office from July 25 through August 19,1994.
The observations were discussed with your staff throughout the assessment period. Concerns were discussed with you and a formal exit meeting with your staff was held on August 19,1994.
In commissioning this team your goal was to obtain an independent review of the operation of CNS and to determine the root cause(s) for the station's declining performance. The si(teen-member team was drawn from nine nuclear utilities, the Institute of Nuclear Power Operations (INPO) and nuclear field consultants. The team possesses over 250 years of experience in the design, operation, maintenance and performance 4
evaluation of nuclear facilities. Some team members have had recent experience at facilities where declining performance problems have been and are being addressed.
The team reviewed performance in the four broad areas of operations and training, maintenance and testing, engineering and technical support and, management and organization. A combination of station practices and procedures, federal regulation, INPO performance criteria, and experience are the basis for the team's observations. Concerns, observations and issues contained in this report represent a team consensus with regard to the nature and extent of the problem. Since this team is not a regulatory authority and is acting on your behalf, issues of a federal, state, or local regulatory nature must be considered by you.
i 9510020025 950905 PDR FOIA PATTERS 95--262.PDR i
R.W. Watkins September 2,1994 Page 2 A number of significant observations were developed by the DSAT. The 1
team found weaknesses in several areas that prevented the plant from
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reaching high standards of performance. The significant items are listed below:
i Corporate and station management have not established or o
encouraged high standards for personnel and unit performance.
Complacency and a philosophy of "do business the way it has always i
been done," contribute to the station's inability to keep pace with'the nuclear industry's rising standards of excellence. Furthermore, a lack of self-critical review and weakness in the assessment of station and industry events has prevented the station from learning from their experience and that of the industry, Weaknesses in long-range planning and scheduling have contributed e
to the station's inability to address long-term problems and implement long range improvements. Current programs and management controls have not required or encouraged the use strategic or tactical J
planning.
Non-routine activities are frequently planned orally and
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initiated without the benefit of a thorough plan.
Independent oversight has been ineffective in that many of the current e
performance problems at the station were not recognized and corrected. Quality assurance audits, surveillance, and evaluations are generally compliance oriented and do not effectively assess performance beyond regulation.
The SRAB and SORC have failed to aggressively challenge o
performance weaknesses when they are identified. These organizations are ineffective in raising problems and concerns to the appropriate managers for resolution.
Several issues identified by the team have the potential to reduce the e
margin of safety in important plant systems. These issues include:
inappropriately preconditioning systems prior to performance testing, uncertainties in the control of plant status, ineffective corrective actions, and weaknesses in configuration and plant design basis
- control, in evaluating the performance of CNS, every effort was made to be as complete and accurate as possible in describing the problem areas. These
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R.W. Watkins September 2,1994 Page 3 t
4 areas are representative of operations at CNS and should be combined with the results of other inspections, evaluations, and reports to develop a complete listing of all activities and programs requiring improvement.
During the period of this evaluation, the DSAT noted actions being taken by the station and corporate staff to address issues identified by the CNS staff,.
NRC, and this team. Recent changes in site management have introduced a i
heightened awareness of nuclear safety. New management has established a higher standard of performance for the CNS staff and clearly demonstrated the fact that the station will be accountable for adherence to these standards. Changes in programs dealing with surveillance testing, corrective action, work control and industrial safety are being implemented.
The fact that you have taken a more aggressive approach to problem identification and subjected yourself and your staff to this independent self assessment is a major and creditable first step. It will, however, only result in improved station performance if similar aggressive actions are taken in addressing the root causes identified in this report. While there is no regulatory or contractual requirement for you to respond to this report, I request that you provide me with a copy of your plans to address the root causes described in Section 3 of the attached report. I suggest that you provide the Institute of Nuclear Power Operations with a copy of this report and a copy of your corrective action plans when they are developed. The j
lessons learned at CNS will be of value to the nuclear industry in improving the level of nuclear performance.
The cooperation of your staff in identifying problem areas and the determination to improve performance expressed by many of the CNS staff is encouraging.
i Sincerely, Ralph E. Beedle DSA Team Manager i
cc:
G.R. Horn J.H. Mueller d'
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COOPER NUCLEAR STATION DIAGNOSTIC SELF ASSESSMENT CONTENTS PAGE EX EC UTIV E S U M M A RY................................... i 1.0 I N TR O D U CTI O N...................................
1
1.1 BACKGROUND
1 1.2 O B J E CT I V E S................................
2 1.3 SCOPE....................................
2 1.4 M ETH O D O LO G Y..............................
3 1.5 FACILITY DESCRIPTION 4
1.6 O RG A N IZ ATI O N..............................
4 2.0 EVALU ATI O N RES U LTS.............................
4 2.1 OPERATIONS AND TRAINING 4
2.1.1 Plant Status Control is Not Rigorously Maintained..
5 2.1.2 Compliance to Standards and Procedures is Frequently Not Conservative.................
8 2.1.3 Training is Not Effectively Used to improve Performance
..........................10 2.1.4 Degraded Material Condition and Long-Term Problems Have Potential to Affect Plant Operation.. 12 2.2 MAINTENANCE AND TESTING...................
15 2.2.1 Work Control is Fragmented and Lacks Coordination...........................
15 2.2.2 Weaknesses in the Conduct of Maintenance...... 18 2.2.3 Deficiencies in Procedure and Instruction Content j
a n d U se..............................
2 2 2.2.4 Weaknesses in Industrial Safety Practices 24 2.3 ENGINEERING AND TECHNICAL SUPPORT..........
25 2.3.1 Design Control is insufficient to Maintain Design I n te g ri ty..............................
2 6 2.3.2 Control of Station Configuration is Not Effectively M aintain ed............................
2 8 2.3.3 Corrective Action Program is Not Effective in Correcting or Preventing Problems............
30 2.3.4 Some Equipment Testing and Maintenance Programs Are Deficient....................
35 2.3.5 Ineffective Engineering Support of Station O p e ra ti o n.............................
3 8 2.4 MANAGEMENT AND ORGANIZATION..............
40 6
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i Cooper Nuclear Station Diagnostic Self Assessment 2.4.1 Impact of Management and Organizational Culture on Performance.........................
40 2.4.2 Ineffective Corporate Leadership and Support 42 2.4.3 Weaknesses in Self Assessment
.............44 2.4.4 Ineffective Independent Oversight 45 2.4.5 Ineffective Management Systems 48 2.4.6 Inadequate Use of Standard Human Resource C o n c e p ts.............................
4 9 2.4.7 Ineffective Planning and Prioritization..........
50 2.4.8 Potentially Degraded Safety System Capability 52 2.4.9 Additional Observations...................
56 3.0 RO OT C AU S ES..................................
58 3.1 Senior management has been ineffective in establishing a corporate culture that encourages the highest standards of safe nuclear plant operation.
..................58 3.2 Senior Management did not establish the vision supported by adequate direction and performance standards to improve station performance............
59 3.3 Inoffective monitoring and lack of critical self assessment have prevented management from recognizing program and process deficiencies and making the necessary improvements.
.............................60 3.4 An ineffective management development program has resulted in a lack of management and leadership skills necessary to ensure that strong leaders and managers are available to fill key corporate and station positions......
61 4.0 EXIT M E ETIN G....................................
6 2 APPENDICES Appendix A - DSA Team Appendix B - NPPD/CNS Organization Appendix C - Exit Presentation Appendix D - Abbreviations
COOPER NUCLEAR STATION DIAGNOSTIC SELF ASSESSMENT EXECUTIVE
SUMMARY
From July 25 - August 19,1994, Cooper Nuclear Station conducted a Diagnostic Self Assessment (DSA) to assess the station's performance. The objectives of the DSA were to identify areas requiring improvement and to determine the root causes for the station's declining performance. The assessment was initiated by the President and Vice President, Nuclear of the Nebraska Public Power District. The team, led by an experienced former nuclear utility senior executive, consisted of 14 technical evaluators and an administrative assistant. Areas assessed included operations and training, maintenance and testing, engineering and technical support, and management and organization. The facility was shutdown throughout the self assessment.
Overall, the team found weaknesses in many areas that prevented the plant from achieving high standards of performance. Corporate and station management have not establisbod or encouraged rising standards for personnel and station performance. Complacency, and a philosophy to "do business the way it has always been done," contributed to the station's inability to keep pace with the nuclear industry's rising standards of excellence. Furthermore, a lack of self critical review and weaknesses in the assessment of station and industry experiences has prevented the station from learning valuable lessons that could have corrected many station performance issues. Severalissues identified by the team have the potential to reduce the margin of safety in important plant systems. These issues include: inappropriate preconditioning of systems prior to performance testing, uncertainties in the control of plant status, ineffective corrective actions, and weaknesses in configuration and plant design basis control.
The team found weaknesses in the implementation of many of the administrative programs and processes that support the operation of the station. Weaknesses were attributed to a lack of guidance from management in the form of clear expectations and standards for performance. Adherence to procedure and program requirements was weak.
Frequently, when interpretation of a procedure or requirement was necessary, the interpretation was not conser' 'ive with respect to plant safety. There is a tendency to make dec:...., to expedite the completion of work rather than to conform to high performance standards. Weaknesses in the implementation of the clearance order and valve line-up programs have i
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4 Cooper Nuclear Station i
Diagnostic Self Assessment 4
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resulted in occurrences where equipment and components were not in the condition intended or maintained under the positive control of the control j
room staff.
i In the area of maintenance and testing, the team identified weaknesses in j
the control end performance of maintenance activities. Inadequate planning i
of maintenance has resulted in excessive out-of-service time. Emergency diesel generator and high pressure coolant injection out-of-service time has i
increased over the past three years due, in part, to poor coordination of maintenance and testing activities. Weakness in the quality of maintenance j
has resulted in degraded and nonconforming plant equipment. Verifications to ensure quality of repairs to equipment important to nuclear safety are not j
consistently made during maintenance activities. Specific problems found in j
i the application of quality control to maintenance activities include: lack of foreign material exclusion and cleanliness control, use of improper materials, and lack of fastener torque requirements. A lack of a conrdinated work I
control process has contributed to additional equinment outage time, 4:
increased outage risk, lost maintenance production hours, an increase in the backlog of maintenance, and over-reliance on the operations shift supervisor to coordinate maintenance on a daily basis.
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The team determined that corporate and system engineering support of plant operations was deficient in several areas. The lack of well-defined roles and responsibilities of the two organizations, as well as interfaces between them, has resulted in inefficient use of engineering resources. Design basis information is not readily available to station engineers. Control of design 1
activities is not sufficient to ensure the station's design basis is maintained and that analyses are based on correct design basis information. Some 4
design changes and other station modifications had not been reviewed for design configuration prior to Installation. Additionally, many system engineers are unfamiliar with the information that comprises the plant design basis. For example, due to a lack of understanding of the relationship among plant technical specifications, the Updated Safety Analysis Report, l
and the design basis, a test engineer specified incorrect limiting stroke times
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for motor-operated valves in the RHR system. Inadequate training on design and licensing basis information provided to the system and corporate engineers contributed to their lack of understanding of these issues.
I The team identified several weaknesses in the station's corrective action program. Many events or adverse conditions at the station result from i
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i Cooper Nuclear Station Diagnostic Self Assessment failed or absent barriers that could have been provided through implementation of lessons learned from in-house and industry operating experience. Corrective actions sometimes do not adequately address the root cause. Technical evaluations of industry operating experience are often untimely, narrowly focused, or inappropriately conclude that an industry problem is unlikely to occur at the Cooper Station.
In the area of management and organization, the team identified significant weaknesses in many areas of the organization. Weak or uninvolved corporate leadership did not assist the station in areas where their expertise could have been beneficial. Corporate management has not insisted that the management practices in place support high quality operation. For example, the station does not have a strong self assessment culture. Independent oversight is similarly deficient in that most of the current performance problems at the station were not recognized and corrected. Quality assurance audits, surveillance, and evaluations are generally compliance oriented and do not effectively assess performance. The SRAB and SORC have failed to aggressively challenge performance weaknesses when identified. These organizations are ineffective in raising problems and concerns to the hppropriate managers for resolution.
4 Weaknesses in long range planning have contributed to the station's inability to address long-term problems and implement long-range improvements.
Current programs and management controls do not require or encourage the use of strategic or tactical planning. Non-routine activities are frequently planned orally and initiated without the benefit of a thorough plan.
The team determined the following root causes of the station's performance problems:
management's ineffectiveness in establishing a corporate culture that o
encourages the highest standards of safe nuclear plant operation failure of management to establish the vision supported by adequate e
direction and performance standards to improve station performance failure of management to establish effective monitoring and failure to e
direct critical self assessment activities that recogrize program and process deficiencies and identify necessary improvements lii
Cooper Nuclear Station Diagnostic Self Assessment management's failure to develop corporate and station personnel with e
the management and leadership skills necessary to ensure that strong leaders and managers are available to fill key corporate and station positions The team noted corporate and station management have taken action to address some of the issues identified in this report. Examples include:
recent changes in site management have introduced heightened o
expectations and standards of performance improvements have been made to the corrective action program to e
better identify plant problems use of specialinstructions to perform safety related work has been e
reduced tighter controls on implementation of clearance orders e
preliminary development of long range business plans and schedules e
Continued management involvement is needed to maintain the momentum for change that currently exists.
4 Iv
COOPER NUCLEAR STATION DIAGNOSTIC SELF ASSESSMENT
1.0 INTRODUCTION
1.1 BACKGROUND
Prior to 1992, performance at Cooper Nuclear Station was generally considered satisfactory and consistent with industry standards. The station's scram rate was low and few significant events were reported. Few performance problems at the station were identified by outside agencies in 1991. Early in 1992 an Institute of Nuclear Power Operations (INPO) evaluation noted weaknesses in the communication and implementation of management expectations and management awareness of performance. The Systematic Assessment of Licensee Performance (SALP) review iden1Kied declining performance in plant operations and radiation protection.
Weaknesses were also identified in the analysis and assessment of plant conditions.
In late 1992 and early 1993, several occurrences led to increased NRC scrutiny of the station. A temporary startup strainer was found in a reactor building closed cooling water pump. Although the station had previously evaluated the systems, in response to NRC Information Notice 85-86, and determined them to be free of strainers, additional strainers were found in safety systems by NRC inspectors. It was also discovered that the test method used to determine operability of the secondary containment did not insure operability under various plant conditions. The test had been used to verify operability for several years. Concerns were raised by the NRC concerning the effectiveness of the station's corrective action program after similar problems were noted to be recurring at the station.
Several key issues were identified in the 1993 SALP that indicated declining performance. These included: failure to aggressively pursue root causes of potentially significant equipment problems, a willingness to live with problems, a weak problem resolution and corrective action program and a lack of sensitivity to potentially degraded plant conditions. Similar problems were identified during other NRC inspections. Twenty-seven NRC violations were issued in 1993 compared to ten in 1992 and four in 1991. The station was assessed two civil penalties, totaling $400,000 in 1993, for issues related to the suction strainers and weaknesses in problem identification and resolution.
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Cooper Nuclear Station Diagnostic Self Assessment The station issued the CNS Near Term Integrated Enhancement Program document in early 1994 to focus management attention on issues that are important to improve overall performance in the near term. However, instances of inadequate problem identification and resolution, weaknesses in surveillance test performance, and events affecting safety equipment performance have continued to occur. Preconditioning of equipment and systems to optimal condition to increase the probability of passing the surveillance test, was also noted by the NRC. The station entered an unscheduled outage, in May 1994, to correct emergency diesel generator load shed deficiencies and resolve logic system test issues. Additional concerns have contributed to the length of the outage including untested containment isolation valves, untested actuation relays and programmatic issues. Plant restart has been further delayed pending resolution of NRC confirmatory action letter issues.
In June 1994, the Nebraska Public Power District met with the NRC to discuss the station's declining overall performance. During the meeting, the NRC indicated its intention to perform a Diagnostic Evaluation to better assess the station's safety performance. NPPD management, recognizing the need to enhance performance, initiated plans to conduct this Diagnostic Self Assessment (DSA) of the Cooper Nuclear Station. The DSA is intended to identify areas requiring improvements. Continuing discussions with NRC management indicates that the results of the DSA may be used by the Commission in their assessment of the station.
1.2 OBJECTIVES The objective of the Diagnostic Self Assessment was to conduct an in-depth independent assessment of the performance of the Cooper Nuclear Station.
4 1.3 SCOPE The DSA assessed performance in the areas of operations and training, maintenance and testing, engineering and technical support, and management and organization. The assessment included specific emphacis on assessment of CNS's performance history. The results of past NRC diagnostic evaluations and experience gained from other industry initiatives was used as a basis for the evaluation. Some of the significant problem 2
Cooper Nuclear Station Diagnostic Self Assessment areas identified from these activities that were included in the scope of the DSA are:
management's offectiveness in resolving underlying root causes and achieving improvement in overall organizational performance effectiveness of site and corporate management leadership effectiveness of the QA organization effectiveness of line organization performance (self) assessment activities ability and capacity of the organization to simultaneously support normal operations, deal with extraordinary plant problems, and respond to significant regulatory initiatives management tolerance of inadequate organizational performance management tolerance of equipment problems effectiveness of management processes and work control processes effectiveness and technical adequacy of engineering support understanding of the facility design basis and adequacy of conformance 1.4 METHODOLOGY The DSA team used performance based evaluation techniques to assess both past and present NPPD performance. Most of the team members are INPO trained peer evaluators and several team members are former NRC inspectors and managers who have experience in application of safety-oriented, performance based assessments.
Appendix A provides a listing of the DSA team membership. The DSA also utilized the guidance from the NRC Diagnostic Evaluation Program Directives and Handbook in conducting the assessment.
The team's selection of specific issues and evaluation subjects was guided by its review of the plant history, including CNS performance information l
collected or developed by INPO. The team also included the information provided via NRC DET " requests for information" in their review. The DSA team reviewed plant event and problem histories, directly observed NPPD's handling of contemporary issues, evaluated plant and corporate NRC-licensed programs and their implementation, and conducted a vertical slice audit of one important safety system.
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Cooper Nuclear Station Diagnostic Self Assessment The DSA applied multi-level evaluation methodology used by the NRC in its performance of diagnostic evaluations. Level 1 of the evaluation focused on plant safety performance with respect to personnel, equipment and procedures. Level 2 of the evaluation concentrated on program adequacy and performance. Activities at Level 3 developed an understanding of offectiveness of management in directing the plant's activities and in responding to the problems identified in Levels 1 and 2. The DSA used the information developed in the Level 1-3 activities to identify root causes for significant verified problems identified at those levels.
1.5 FACILITY DESCRIPTION The Nebraska Public Power District Cooper Nuclear Station, a 778-MWe (net) General Electric boiling water reactor, is located on the Missouri River south of Brownville, Nebraska. Commercial operations began in July 1974.
The station was shut down throughout the assessment.
1.6 ORGANIZATION The NPPD organization for support of the Cooper Nuclear Station consists of General Office and Station components of the Nuclear Power Group. The head of the Nuclear Power Group is the chief nuclear officer, titled vice president - nuclear. A chart of the organization is provided in Appendix B.
2.0 EVALUATION RESULTS 2.1 OPERATIONS AND TRAINING The team found weaknesses in the implementation of many of the administrative programs and processes that support the operation of the station. Ineffective support programs have hindered the operator's ability to control and maintain systems and equipment in a manner that contributes to safe and efficient operation. In addition, oversight and control of shift routines and activities does not ensure the control room staff is fully aware of and in control of activities that may affect plant status and operation.
Many of the weaknesses are attributed to a lack of guidance from line 4
Cooper Nuclear Station Diagnostic Self Assessment management in the form of clear expectations and standards for performance. Management frequently failed to recognize program and personnel performance deficiencies. For those deficiencies that were identified, they failed to aggressively pursue the determination of root causes and corrective actions. Training was also not effectively used to provide the technical and professional skills necessary to enhance personnel performance in several key functional areas.
Positive observations included the station's aggressive cleanup effort to minimize contaminated areas in the plant. Areas of surface contamination have been significantly reduced in recent years resulting in ease of access for operation and maintenance in most areas. Operations and Training Department teamwork was noted in activities supporting control room simulator fidelity thereby ensuring operator training is realistic and relevant to plant operation. Improvements in operational communications to enhanco shift watch standing effectiveness were also observed.
The team observed operations and training performance during an extended outage period. The areas observed included management planning and direction, implementation of management expectations through observation of on-shift activities and variou program activities, equipment condition and control, and effectiveness of internal assessments. Support of operations by various site and corporate groups, including training, was also reviewed. A substantial number of interviews and document reviews were conducted.
In addition, informal discussions, plant walkdowns, and control room observations were used by the team to evaluate operations performance.
2.1.1 Plant Status Controlis Not Rigorously Maintained Administrative programs and processes intended to maintain plant status control are sometimes inadequate to insure that system alignments and clearance boundaries are known and controlled by the control room staff.
Weaknesses in the implementation of these programs and processes have resulted in clearance order violations, valves and other components being j
found out of position, and inadequate control of work boundaries.
Operation's ownership of the plant status control responsibility was not sufficient to ensure rigorous compliance to program standards. Additionally, the administrative programs for the control of seal wired valves and independent verification need strengthening.
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1 Cooper Nuclear Station Diagnostic Self Assessment i
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I (1)
Some aspects of implementation of the clearance order procedure deviate from good industry practices for control of tagged equipment.
Some of these practices reduce the ability of the control room staff to J
control the status of plant equipment and to remain cognizant of j
system status and availability. Other clearance order practices can j
desensitize operators and technicians to the importance of tagging requirements resulting in equipment damage or personnelinjury.
Additionally, some clearance order procedure requirements were bypassed through use of other processes. For examp~le:
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CNS Procedure 0.9, " Clearance Orders and Caution Tag Orders," states that it applies to all equipment and work conducted at the station. However, work on safety systems is i
frequently performed using special instructions (SI) that establish work boundaries and isolation requirements.
Frequently, these instructions do not use clearance orders and tags for equipment or personnel safety. Using SI work steps, instead of a clearance order, removes an important tool the
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shift supervisor has to monitor and control the condition of a system or component. A prerequisite for the shift supervisor to release a clearance order is the verification that the system is ready for service. Use of an Si removes this control from the shift supervisor.
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Until recently, test valves for local leak rate tests (LLRTs) were i
danger tagged as "no position." These danger-tagged valves l
were manipulated during performance of LLRTs with the danger tags still attached. This practice was used to shorten the time to complete the test and minimize the need for operator involvement. This practice is not consistent with the clearance order procedure or standard industry practice and is being j
eliminated.
CNS Procedure 0.9 permits the control room operator to designate persons other than operators to implement a clearance order. Operators interviewed by the DSA team related occurrences when this has happened. This practice is 1
not consistent with standard industry practice and is under review by operations management.
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Cooper Nuclear Station Diagnostic Self Assessment Operators sometimes do not have the clearance order sheet e
specifying components to be tagged in hand while hanging and removing danger tags. This practice increases the likelihood for tagging the wrong component or removing the wrong danger tag.
(2)
There is inadequate guidance on implementation of the valve line-up
. program. Action required for valves found out of the position specified on the valve line-up sheet, criteria for performing line-up checks after maintenance or outages, and requirements for periodic valve line-ups are not specified by procedure or policy. Components found mispositioned are typically not investigated to determine the reason for the mispositioning. Following the discovery of two mispositioned valves on the reactor recirculation system, valve line-ups were completed on six additional systems. More mispositioned valves were identified. As a result, a complete valve line-up was ordered and was in progress when the DSA team left the site. At that time 65 components, including valves, dampers, and breakers were identified as mispositioned. The high number of mispositioned components identified indicates a weakness in the station's ability to control and maintain system status.
(3)
Drawing walkdowns conducted between 1986 and 1993 identified over 200 valves that are not included in valve line-up check lists.
Operations personnel have not established a priority to include these valves in the line-up sheets. Considering the number of valves that have been found to be mispositioned that are listed on line-up sheets, the status of the unlisted valves is uncertain.
(4)
Seven lead wire seals, used to prevent operation of critical valves associated with reactor safety without breaking the seal, have been found broken, missing or improperly installed in the past four months.
Three of the deficiencies were discovered by the DSA team. The seals were replaced but no investigation was performed to determine
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the cause for the discrepancies. Missing or improperly installed seal wires remove a barrier to unintentional operation of valves important to safety.
l (5)
CNS Procedure 2.0.1, " Operations Department Policy," establishes numerous exceptions to the requirements for independent or 7
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Cooper Nuclear Station Diagnostic Self Assessment I
- concurrent verification of valves, breakers and electricalleads. The aggregate effect of the exceptions is to prevent detection of misoperation or mispositioning of a component. For example, technicians land leads on sensitive equipment without concurrent verification that the lead and location are correct. This can result in the lead being landed on the wrong terminal, followed by an unintended actuation before the second person has the opportunity to detect the error. Typical industry practice is to provide concurrent verification for work on sensitive equipment and independent verification on component positioning that affects reactor or personnel
- safety, 2.1.2 Compliance to Standards and Procedures is Frequently Not Conservative The station has not established an expectation on adherence to standards, procedures and program requirements that conveys a philosophy accenting conservative compliance. Interpretations of technical specification requirements are sometimes inconsistent and are sometimes made to minimize the impact on the issue at hand. The requirements established in some programs are bypassed through the misuse of other processes.
(1)
Some activities at the station are conducted in a manner that does not communicate a conservative approach toward the interpretation of the CNS Technical Specifications. The DSA team observed, and was informed of, several maintenance repair activities that were performed without SORC approved procedures as required by the technical specifications. Discussions with the CNS staff confirmed this was an often-used practice. Frequently these activities were performed using specialinstructions written by the work crew leader. Additionally, some work was observed to be performed on essential equipment, without written specialinstructions, relying instead on the skill of the craft. Recently, management guidance has been given to reduce the l
use of sis for safety related work.
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t (2)
A change was made to the quality assurance program that reduced the level of commitment to the NRC without processing the change in accordance with 10CFR, Part 50.54(a). QA audit frequency was i
changed for certain audits from annually to biennially without 8
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I Cooper Nuclear Station Diagnostic Self Assessment i
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obtaining prior NRC approva!. Area audits deleted from the 1993 schedule included: station operations, repair maintenance, environmental, and SRAB/SORC activities. GA management did not.
i interpret the change to be a reduction in the level of commitment to the NRC requiring prior approval, even though the previous auditing program is based on annual audits. Additionally, ambiguities as to
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which revision of ANSI N18.7 the GA program is committed have not been resolved by the station although the need to do so has been 4
recognized by OA management.
(3)
The CNS Emergency Plan requires the shift technical advisor (STA) position to be manned at all times. The technical specifications and station procedures contain provisions for not staffing the position during outages. During the current outage the STA position was left unmanned for several days before the discrepancy was recognized. A failure to ensure that different but interrelated programs establish i
consistent requirements resulted in securing the STA function without first recognizing the discrepancy.
t (4)
Procedure and program requirements are sometimes ambiguous. For j
3 example, the Conduct of Maintenance procedure allows the maintenance manager to make exceptions to that procedure but fails i
to establish controls or documentation requirements for exceptions j
that are authorized. The Temporary Design Change (TDC) procedure j
j states that TDC's are not considered permanent while another step in the same procedure describes what to do when a TDC is considered
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permanent. Ambiguities in procedures can result in worker confusion 1
regarding management's expectations and reinforce an attitude to interpret the requirements in a manner that expedites work completion 2
rather than conformance to expectations.
4 (5)
Decisions to postpone the Emergency Plan's 50 mile ingestion j
pathway zone (IPZ) dose assessment model conversion to EPA 400 requirements were made without modifying the Emergency Plan or the Emergency Plan Implementing Procedures. The emergency planning coordinator did not view this as a potential licensing issue and considered verbal NRC approval adequate.
(6)
A wou established procedure validation and walkdown process has
. been circumvented through the use of special instructions. While not 9
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Cooper Nuclear Station Diagnostic Self Assessment t
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intended _to be used as procedures,'special instructions have sometimes been used in place of procedures. Since special instructions are neither validated or walked down, errors go undetected until they are actually being performed in the field.
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4 (7)-
Proceduralized preconditioning of equipment, prior to surveillance testing, has resulted in the inability to determine the as-found condition of some equipment. A lack of rigorous investigation and response to a NRC identified concern regarding the' testing of i
secondary containment integrity resulted in recurrence of a similar event and an undetected degradation of the emergency electrical-system. Although station management considers this issue to be adequately addressed through recent management directives and procedure reviews, the DSA team found that little guidance has been developed for operability determinations in cases where preconditioning concerns were identified during the procedure reviews.
2.1.3 Training is Not Effectively Used to improve Performance Training in some functional areas is inadequate to provide personnel with the knowledge and skills necessary to perform their assigned tasks. Training is viewed by some CNS management as an obligation instead of an opportunity to improve personnel performance. As a result, line management has not recognized the need for accurately determining core needs for competency in some areas. Additionally, a lack of line management ownership of their respective training programs has resulted in the training department receivir.g little or no oversight and feedback to improve the quality of training. Examples include:
(1)
The initial engineering support personnel training program for station engineers provides limited overall system knowledge. Position-specific guidelines for selected engineering support positions were not incorporated into training as specified by the issuance of.INPO ACAD 91-017, " Guidelines for Training and Qualifications of Engineering Support Personnel," due to inadequate follow-up by training management. System engineer training consists primarily of self sturiy and a demonstration of their knowledge of their assigned system to their supervisor before being " certified" as system
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Cooper Nuclear Station Diagnostic Self Assessment engineers. There is limited cross training of engineers to improve the knowledge of the other (mechanical or electrical) aspects of system operations. Examples of training / knowledge weaknesses of observed include:
Several system engineers interviewed.were unaware of where e
the design basis for their system is located or how to identify the applicable design basis information for their system.
System engineers currently prepare special instructions for e
maintenance work activities on safety-related components.
Corporate engineers often prepare the special instructions for design change package implementation. However, neither group has received training in work planning or procedure preparation.
Corporate engineering personnel do not receive plant systems e
training.
(2)
Skill of the craft training needs are not understood and are inadequately defined. Many job performance measures (JPM's) are evaluated in the training shop environment to a generic skill. Few follow-up motor skill evaluations are conducted on specific in-plant equipment. Maintenance supervision relies on procedures and skill of the craft training to ensure maintenance activities are properly performed. The expectation is that journeyman need only basic skills of the craft training. Once this training is complete, maintenance supervision believes that the journeymen can handle most tasks in the plant using procedures or specialinstructions. Subsequently, maintenance supervision (with the exception of the operations manager who is responsible for the l&C training program) does not promote further training of maintenance personnel. However, weaknesses observed in the conduct of maintenance indicate additional training may be needed. Refer to section 2.2.2 for additional detail.
(3)
The health physics (HP) technician continuing training program is limited in that it does not build an in-depth technical program following the fundamental training program. Although HP supervision 11
Cooper Nuclear Station Diagnostic Self Assessment conducts continuing training during periodic meetings, the continuing training process needs to be defined from a Training Department perspective that includes a skills and needs basis and expanded to provide more technical detail and challenge for HP personnel.
CNS Directive 54, " Management Overview of Training and Evaluation Activities," issued in 1992, directed management to participate in periodic training observations and provide feedback on training quality and effectiveness. Maintenance management and supervision have not conducted any of the observations required by CNS Directive 54.
Additionally, the engineering manager has not conducted any observations since 1992. The operations manager has provided feedback to the operations and I&C training programs. However, the DSA team observed that the operations manager's expectations for the shift supervisor maintaining a stand back overview during emergency events is not incorporated into simulator training indicating additional oversight and
. monitoring may be needed.
2.1.4 Degraded Material Condition and Long-Term Problems Have Potential to Affect Plant Operation The overall number and individualimportance of equipment problems l
represents a potential challenge to effectively monitor and operate the plant.
The team does not consider this to be a significant issue at this time, as evidenced by a low number of significant events and complicated plant trips.
However, degraded material conditions and other long standing problems may unnecessarily burden operators responding to various plant conditions and transients by requiring actions not identified in response procedures.
The DSA team found a willingness by station management to accept some degraded conditions without an aggressive effort to correct the problems.
Lack of action to correct material deficiencies and other long standing problems will result in an ever increasing number of operator work arounds and other problems that further challenge the operators ability to effectively monitor and operate the plant. Contributing to this problem is a lack of an integrated work control process that includes a mechanism for problem identification, prioritization, scheduling, status tracking and trending of recurring deficiencies. Examples include:
12 t-__---_---_-_-________-__
P Cooper Nuclear Station Diagnostic Self Assessment (1)
The "B". reactor feed pump minimum flow valvs leaks by its seat at 200 gpm, and as a result, is kept isolated by shutting a manual
' isolation valve. This is identified with a caution tag that was hung on 8/26/93.
Isolating the leakage improves plant efficiency by avoiding heat losses to the condenser but requires operators to manually open the isolation valve if the minimum flow path is needed.
(2)
Drywell "F" sump low level cutout switch doesn't reset until level is high. The reset under these conditions can cause a high fill rate alarm. This problem was identified in June 1993. Living with this condition could result in operators becoming less sensitive to drywell leakage annunciators and as a result take less than prompt action should actual leakage occur.
(3)
The reactor vessel level injection solenoid isolation valve leaks past its seat. As a result, a manualisolation valve must be closed. This injection (fill) line is from the core spray system and would be used during emergency operating procedure conditions when reactor vessel level instrument reference legs are needed to be back filled. With it isolated, an operator would be sent to the reactor building, second level to open the manual valve.
(4)
The demineralized water level control valve leaks by the seat. It has been isolated, requiring operators to manually open the valve prior to starting the mechanical vacuum pump from the control room.
(5)
Long-standing problems in the service water systems due to silt l
accumulation have resulted in operational work arounds and increased i
maintenance on critical service water components. Examples include:
i
\\
Silting has resulted in problems with instrument sensing lines plugging and loss of the associated indication or control function. Silting concerns have caused the station to change i
the manner in which they operate the RHR system during shutdown cooling operations. The RHR system heat exchanger j
outlet valve, which is not designed to be throttled, is throttled to control cooling to avoid throttling of service water valves designed for this purpose. The concern the station has with throttling SW valves is the additional erosion caused by the presence of silt. ~ In addition, instruments that indicate service 4
13
Cooper Nuclear Station Diagnostic Self Assessment water d/p on RHR heat exchanger divider plates are pegged low due to problems with sensing line plugging. Loss of this indication prevents operators from being able to perform the precaution in an in-service test surveillance procedure that requires verification that d/p is less than 10 psid in order to prevent damage to the RHR heat exchanger divider plate.
Spargers used in the service water bay for keeping silt in e
suspension have been in need of maintenance for several years.
The plant design has five sets of spargers. The system is designed to work with automatic valves feeding the sparger header. Due to excessive wear of the spargers, only two spargers are in operation at any time. This condition has existed for several years but was not identified in the current maintenance back log.
Service water pumps that are not in operation were rotated by e
hand at least once per every six hours by operators and prior to each time the pump is started in the non-automatic mode. This practice was stopped during the DSA, Service water booster pump maintenance is high considering e
the relatively low use of the pumps.
Maintenance procedures for setting the impeller clearances on e
l the pump require a one hour operation to ensure that the casing is clear of sand prior to work on the pump.
Traveling screens are operated continuously to prevent binding e
from silt accumulation. Previous problems with screens require quick response from maintenance to avoid accumulation of silt preventing operation. If response is delayed, plant operation may be affected.
(6)
Some long-standing equipment degradations noted during operation and maintenance are uncorrected and are not being tracked by the corrective action program or work control system for future resolution.
Coolant leakage from the "A" RHR heat exchanger mid-body e
flange joint is being collected by a semi-permanent drain hose 14
- _ _ ~
1 I
Cooper Nuclear Station Diagnostic Self Assessment embedded in the shell insulation. The leak had been first identified in 1986 via a maintenance work request that was subsequently cancelled in 1990. Although the cancelled MWR was annotated to delay the job until an outage of sufficient duration, no replacement MWR was created.
A temporary patch has been installed on the REC piping from e
the reactor recirculation pump motor generator oil coolers in 1977 and apparently not considered as a temporary repair or modification. The patch was identified during a recent walk-down, removed and permanently repaired.
2.2 MAINTENANCE AND TESTING Maintenance activities are not sufficiently controlled to adequately assure that equipment quality and availability are suitably maintained. Some controls for maintenance activities are inadequately established and are
- frequently not properly applied to work, resulting in nonconforming and degraded plant equipment. Improper maintenance work has resulted in an increase in out-of-service time and rework. Quality control verifications are not consistently incorporated in work instructions and are not consistently performed to ensure that the work meets established requirements. Lack of a comprehensive work control system using traditional scheduling and planning techniques also results in additional equipment outage time, increased outage risk, lost maintenance production hours, an increase in the backlog of maintenance, over-reliance on skill of the craft in the absence of comprehensive work packages, and over-dependence on the operations shift supervisor to provide close coordination of maintenance activities and plant configuration.
Maintenance and testing were assessed through interviews, observations of maintenance work, witnessing of testing, and review of related documentation.
2.2.1 Work Controlis Fragmented and Lacks Coordination CNS does not have a comprehensive work control system that includes work package and work instruction development, parts and logistics planning 15 y
Cooper Nuclear Station Diagnostic Self Assessment functions, nor centralized short-and mid-term scheduling and coordination functions. The lack of a comprehensive work control system has resulted in extended system outage durations, an increase in the duration and number of equipment outages, repeated challenges to the outage risk assessment process, and a reliance on the operations shift supervisor to manage the control and coordination of work and the configuration of the plant's systems. Additionally, lack of an effective work planning effort is affecting the quality of work being performed by failing to consistently provide written and/or properly reviewed and approved work instructions. The lack of a LCO tracking system adds additional challenges to the ability of the shift supervisor and line management to direct work activities and to assess the impact of emerging work items.
2.2.1.1 Work Planning Work planning is not performed by a dedicated staff of planners but by the shop work crews. Craft personnel are assigned to determine the extent of the problem, develop repair methods including application of vendor or engineering information, arrange for parts and materials, and process the job related paperwork. System and corporate engineers may develop work instructions and procedures for modifications and other plant changes.
Management has accepted the extensive use of skill of the craft as a substitute for written instructions and procedures that should contain information essential to the successful, documented completion of maintenance tasks such as critical work steps and sequences, quality requirements such as torquing, critical dimensions, and inspections.
Reliance on the craft to arrange for their own job materials combined with weak planning of work package quality documentation and inspection requirements has contributed to installation of incorrect parts.
The station staff has also missed the opportunity to build their library of formally issued maintenance procedures by not converting special instructions into fully approved procedures.
2.2.1.2 Scheduling and Coordination Each maintenance department generally controls its own work priorities with little coordination with other departments. There is little centralized direction for work item prioritization. The station does not use train-specific outage windows, rolling schedule or other similar scheduling techniques. This 16 i
Cooper Nuclear Station Diagnostic Self Assessment reduces management's ability to collect, group, and coordinate work to minimize equipment unavailability, control room work loads, and increase craft productivity and has contributed to repetitive and excessively long system and component outages.
The shift supervisor spends a significant fraction of his time processing work requests as they arrive at the control room service window, generally on a first come first serve basis. The DSA team viewed this as an administrative burden on the shift supervisor that detracted from his ability to direct and monitor plant operations. Although there is a " daily work list," it does not accurately reflect ongoing work. In addition, the work scheduled on the list is frequently not worked as planned. Consequently, the shift supervisor has no viable list of scheduled or authorized work to assist the in decision making for the coordination of work.
Operations is not consistently involved in assigning priorities to work but acts as a processor of items proposed by the work groups. Even items of potential operational significance do not always receive sufficient priority. A number of the degraded material conditions identified by the team involved operational work-arounds that should be corrected, e.g., silting problems in systems carrying river water, malfunctioning "F" drywell sump low level cutout switch reset, and others as discussed elsewhere in this report.
Work is not routinely scheduled to optimize completion of backlogged corrective and preventive work while equipment is out of service. Backlog 4
l has increased from 1,023 open items in January 1994 to 1,392 in June 1994 and to over 1,600 in July 1994. Safety related systems and equipment are frequently removed from service for a single routine task, returned to service, and then taken out of service a few days later for another similarly routine task. For example, the "A" reactor recirculation i
pump was taken out of service and restored three times between June 2 3
l and 9,1994 for electrical maintenance. The "D" service water booster pump was out of service three times between March 1 and 11,1994 for an L
oil change, a gland water piping repair, and an alignment check.
During outages, plant procedures call for designation of specific senior managers as Outage Directors. Because of the number and magnitude of
~
issues being addressed by the plant staff, no senior managers were considered available for this position. instead, two more junior staff i
members are assigned to the position of shift outage director. The 17
Cooper Nuclear Station Diagnostic Self Assessment governing procedures were not clear regarding the shift outage directors' organizational reporting lines nor which line manager has the ultimate responsibility for outage scope identification, growth, and control; schedule adherence'and accountability; and, information dissemination and communication.
The lack of centralized outage management and information was evident when the operations staff dealt with safety system train outages and restorations. During the assessment, the staff switched residual heat removal from RHR Division I to Division ll but encountered a number of challenges. First, some actions needed to restore Division ll's operability were being identified during outage schedule meetings but were not being captured in an action list for assured follow-up. Prerequisites for the divisional changeover were being identified until the initially scheduled changeover date and beyond. Secondly, some work items were sent to the maintenance shops but the paper work was misplaced. The jobs did not start and were not recognized as potential impacts to the changeover due to the lack of tracking information. Thirdly, several major jobs were not on the daily work list such as re-insulation of RHR piping, scaffolding removal, and battery testing. Lastly, a system readiness milestone certification process to establish and confirm RHR divisional readiness and operability did not exist.
2.2.2 Weaknesses in the Conduct of Maintenance The following aspects of the plant maintenance program's performance contribute directly to poor quality maintenance. Low management expectations and performance standards for the maintenance program and correspondingly weak performance by several quality related aspects of the program were evident.
2.2.2.1 Nonconforming and Degraded Plant Equipment The team found that inadequate maintenance controls or poor adherence to those controls contributed to improper or unsuccessful repairs and return of the equipment to service. For example:
l (1)
Safety related level transmitters for the scram discharge volume were installed using 1/4 inch mounting bolts instead of the 5/16 inch or larger bolts specified by the original system engineer-prepared special 18 t___.____ _ ____._________._ _ _ ___._ __ _ _ _ _ _ _ _ _ _
Cooper Nuclear Station Diagnostic Self Assessment instruction and the equipment vendor. The larger bolts were required to meet the seismic qualification requirements for the transmitter.
The CNS system engineer changed the specialinstructions to provide torque requirements for the 1/4 inch fasteners. Although the system engineer subsequently wrote a condition report documenting the improper bolting condition, the transmitter was assembled, tested and returned to service.
-(2)
RHR pump motors had periodically experienced loose bolting following vendor shop repairs since at least 1988. In response to a 1993 loose bolting problem with the "C" RHR pump motor, the station determined that the vendor shop did not require quality control verification of torque in its shop. Corrective action was not taken to check the bolting on the "A", "B", or "D" RHR pump motors nor were the CNS work packages upgraded to specify and verify bolting torque.
Subsequently, the "A" pump motor was found to have loose bolting and a related oil leak in July 1994. Maintenance items were then written to check the other pump motors.
(3)
Other examples include:
reassembly of the "A" service water pump coupling without using the vendor's recommended torquing pattern and values reassembly of the "A" service water pump impeller using L
e clearance values about one-half those specified by the vendor manual (0.021 inches vice 0.056 inches) installation of a #2 EDG fuelinjection pump and replacement of e
the exhaust manifold using specialinstructions that did not include torquing of the bolts per vendor manual requirements 2.2.2.2 Quality Control Weaknesses in the quality control program result in inconsistent specification of quality requirements and rigorous quality verification of field work on safety related equipment. As discussed above, work instruction are prepared by the craft persons or system engineers assigned to the l
maintenance task. Quality requirements are normally to be input to the work instructions by work item tracking staff. Many of the work packages 19 L
Cooper Nuclear Station Diagnostic Self Assessment reviewed by the DSA team contained no requirements for verification of key process steps or conditions to ensure the quality of the work performed.
CNS uses a peer quality controlinspection process. A qualified craftsmen who did not participate in the work temporarily assumes the role of inspector. The team and recent NPPD quality assurance audits found occasions where this independence was not maintained. Peer inspector training was also found to be inadequate in that it does not include methods for performing checks or observations in the field but rather addresses only the administrative procedures and maintenance technical skills. Practical observation training and demonstration of field observation proficiency is not included. The above weaknesses result in relatively few problems being identified by peer inspectors. The team found that no deficiencies had been documented as condition reports by peer inspectors since the new corrective action program was implemented in April 1994. Little management oversight of the peer inspection activities was noted by the team, indicating a lack of line management ownership or concern for the quality of maintenance.
Specific problems found in the application of quality control to maintenance activities were:
(1)
Multiple examples of failure to specify foreign material exclusion and failure to verify system cleanliness. CNS has experienced recent foreign material induced failures in a valve motor operator and multiple air system solenoid valves.
(2)
Fastener torquing requirements not specified nor used for diesel generators, RHR pump motors, and other equipment.
i (3)
Correct parts and proper materials not being consistently verified at the point of installation, frequently resulting in questionable or nonconforming conditions. Examples include a HPCI auxiliary oil pump control relay with an incorrect voltage rating; an undersized EDG starting air system relief valve; and, various commercial grade check valves installed in the nuclear boiler, RCIC, RR, MS, and HPCI systems without proper dedication.
The aggregate issues of maintenance craft providing their own work planning (including specification of quality control requirements), the over-20
Cooper Nuclear Station Diagnostic Self Assessment reliance on skill of the craft of processes and procedures, and the peer QC program contribute to the inadequate quality of maintenance at CNS.
2.2.2.3 Rework Station management does not effectively monitor rework (re-performance of corrective maintenance necessary because of unsuccessful or improperly performed repairs) as part of the existing performance monitoring process.
Several plant practices tend to mask the occurrence of rework and degrade the effectiveness of work authorization and control processes. For example, maintenance work requests have been routinely held open for or re-opened after long periods of time. The team reviewed a number of examples of rework due to unsuccessful initial repairs. Examples include:
(1)
Changes were made to 4160V breaker wheel and frame alignment using locally made tools and informal procedures that were not based on controlled drawings or vendor information. Those changes resulted in misalignment of and operability problems with auxiliary devices and subsequently affected breakers for an RHR pump, service water pump j
and service water booster pump, electrical bus ties and feeds.
(2)
The "A" service water pump had been repaired in August 1994 and its impeller clearance adjusted. Over the next several days, the pump required impeller clearance readjustment at least twice more. No cause for the unstable clearances had been determined but the clearances used for assembly deviated from vendor manual values.
(3)
Additional examples involved turbine equipment cooling pump mechanical seal leaks due to a missing 0-ring, rework of diesel generator engine leaks three months after major overhaul, improper assembly of various containment isolation valves, and RHR service water booster pump motor-operated valves unsuccessfully overhauled during the refuel outage.
)
4 I
21
Cooper Nuclear Station Diagnostic Self Assessment 2.2.3 Deficiencies in Procedure and Instruction Content and Use Management has not provided procedures for maintenance and testing that are adequately developed, reviewed and approved, and controlled in use. A great deal of reliance is placed on the " skill of the craft" that is assumed to derive from a very stable work force of crafts persons with unusually long incumbencies. In many cases, work is performed without specific work instructions, using only a maintenance work request to authorize and scope the work.
Administrative controls in procedures frequently have ambiguous or inadequate instructions and tend to weaken the local performance standards and management expectations for procedure adherence. For example, the determination of need for pre-test, post-test, and quality control requirements in Procedure 7.0.1.2, "MWR Generation and Review," are not clearly delineated. Section 1.2 of Procedure 7.0.4, " Conduct of Maintenance," states that the maintenance manager can make exceptions to the Conduct of Maintenance Procedure for non-safety related items but does not describe what exceptions are permitted nor how they are to be f
1 documented. The guidance for use of Interim Procedure Changes and Temporary Procedure Change Notices in Procedures 0.4, " Procedure Change Process," and 0.4.2, " Temporary Procedure Changes," are not explicit.
Section 2.4.1 of Procedure 3.4.4, " Temporary Design Changes," states that temporary design changes are not considered permanent while Section 1
2.4.4 describes the steps to be taken when one is considered permanent.
l Some work on essential equipment is performed in accordance with special instructions that are written by a variety of station personnelincluding managers, engineers, supervisors, and craft personnel. Frequently, these instructions are used without formal review and approval, including the SORC approval required by technical specifications. This has contributed to j
the use of maintenance work instructions that do not provide sufficient technical information to assure work is in accordance with vendor i
requirements or specifications.
The team found many examples where either skill of the craft or unapproved and inadequately controlled specialinstructions were used:
l 22
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Cooper Nuclear Station.
Diagnostic Self Assessment l
4 l
(1)
A breaker contactor for core spray motor-operated valve 5A was i
replaced using a special work instruction written by the work crew i
leader but not approved by SORC.
(2)
A complete overhaul of an RHR pump motor was performed on using
.]
unapproved special instructions.- Subsequent problems involving loose RHR pump motor bolting were repaired on two MWRs in July and August 1994 using specialinstructions prepared by maintenance 1
planning and system engineering.
~(3)
Various repairs were made to the emergency diesel generators without
[
approved procedures, including:
i
- 2 EDG fuel injection nozzle overhauls in March 1993 using
)
e special instructions replacement of #2 EDG lube oil piping in March 1993 using skill e
l of the craft i
i removal and reassembly of the #2 EDG exhaust manifold in e
March 1993 using skill of the craft.
j I
Even when procedures used for surveillances and field work are fully i
developed, reviewed and approved, they frequently result in inappropriate actions or work interruption due to unusable or incorrect information. For example:
(1)
Testing in accordance with Surveillance Procedure 6.2.2.5.14, "RHR Initiation and Containment Spray Logic Functional Test," was I
suspended several times between July 24-26,1994 due to errors in the procedure's treatment of relay logic. The errors were corrected by procedure changes. On July 26, the procedure caused an inadvertent
{-
trip of the 1 A recirculation pump when the test shut the operating pump's discharge valve. The procedure had been extensively revised
.in the recent past but had not been subjected to verification and t
validation.
i (2)
The sensing lines for service water pressure switches which isolate the essential water sub-system from non-essential sub-system accumulate river silt and are routinely back flushed by technicians 23
f
]'
Cooper Nuclear Station Diagnostic Self Assessment t
prior to calibration. The back flush evolution is not included in the calibration instruction and discussions with I&C technicians, supervisors, and training instructors indicated no standardization of the practice. Further, the team found that, although the pressure
. switches were calibrated, the functional testing for the auto-closure feature was inadequate.
1 There is a lack of confidence by station personnelin the ability to revise and improve processes and programs in a timely manner due to an inadequate 4
procedure revision and improvement program. As a result, both 4
management and staff have become tolerant of procedure deficiencies and lax adherence. The backlog of unprocessed procedure changes has grown by about 65% since 1992. In the same period, the number of procedures 1
which exceeded their biennial review time frames increased from about five to about thirty procedures per month. The number of open procedure
[
change notifications has increased by about 60% and their average age has I
also increased. Although performance and status are reported monthly to station management, no comprehensive action appears to have been taken in response to these indicators. The team found that the inability to make expeditious improvements to procedures materially degraded the staff's j
attitude about procedure adherence and submittal of changes for improvement.
J 2.2.4 Weaknesses in Industrial Safety Practices Standards for industrial safety are not consistently enforced by station management. Personnel frequently ignore station and corporate safety j
guidelines in the performance of work. Independent verification of clearances is not performed to provide for worker safety. Industrial safety practices of j
personnel performing work in the station are not in accordance with station guidelines and occupational safety standards. Examples include:
(1)
Scaffold used for reactor equipment cooling piping was not equipped with toe boards, guard rails and/or mid rails and had inadequate 4
tipping protection. During the REC work, a welder was observed 1
welding while standing on a steel rod pipe support with an improperly
' tied-off safety harness. Workers were periodically observed walking in overhead cable trays and duct work without fall protection.
24
i Cooper Nuclear Station Diagnostic Self Assessment -
(2)
Inconsistent use of hard hats, eye protection, and foot protection
.were observed throughout the plant. For example, workers cutting pipe for the REC repairs were not wearing eye protection nor hard hats.
(3)
Numerous problems were observed with clearance order administration and equipment status errors. Current practices for local leak rate testing allow operation of tagged valves and maintenance special in'structions were used to isolate work boundaries instead of clearance orders and tags. The service water pump shafts were manually rotated using a bar on the coupling with the pump in pull-to-lock but without the protection of a clearance order.
Performance indicators for industrial safety accident rate at the station are well above the industry median. The stations industrial safety accident rate performance indicators have been above the industry average for the past four years and the station currently ranks 60th out of 71 plants in overall industrial accident rate performance. The team's observations were sufficiently numerous to indicate that management is not out in the plant observing activities and are not enforcing acceptable standards of performance.
2.3 ENGINEERING AND TECHNICAL SUPPORT The control, use, and understanding of the station's design basis information was found to be weak. Station modifications are sometimes installed prior to receiving required design reviews. Inadequate training provided to the system and corporate engineers on design basis information, licensing basis and other station commitments contributed to their lack of understanding of the relationship between these issues. Some equipment performance monitoring programs are deficient and not effectively identifying degraded performance. Many of these programs have not been reviewed to identify weaknesses and areas for improvement. Corporate and system engineering support of plant operations is often weak and poorly coordinated. Roles and responsibilities for various engineering support groups are not well defined.
The team performed an in-depth review of the residual heat removal system and its associated electrical power supplies and support systems. The team also ev luated the effectiveness of the engirieering and technical support functions by reviewing routine engineering support of the plant, resolution of 25
~-
~.
i i
Cooper Nuclear Station Diagnostic Self Assessment
> -,::::tL%n%$
V~
4
' plant problems, plant modifications and design changes, configuration p
control and organizationalissues. The team conducted numerous interviews -
with engineering support personnel, station and corporate management.
2.3.1 Design Controlis insufficient to Maintain Design Integrity Control of design activities is not sufficient to ensure analyses are based on correct and current design information. Contributing to this lack of effective
]
design controlis a lack of readily available design basis information.
Additionally, many system engineers were unaware of how to locate design basis information and what information comprises the plant design basis.
1 (1)
.The control of design calculations limits the ability of design engineering personnel to ensure that current calculations are being used as references when designing a plant modification. During
. interviews with engineering personnel,it was noted that there are over 24,000 calculations on file to support the station. However, it
{
was found that the listing of calculations does not identify which calculations are current, such as identifying the calculation that superseded a previous calculation. During reviews of design change packages, it was noted that the supporting calculations seldom i
reference previous calculations, and none of the calculations reviewed identified any previous calculations as superseded. In one case, there were three different calculations to support a portion of a modification, and two of the calculations did not reference any of the other calculations associated with the modification. Additionally, a review of calculation control procedures identified the potential for a calculation to become approved and included in the calculation listing t
without the modification it reflected being installed in the plant.
These activities can result in the incorrect calculation being used ;n station analyses.
(2)-
The control of plant changes that affect either physical station configuration or key plant analyses sometimes do not ensure the analyses are maintained current. During the 1993 refueling oi:tage, the station used a process wherein a design engineer could prepare a
. set of design sketches to accompany an MWR, obtain SORC approval
(
for the sketches as a design change, and authorize the change to be installed in the plant. A review of some examples of these changes noted that the calculations to support these design sketches would 1
26 4
s' w
Cooper Nuclear Station
^
Diagnostic Self Assessment i
i sometimes lag as much as one year behind the installation of the change. Additionally,in the case of two of the SORC-approved MWRs reviewed, the design change that followed the SORC-approved MWR required some significant station work to ensure the completed modification would still comply with design requirements. For example, a damper in the standby gas treatment system was blocked 4
open as a result of a SORC-approved MWR. However, when the design change was developed to finalize the design for blocking open I
the damper, it was found that there was a' possibility that the purge flow from the containment could cause nitrogen and radioactive gases from the containment to back up into the reactor building exhaust plenum. As a result, the design change included system testing to j
i establish the throttled position of another damper to ensure the flows would be limited and not allow containment nitrogen and gases to be
{
drawn into the reactor building exhaust plenum, j
(3)
Controls over design information are not adequately established to ensure the correct information is provided for third-party analyses.
i For example, one engineering manager indicated he was not aware of any design engineering interface with GE regarding the fuel reload analysis and the control of design information necessary to support the various reload and transient analysis. During discussions of incorrect in-service testing valve stroke time requirements, one corporate engineer indicated the latest core reload analysis included a change to the stroke time for the LPCI Injection valve. The analysis didn't identify the slower time as a concern. As a result, a documented basis for using the slower stroke as an acceptable testing value could not be identified. This lack of a basis is due to a lack of controls over the transfer of this design information.
j (4)
The understanding of design basis information is limited, with many engineering personnel unable to differentiate between the design basis i
for the station and the licansing basis. As a result, some aspects of plant testing and operation are not adequately addressed and design information may not be appropriately considered in some activities.
l For example, a lack of understanding of the relationship among plant technical specifications, the USAR, and the design basis, caused the in-servico testing engineer to incorrectly specify the limiting stroke
. times for motor-operated valves in the RHR system. In another example, in response to questions concerning interactions between 27
4 Cooper Nuclear Station Diagnostic Self Assessment the spent fuel pool cooling system and the RHR, engineers were unable to identify the basis for a USAR statement that the RHR system could provide fuel pool cooling if the fuel pool temperature were to approach 150 degrees Fahrenheit. Additionally, design basis information was frequently not identified as reference material when pr'eparing design calculations. In reviewing approximately eight calculations that support design change packages, the team only
!!!entified two instances where the original design information was i
referenced.
(5)
An additionalindicator of a lack of understanding of design basis information is the use of tests to establish design input information.
For example, when examining the possibility of back flows from the containment purge lines to the reactor building exhaust plenum, testing was performed to identify the correct setting for a damper that was placed in a throttled position. However, the testing did not verify that the system was capable of operating as intended in the design configuration. (i.e., verifying flows in portions of the system that were shown on process flow diagrams) when determining the " correct" throttled position for the damper, in another example, the system resistance of the RHR system was to be modified by replacing the l
flow trim in the LPCI injection throttle valve and the suppression pool cooling throttle valve. The system was verified to perform properly by measuring pump discharge pressure and flow rate, then using the original pump curve to determine whether the flows and pressures would meet technical specification requirements. This method of testing did not include considerations used in the original system 4
design, such as system configuration for operations, or the changes in j
system configuration assumed in a post-accident condition. Typically these performance requirements are more complex that the values listed in the technical specifications.
i 2.3.2 Control of Station Configuration is Not Effectively Maintained Changes to station configuration are not adequately reviewed or controlled to ensure the station configuration reflects station design. A number of items have been Identified that are not consistent with design or licensing 3
documents.
i; 28 a-
Cooper Nuclear Station Diagnostic Self Assessment (1)
A number of instances of alterations (undocumented modifications) to the design of plant equipment have been identified. These include: a semi-permanent leak collection hose attached to an RHR heat exchanger, a weld patch on the reactor equipment cooling system, and the removal of check valves from the standby gas treatment system. Many of these alterations have been implemented through the maintenance work process without being recognized as modifications. Alterations to plant equipment, through the maintenance work process, do not receive the in-depth analysis and.
review require to support changes to the design of plant equipment.
(2)
The communication of design requirements to the station has not been effectively controlled to enable the station to establish the appropriate procedural controls to prevent placing the plant in an un-analyzed configuration. For example, it was recently identified that the reactor equipment cooling system could be cross-tied in a way that would prevent the system from performing its required function following a design basis accident. Similarly, corporate engineering personnel noted that the station procedures permitted some electrical loads to be cross-tied in a way that differed from the station electrical load analyses, and recently submitted a lotter to the station manager to identify the need to revise these procedures to prevent these system alignments. Additionally, station procedures allow the shift supervisor to modify valve lineups from those shown in design change packages.
(3)
The lack of readily available design basis information also contributes to cifficulties in establishing the correct essential /non-essential system classifications. Some important station equipment has been incorrectly classified as non-essential, such as the control room envelope. Determining the correct classification to be used when performing maintenance or procuring spare parts is sometimes difficult
. to ascertain.
(4)
A comparison of some drawings to procedures and valve lineup checklists identified approximately twenty-one valves on one drawing that were shown on the drawing in a position different than the normal valve position during plant operations. Further discussions identified that the station had taken a position that the procedures controlled valve positions, and the drawings identified the valve 29
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Cooper Nuclear Station i
Diagnostic Self Assessment i
l locations. This undermines configuration control because the drawings are a principal design output document and, as a design output document, should reflect the normal system alignment used in
]
the system analysis. Additionally, a limited scope drawing verification -
program identified several hundred discrepancies, including incorrect labeling of components, incorrect identification of some components, and incorrect references for continuation of systems.
2.3.3 Corrective Action Program is Not Effective in Correcting or Preventing Problems The station has experienced many recent events or adverse conditions that result from failed or absent barriers that should have been provided by effective evaluation and implementation of the lessons learned from in-house and industry operating experience.
2.3.3.1 In-House Operating Experience Program l
CNS has not consistently demonstrated the ability to identify, aggressively pursue and permanently resolve their own problems occurring at the station.
The inability to resolve recurring problems was attributed to failure to conduct thorough root cause investigation or implement the necessary enduring corrective actions. These deficiencies have been noted in the CNS 1
Integrated Enhancement Program.
The DSA team recognizes that the station has made significant changes in the way problems are reported and evaluated. In April 1994, a single problem reporting system, having a low reporting threshold, was implemented, it is evident that aspects of the program have been embraced by station employees, particularly on the working level where over 95% of condition reports are being generated. (Problem reports are being generated at a rate of about 1420 per year, as compared to about 138 per year in 1992.) Training has been given on the new program, thorough guidelines have been developed on root cause analysis techniques, and expert mentors / coaches have been provided to facilitate implementation of the new guidelines. A corrective action program manager has been assigned, and a group of root cause team leaders has been formed to improve the consistency of root cause analyses.
30 4
't
Cooper Nuclear Station Diagnostic Self Assessment Notwithstanding these accomplishments, weaknesses continue to exist in the administration of the corrective action program as evidenced by the following:
(1)
A growing backlog of problem reports is challenging the station to work on the important issues and avoid being distracted by the number of problem reports generated on events or conditions having lesser significance. Recent statistics show the backlog for significant condition reports (category 1 and 2 CRs) contain more overdue and older issues than the backlog of non-significant condition reports (category 3 and 4 CRs). This indicates that work on backlog items may not be appropriately prioritized.
(2)
Root causes are continuing to be determined by an informal apparent cause process rather than rigorous application of the
)
techniques contained in the CNS Root Cause Guidelines.
(3)
Examples were found where planned corrective actions don't clearly focus on the root causes. For example, the root cause for failure of Westinghouse DB-50 undervoltage trip assernblies was lack of management commitment to operating experience review program implementation. However, the corrective actions primarily address prevention of the hardware failure and l
do not address such management commitment issues as performance monitoring and effectiveness reviews, resource j
i and staffing, responsibility and accountability for program j
implementation, and performance of interface organizations, (4)
Accountability for the corrective action program is fragmented and the vision for the near-term and long-term program has not been finalized.
The DSA team identified the following recurring in-house events to be representative of continuing problems in this area:
(1).
On February 1,1994, while operating at full power, a core spray pump minimum flow valve unexpectedly closed and then automatically opened when the system test return valve was stroked open during valve operability surveillance testing. An 31
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t Cooper Nuclear Station Diagnostic Self Assessment t
investigation was unable to recreate the anomalous equipment behavior. Because the core spray flow instrument had a history of problems associated with air in the sensing line and the flow transmitter had been removed from service and calibrated earlier that day, the most likely cause was attributed to instrument spiking caused by air in the' sensing lines.
Continuing evaluation of the event had subsequently dismissed air entrapment when the event recurred in April 1994.
The work history for core spray flow transmitters was then reviewed and numerous problems associated with erratic and i
erroneous flow indication dating'back to 1985 were documented. As recently as March 1993, erratic flow.
indication had been noted while the core spray pump was running, and the pump minimum flow valve was found to be cycling. An operability determination completed in March 1994, ccncluded that the system was operable because,in part, unexpected cycling of the core spray minimum flow valves occurs only during testing (note the inconsistency of this statement with the March 1993, event described above). In July 1994, the station concluded that due to the effects of air on the flow-transmitter, the minimum flow valve could cycle continuously, and that because the valve operator is not designed for this duty, it could fail in non-conservative position during an actual demand.
(2)
In June 1993, the NRC identified a concern regarding the way i
secondary containment operability testing was being performed.
The test was being conducted after substantial preventive and corrective maintenance had been performed, thereby precluding any opportunity to identify degradation that may have occurred prior to the maintenance. No as-found performance data was available. No action was taken by CNS management to address the generic issue of equipment preconditioning, and in May 1994, the NRC identified another case of preconditioning associated with the procedure for sequentialload testing of emergency diesel generators. Some diesel generator loads were shifted before the test, and/or circuit breaker cleaning and lubrication was conducted prior to breaker functional testing.
32 i
Cooper Nuclear Station Diagnostic Self Assessment (3)
In March 1993, during a plant outage, the B RPS bus unexpectedly lost power resulting in several group containment isolations and a half scram. Investigation of this event was unable to determine the cause. In June 1993, the B RPS bus again lost power and the containment isolation signal resulted in a seven-minute interruption of shutdown cooling. Following this second event, a defective underfrequency monitoring unit in the RPS motor-generated control circuit was discovered and was attributed as the cause of both events. Further investigation of this problem revealed that an engineering work request had been written and approved in July 1990, recommending that the non-essential motor-generator output breaker trips be removed due to repetitive spurious actuations during the previous two refueling outages. The EWR was subsequently closed by mistake before a design change was initiated. The root cause analysis of the recent spurious actuations addressed only the defective underfrequency relay, not the previous similar events, the inadvertent canceling of the EWR, or the breakdown in control and tracking of corrective actions.
2.3.3.2 Industry Operating Experience Review CNS has not benefited sufficiently from the experience of other stations in the industry. Performance in this area is weak because technical evaluations of industry operating experience documents are untimely, narrowly focused, based on incorrect assessments of the station equipment performance history, or inappropriately conclude that industry problems were unlikely to occur at the station.
The industry operating experience program relies primarily on a single manager to distribute industry operating experience (OE) documents to responsible departments for evaluation and development of corrective actions. The team found that the OE program manager and supporting department managers are not held accountable for carrying out their assigned responsibilities, and in-depth, independent technical reviews of the evaluations are not routinely performed. Further, periodic effectiveness reviews have not been effective in discovering the depth of the problems in the operating experience program (and the implication of these problems on the overall program adequacy) when individual cases of failed or absent 33
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i Cooper Nuclear Station Diagnostic Self Assessment barriers were discovered. Due to the number and variety of recent station events that involve precursor industry events, the station is performing an extensive review of industry operating experience documents dating back to 1982.
The following example was judged by the team to be representative of problems in the industry OE area: In September,1993, the station evaluated INPO SER 5-93, and NRC IN 93-62. Both of these documents address BWR thermal stratification problems and its consequences. The review concluded that existing station practices and training were adequate to address the concern, and that such an ovent was unlikely to occur at the station. During a reactor scram in December 1993, reactor vessel temperatures did stratify, and heatup/cooldown rate limits were exceeded.
Although this condition was essentially identical to events described in the industry operating experience documents, it went unnoticed by the shift crew, and was also not detected durin0 the subsequent post-scram review.
It wasn't until February 1994, when reports of additionalindustry events were provided to the station, that the post-scram records were reviewed and it was identified that the limits violation occurred.
The following additional events (and their industry precursor documents) involve industry lessons learned that were not taken advantage of by CNS:
Inadequate sequentialload testing of emergency diesel e
generators led to undetected failures in the load shed logic on May 25,1994. (NRC IN 991-13, NRC IN 88-83)
Failure of Westinghouse 480 volt circuit breaker undervoltage e
trip assemblies led to unrecognized emergency diesel generatcr overload on June 14,1994. (NRC IEB 83-08) e Calibration inaccuracies in feedwater flow instrumentation led to non-conservative indication of reactor power and subsequent power by derating by 0.8 percent on March 11,1994. (GE SIL 452 and 452 Supplement 1)
Deficient abnormal operating procedure for loss of feedwater e
events resulted in unrecognized potential for placing the plant in the power instability region during a reactor water level 1
34
Cooper Nuclear Station Diagnostic Self Assessment i
4 i
transient by tripping a recirculation pump on 12/14/93. (INPO j.
SER 23-93) i Multiple failures of GE type SBM control switches in August, i
e 1994. (GE SIL.155 and Supplements 1 and 2)
- Control room habitability envelope test failure on April 11, e
1994, due to excessive leakage and design deficiency. (NRC IN 86-76) l e'
Failure to controlinterfacing ventilation systems during j
secondary containment integrity tests led to undetected 10-inch penetration with no water loop seal since original construction on March 8,1993. (NRC IN 90-02)
I Shifting emergency diesel generators loads as part of the test e
setup before load shed testing in May,1994 - preconditioning issue. (INPO SER 27-93)
High pressure coolant injection pump discharge valve failed on e
September 30,1993, due to a dislodged motor pinion gear key.
(Limitorque maintenance update, INPO SER 9-88)
Primary containment declared inoperable and shutdown action e
statement entered on October 11,1993, due to core spray dual-function valve (mini-flow valve) not meeting licensing basis. (NUCLEAR NETWORK OE 5033 on 1/10/92, and NUCLEAR NETWORK OE 5493 on 8/3/92)
The team recognizes that a change to the way industry operating documents are processed is being considered. The team feels that it is important for the station to study cases such as the ones above in order to determine the program breakdowns responsible for the problems.
2.3.4 Some Equipment Testing and Maintenance Programs Are Deficient Programs for monitoring equipment performance to ensure safe plant operations have not been effectively developed or maintained to ensure the bases for the programs are adequate and the scope of the programs is appropriately defined. Many of these programs were developed at the time 35
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Cooper Nuclear Station Diagnostic Self Assessment of initial plant startup, or when the requirements for such a program were first established, and have not been reviewed since that time to ensure adequacy. During the last eighteen months, reviews of some programs have identified fundamentalinadequacies in the programs. Examples include:
(1)
The 10CFR50, Appendix J prcgram for leak rate testing of containment penetrations and the associated isolation valves was recently identified to be insufficient. Following the identification of penetrations that did not meet expected requirements, a complete walkdown of containment penetrations identified approximately fifty penetrations that had not been previously tested as required. A further review of the adequacy of the testing processes applied identified a number of penetrations that had been tested improperly, such as not testing containment isolation valves in the direction they would be expected to prevent flow during post-accident conditions.
Although the program was found to be deficient during this review, some individual testing problems had been previously identified, but had not identified the need for an overall program review. In one case, the boundary valves for a penetration that was not correctly tested had been identified in the technical specifications as the correct boundary valves for this system. Additionally, previous program reviews, including NRC inspections, had led the station staff to believe the program was adequate and problems identified were not indicators of significant program weaknesses. It should also be noted that the lack of available and controlled station design basis information limited the ability of station personnel to ensure the containment penetrations were correctly identified and tested.
(2)
The in-service test program for testing important pumps, check valves, and motor-operated valves is deficient in its establishment of the bases for required stroke times for motor-operated valves. As a result of reviews of motor-operated valve stroke time acceptance criteria under the in-service test program, and a comparison with original system design requirements, a number of differences were identified. When questioned about the bases for the differences, station personnelindicated that this problem had recently been identified and a review was in progress at corporate engineering to ensure the valve stroke times were in accordance with design requirements. When asked about the bases for stroke times previous to this corporate review, station personnelindicated the acceptance 36
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Cooper Nuclear Station Diagnostic Self Assessment criteria were based on valve stroke time requirements identified in the l
technical specifications or the USAR. Generally, station personnel were unaware of the design valve stroking requirements established in the system design specifications. Additionally, monitoring of pump performance does not ensure that the pumps are operating within expected parameters. As a result of reviews of performance trends for the RHR pumps, unusual performance trends were identified, such as pump differential pressure readings that increased over four
].
quarterly tests, a!though the normally expected pump performance would be stable or slightly declining. When questioned about evaluations to determine the causes of these unusual results, the program engineer and the system engineer indicated the causes for these results had not been analyzed because they did not fall outside the acceptable pump performance limits.' Additionally, establishment of the appropriate pump and valve acceptance criteria is hampered by the lack of a readily available and controlled station design basis.
(3)
The prograin for control of vendor manuals, which ensures these
. manuals are maintained current and reflect the latest vendor recommendations, does not sufficiently ensure the vendor manuals in use in the plant are the latest controlled copy. Currently, a controlled copy of the vendor manuals is maintained in the station library, but l
the copies of the vendor manuals available to the maintenance shops are not maintained current with the latest updates. As a result, workers in the field may be working with vendor manuals that do not reflect the latest approved information. Additionally, limitations on resources and conflicting priorities have resulted in backlogs of vendor manual changes awaiting engineering review and over eighty approved manuals for safety-related equipment that have not been reviewed to identify applicable preventive maintenance requirements.
(4)
After finding cracks in the reactor equipment cooling system in 1979, GE recommended changing the chemistry in the system and establishing a program for ongoing monitoring for crack growth. At
^
the time, a program was not developed to provide ongoing inspection of the weld joints. As a result, system leaks were not treated as indications of potential system degradation until the current outage when a sampling inspection program was undertaken to determine the extent of weld joint cracking.
37 2
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y.
_._m, e --
- h
Cooper Nuclear Station Diagnostic Self Assessment 2.3.5 Ineffective Engineering Support of Station Operation A lack of clearly established roles and responsibilities for engineering organizations has resulted in an inefficient use of engineering resources and inadequate engineering support. Contributing to this problem is a lack of an effective management monitoring and assessment process to identify resource inefficiencies and where additional resources are required to maintain effective engineering support.
(1)
Documented management expectations for system engineers include many typical engineering duties, such as system walkdowns, maintenance support, and system performance trending. However, assignment of additional duties to system engineers has resulted in an excessive workload for the current level of resources. For example, the majority of engineering work is focused on performing evaluations of condition reports under the relatively new corrective action program. Some engineers indicated that the program requirements result in an average of over forty hours of work for each condition report. As a result of the number of condition reports being prepared, the site engineering resources are unable to process the condition reports as quickly as new ones are being generated, resulting in a growing backlog of condition reports for review. Additionally, non-traditional work assignments to engineering are contributing to the excessive workload. Due to a lack of maintenance procedures and maintenance planning personnel, system engineers are called upon to prepare special work instructions for maintenance activities.
As a result of these workloads, backlogs are increasing in a number of areas, such as industry operating experience reviews, NPRDS reports, vendor manual reviews, and procedure reviews. These backlogs are increasing despite system engineers typically working 50 to 110%
overtime over the last eighteen months. Due to the increasing backlogs of various reviews and reports, the attention of the system engineers is being diverted from monitoring system performance and maintaining the necessary perspective when investigating the root causes of system performance problems.
(2)
Due to the lack of clearly defined responsibilities between corporate and site engineering resources, determining work assignments is sometimes difficult and is currently in a changing condition. As a result, station demands on the corporate organization for support 38 i
l i
I
f' Cooper Nuclear Station Diagnostic Self Assessment during the current outage are resulting in significant delays in completing planned engineering activities, such as development of design basis documents, preparation of instrument setpoint calculations, and planned improvements in the modification process.
Additionally, the lack of clearly established roles for the corporate engineering organization has resulted in difficulties in identifying the responsible organization for providing support for identified plant problems. For example, when problems were identified in the shutdown cooling and reactor equipment cooling systems, the expected role of the corporate engineering organization was not clear, resulting in one system engineer approaching a contractor for support that could have been provided by the corporate engineering organization. Similarly, corporate engineering personnel have been managing a drawing verification project, with the station role not clearly defined as part of the project planning process.
A (3)
Additionally, the lack of clearly established roles and responsibilities, as well as excessive system engineering workload and the lack of effective system training for system and design engineers, have contributed to plant modifications that do not correct the identified equipment performance problems, or may introduce additional problems to the system. For example, a modification to replace a
^
core spray system flow transmitter resulted in the installation of a l.
transmitter that is more sensitive than the transmitter it replaced, causing more exaggerated system response to air trapped in the i
instrument sensing lines. In another case, a modification to install a subsystem to provide backfill for the reactor vessel level instrument reference legs during post-accident conditions was attached to the high point vent piping for the core spray system without providing a vent for either system, resulting in air entertainment in both systems and indicated vessel level transients when the backfill subsystem is aligned to supply the reference legs.
f Contributing to the above problems is the ineffective development and use
. of performance monitoring activities. Actions to monitor many of the current system engineering activities have recently been initiated, and demonstrate that the organization is struggling to keep pace with the inflow of work. Also, these indicators do not provide management feedback regarding completion of many of the formally assigned system engineering activities, such as performance trending and system walkdowns.
39
[
Cooper Nuclear Station Diagnostic Self Assessment Additionally, the monitoring of corporate engineering performance is provided through a monthly report and schedule tracking activities.
Currently, the monthly reports identify a number of areas where planned work is not being completed, and do not effectively track progress on short term work assignments in support of current station needs.
14 MANAGEMENT AND ORGANIZATION Significant weaknesses were identified in many areas of the organization.
This has been the result of lack of corporate leadership and support that fostered a management culture resistant to change, and inhibited the Nuclear Power Group from reaching for a higher level of performance commensurate with the rising standards of the rest of the nuclear industry.
This manifested itself through a lack of self assessment and independent oversight, weak management systems for monitoring plant performance, lack of organizational discipline for planning and execution of plans, and failure to have in place an effective management development program to provide managers with the basic skills for managing systems / processes and leading people. These weaknesses have resulted in a reactive organization which has been unable te Identify and correct declining plant performance.
The team drew it's conclusions by reviewing selected documentation and by conducting about three dozen formal interviews and many informal interviews from a vertical and horizontal cross section of the organization.
2.4.1 Impact of Management and Organizational Culture on Performance Management / organizational culture at CNS has not provided an environment which encouraged open dialogue at all levels of the management and staff, and enabling effective identification and solution of long term problems with the plant, work processes and people. In the team's judgement this management culture, which has existed over a long period of time, has resisted change and has been one of the significant barriers preventing CNS from establishing rising performance standards for personnel and plant in partnership with the rest of the nuclear industry.
(One can define or describe organizational culture as a unique blend of values, beliefs, attitudes, norms, practices, myths, history and self image that becomes "the way things are done." It creates meaning and establishes reference points for determining the conduct of organization members).
40
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Cooper Nuclear Station Diagnostic Self Assessment The organizational culture that has existed at CNS affects performance in different ways and in many areas. For example:
(1)-
A welder observed what he thought was rust on a portion of REC piping. The rust was thought to be the result of a through wallleak in the piping. He didn't mention it to his supervisor until three weeks later, and then only after listening to a talk by the new site manager where the importance of the need for the staff to identify problems was emphasized. The timing was unfortunate however, since the REC system had been refilled. This required the system to be re-isolated and the piping drained to facilitate repairs. The initial reaction by the maintenance management was anger and frustration with the welder for not identifying it earlier. This type of management reaction represents a culture which discourages identification of problems.
Reactions such as this have the potential for making employees feel they are placing themselves at risk for being an impediment to getting the plant back on the line.
(2)
Soveral system valve mispositioning events were identified by operations. Operations management's proposed response was to re-perform all the valve lineups. The new site manager questioned the response and the overall policy for operating valves and why this policy has resulted in so many instances where valves were found to be out of their intended position. This raised the question regarding policy clarity, which was not very clear, and pointed to a need for changing the policy to establish better controls. This example represents a management culture in which the Operations management addressed only the symptom and failed to address the fundamental problem of why the valves were out of position in the first place.
(3)
The station culture has created a worker's perception that they should refrain from proposing improvements that are beyond " minimum compliance" because they probably wouldn't be funded anyway. An example of this was the many missed opportunities to improve the control room emergency filter system (CREFS). This significant improvement, to provide the necessary design basis margin, was continually delayed over several years until it impacted system operability. The subsequent problems with the control room envelope, which was determined to be of marginal design and 41 i
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Cooper Nuclear Station
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Diagnostic Self Assessment j
i i
unrollable, are well documented and has been one of the barriers to plant startup. This is a further example of the station culture and illustrates again it's impact through the inability or lack of willingness to pursue problems to resolution, that is to fully assure that the l
control room envelope would maintain an adequate supply of filtered air at the required pressure and beyond merely satisfying the vague technical specifications and USAR requirements. (compliance j
e oriented).
)
In summary, the team concluded that the CNS has historically resisted change and improvement beyond minimum compliance, and have generally disregarded rising industry standards. Furthermore, management has tacitly j
or overtly approved of this isolationist approach for many years.
2.4.2 Ineffective Corporate Leadership and Support Corporate leadership did not assist the site in areas where the presence of strong corporate leadership could have been beneficial. Corporate 4
l management has not assured that the management practices necessary to assure success in running a complex, high consequence operation are in 1
place. These include high-level skills and practices, which are generic in nature and not all related specifically to the nuclear process. For example:
1 (1)
A consistent system for the comprehensive monitoring of plant performance, comparing it against industry standards, then holding i
responsible management accountable for substandard performance i
has not been observed. Well thought out systems for management of I
plant activities were not in evidence. Direction was provided through extensive meetings, and accountability triggered mainly by unanticipated events, or prompting by external oversight observations.
An example of an ineffective management system was the use of data generated by radiation protection performance. The report is distributed once per month via a single document that travels a serial route through the organization. No accountability forum appears to be used to assure that managers are aware when performance in their respective organization falls short. When corrective action is recognized to be necessary, such as the need for a cobalt reduction program, there appeared to be no clear planning or accountability for addressing the problem. Another example was the lack of monitoring of maintenance performance parameters. CNS does not 42 4
+,
Cooper Nuclear Station Diagnostic Self Assessment systematically track these parameters against performance standards.
-This results in a process that is managed mostly in a reactive mode.
No strong role models for using a systematic approach to management were evident at CNS and no management training program toward this end appeared evident.
(2)
Independent oversight has been conducted in a way that had a low
~ probability of success. When problems occurred, they were not used as learning experiences. Corporate executive management did not ensure that these deficiencies were promptly addressed and corrected.
The Corporate Board did not challenge SRAB regarding the absence of observations regarding deteriorating performance, in fact there is no evidence that SRAB meeting minutes were routinely reviewed and commented on by the corporate officers with the exception of the vice president, nuclear. Details and examples are provided in Section 2.4.4 of this report.
(3)
Historically, comprehensive long-term planning has been insufficient to achieve substantial improvement in organizational performance.
1 Recently plans have been put in place for an integrated business planning process. See details in Section 2.4.6 in this report.
-l (4)
The Nuclear Power Group has not effectively utilized or developed more contemporary human resource and organizational development methods to assure strong management and supervisory performance.
This has resulted in management performance weaknesses throughout the CNS organization, which has contributed to deteriorating plant performance. The Integrated Enhancement Plan / Business Plan currently contains some objectives toward this end and some actions, such as management development training, are ongoing. This program is however, separate from a program for management development under the sponsorship of vice president, finance and administration. Rather than use this ptogram, NPG developed their own. This is another area where CNS could have benefited from strong corporate leadership. The example provided the team with further evidence that reinforced the view that CNS encouraged an isolationist approach with the rest of NPPD. See details in Section 2.4.6 of this report.
43
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4 Cooper Nuclear Station i
l Diagnostic Self Assessment
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2.4.3 Weaknesses in Self Assessment 4
l CNS does not' have a strong self assessment culture. Although there is a guideline for the self assessment program, in some cases where a self f
assessment was done, it was ineffective due to a pronounced lack of a self-i critical attitude. While the guideline does describe the methodology it does I
not include good direction and clear expectations regarding criteria for conducting formal, systematic assessments. A review of self assessment i
report files revealed only sporadic performance of self assessment. Also, j
during the DSAT review of maintenance, no reports existed when a request -
j was made for the self assessments of MWRs and field observations required
~
. by section 8.10 of the Conduct of Maintenance procedure. When performed, the quality of the self assessments varied. Of the two reports reviewed in detail, the radiation protection ~ effort was excellent, however the l
SRAB assessment was marginal.
- The'SRAB self assessment, which was done in the third quarter of 1991, concluded that their activities were being " effectively implemented and the Board is making a meaningful contribution to the safe operation of CNS."
Contrary to this conclusion, the Board did not detect or confront performance issues which were occurring at the station. A significant lack of ability to be self critical was evident. Poor conclusions not withstanding, the assessment report contained a number of comments and suggested improvements that would have improved the SRAB function had they all been acted on effectively, however they were not. A less rigorous self assessment performed in late 1993, and correspondence between the vice president, nuclear and the SRAB chairman indicated that SRAB performance issues had not been resolved.
i i
Self assessment should also be initiated whenever a significant opportunity for learning presents itself. The CNS staff took such an opportunity by evaluating themselves against an NRC DET report for a BWR reactor facility similar to CNS. A review of 75 findings in that 1991 DET report was conducted and determined that none of the findings applied at CNS. Had the staff performed a more thorough study and taken action on some the findings, problems that are now being experienced at the station could have been identified and corrected. A close reading of the station's response revealed extensive rationalization of the seriousness of the issues and a
~
shallow assessment of why they did not apply at CNS. One example was item 70, where the issue was insufficient headquarters support and 44 n
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Cooper Nuclear Station Diagnostic Self Assessment oversight. The response cited several examples where this did not represent a problem, including one that the SRAB micromanages the SORC. The fact that the SRAB is micromanaging the SORC instead of assessing the effectiveness of SORC, supports the team's finding regarding the effectiveness of SRAB. That is, the SRAB and SORC lacked sufficient ability to be self critical and were not able to detect or confront performance issues which were occurring at the station.
2.4.4 Ineffective Independent Oversight NPPD independent oversight was not effectively managed. When they had the opportunity to improve, they either missed the opportunity or, if learning occurred, (as in the case of the SRAB self assessment), follow through of the learning process was deficient. The result was an inability to assess station performance. NPPD independent oversight failed to detect the current performance deficiencies existing at CNS. Review of SRAB minutes and SORC minutes along with interviews indicated that these oversight functions believed that CNS performance was essentially strong.
Unfortunately, this falso sense of satisfactory performance appears to have been initially reinforced by external oversight organizations including the NRC. The performance problems subsequently identified by the NRC and the DSA are generally long standing and do not represent a rapid decrease in performance. In actuality, CNS may not have experienced a significant change in performance, but they have failed to keep up with improving industry standards. It's only the belated recognition of this that gives the appearance of a rapid decline in performance.
The quality assurance function however, differs from SRAB and SORC in that it is a standing organization charged with oversight and possessing true organizationalindependence. SRAB and SORC, on the other hand, are committees convened periodically, and composed largely of managers with line responsibilities. Because of these differences the causes of their respective failure to identify the performance issues also differ.
(1)
The team's conclusion regarding causal factors fer the SRAB/SORC failure, was based on SORC meeting observations, review of minutes, and structured interviews and include the following:
The membership of both the committees was composed of a e
large component of plant line management. It is apparent that 45
l h
Cooper Nuclear Station Diagnostic Self Assessment they have been unable to succeed at differentiating their line and oversight roles. In late 1993, the vice president, nuclear communicated to the SRAB chairman commenting on this concern.
i The corporate management failed to apply the basic e
understanding of the role of oversight to the nuclear operation to ensure that common pit falls were avoided.
Neither committee rigorously carried out their entire charter; e
SRAB's being the SRAB charter and SORC's being the technical specifications with emphasis on paragraph 6.2.1. A.4.e. In 1993, SRAB did a self assessment which identified important areas for improvement; however, there was little evidence that permanent change actually occurred.
Neither SRAB nor SORC appear to have taken advantage of the e
opportunity to understand their performance deficiencies in light of and at the time of the earliest indications of the current problems.
SRAB did not appear to have challenged the QA function when e
performance problems became evident.
l SRAB was not effectively challenged on its performance by e
executive management when problems became evident.
e SRAB minutes did not indicate that they ever seriously challenged SORC oversight performance.
(2)
The QA problems were more complex. QA generally exhibited low performance combining a) a lack of vision of quality beyond compliance, b) an insensitivity to the need to evaluate performance vs. reviewing programs, and c) lack of management attention to the
-QA program. It was determined that QA performance may have been diluted by excessive use of their organization for performing staff duties. Additionally, the QA organization was called upon to perform the functions that will now be carried out by the independent review group function. While management had called on QA to perform these additional functions, QA did not adequately perform the 46
Cooper Nuclear Station Diagnostic Self Assessment functions required by the regulations and did not uncover most of the performance deficiencies now evident in the line organization.
(3)
The QA audits, surveillances and evaluations were generally compliance oriented and performance-based issues were generally superficial and caused QA's credibility with the plant staff to suffer.
Further, senior management did not rely on OA as a meaningful tool for evaluation of performance-based technical matters. As a result, QA's effectiveness was significantly impeded. For example:
The DSA team concluded that QA did not adequately follow up e
on open/ overdue issues to ensure that they obtained senior line management sponsorship for appropriate response to their findings and concerns. This was evidenced by the large backlog of open QA findings, and the growing average days that a finding remained open. Since this is clearly a management issue, CNS management must determine what, in the way of QA follow up, works best for them. In either case, the bottom line is that response to QA issues has been deficient and must improve.
Furthermore, QA had a weakness in identifying repeat findings e
to management. CNS performance has been characterized by repeat failures / events that have not been highlighted by QA even though they were identified in audit reports. If QA has pointed out repeat performance deficiencies to the line organization, their efforts were unsuccessful, and rather than emphasize the repeat nature of the deficiencies QA has typically closed the finding if a previous finding or NCR was still open.
As evidenced by the above, in the instances where QA e
identified poor performance in the line organization, response by the line organization was inadequate, and characterized by defensiveness, resistance to findings, and slow response, There was no evidence that SRAB challenged QA to achieve a e
higher level of performance nor did it bring performance deficiencies to the attention of executive management.
47
i t
Cooper Nuclear Station Diagnostic Self Assessment 2.4.5 Ineffective Management Systems Management systems appear to be weak at CNS. A consistent system for the comprehensive monitoring of plant performance, comparing it against industry standards, then holding responsible management accountable for substandard performance has not been observed. Neither collective nor individual department level indicators or management tools are available to routinely and systematically assess performance toward established goals.
During many management interviews it was stated clearly that these management tools were not used. Similarly, initiatives for correction or improvement frequently languished due to a similar lack of control. Some examples include:
important programs, such as cobalt reduction identified by the e
radiation protection self assessment, Integrated Enhancement Program progress / updates, and initiatives stemming from the 1992 SRAB self 2
assessment were not accomplished because the commitments are either not systematically tracked and/or managers held accountable.
important maintenance parameters are not tracked and controlled in a e
systernatic way.
Existing backlogs of CR's TPCNs, PCNs, PTMs, MWRs, would benefit e
i from a systematic management approach to assure that management expectations on prompt processing and backlogs are being consistently met.
Monthly radiation protection reports with important management i
e control information is circulated serially, requiring time to complete the review and the distribution is followed by no clear accountability.
In summary, overall corporate performance monitoring was determined to j
be weak. Furthermore, the level of skills necessary to set up and manage these systems are not apparent nor is there any training being conducted to provide these skills. Strong role models, which would provide expectations f
regarding the need for these systems have also not been evident. Since these are universal business skills not unique to nuclear power, it could be l
expected that the corporate leadership would ensure that CNS is practicing them, but again that leadership was not evident.
48
}
Cooper Nuclear Station Diagnostic Self Assessment c
2.4.6 Inadequate Use of Standard Human Resource Concepts The Nuclear Power Group has not effectively utilized or developed more contemporary human resource and organizational development (HR/OD) methods to assure strong management and supervisory performance. This has resulted in management performance weaknesses throughout the CNS organization, and has contributed to deteriorating plant performance.
Furthermore, the corporate HR/OD resources appear inadequate to meet the need. There are individual performance issues that have contributed to many aspects of the current performance problems at CNS, whether it has been workers choosing against their managers' expectations and not using i
I procedures, or supervisors failing to plan, communicate, maintain accountability or follow administrative procedures; or managers choose to perform in the reactive mode, ignore industry changes or do not properly incentivize their organizations. HR/OD tools that could have helped correct this category of problems were not generally made available to the personnel at the site or, if present (such as the performance review program) not used with enough skill to affect improved performance.
4 Adding to the prob!em was that the corporate HR organization is located over 120 miles from the site with only one clerical person present at the plant. This in spite of the fact that one-third of the company's employees are at CNS. Further, interviews have indicated that the company does not to possess a significant OD capability.
Management and supervisory training was available from the corporate HR organization, but has not been utilized to a significant degree by the site organization. Interview data implied that HR assistance initiatives made toward the site were rebuffed, ignored, or given low priority. During an interview, an I & C foreman indicated that he has had three to four days of i
supervisory training since assuming his role five years ago. Most managers 4.
have not received any supervisory or management training.
i Based on interviews, the selection process for filling management positions has been biased toward technical competence with no apparent strong analysis of management potential. In the case of supervisor selection, there remains a strong seniority component. Currently available technology for targeted selections for filling vacancies have generally not been used, reducing the likelihood of selecting the best talent for open positions from 49
Cooper Nuclear Station Diagnostic Self Assessment t
4 either inside the District or, up until the most recent past, from outside sources.
Position incumbency appears unusually long. Rotation for career development is limited. During interviews, some managers stated that there were incumbents who were reluctant to assume their current positions in the i
first place and had made those concerns known in the selection process.
The team was informed that there is a performance review program in place, but interview feedback indicated that, while the forms are completed, real use of the program to improve personnel performance is scattered and ineffective. Discipline does not appear to be used as a toolin shaping j
performance.
2.4.7 Ineffective Planning and Prioritization l
i l
CNS is weak in the organizational discipline of planning and execution of plans. This has been a significant contributor towards their difficulty in achieving improvement and solving long term problems, in general, activities are not well planned, contributing to an observation that programs and corrective actions are initiated but not carried through to completion.
Current programs and management controls have not required or promoted the use of strategic or tactical planning. Existing planning and scheduling systems have been ineffective. As previously noted, management has fostered an environment in which production and work accomplishment has usually been given the first priority with pressure on the staff to achieve results with minimal delay. Non-routine activities are frequently planned orally and launched without the benefit of a thorough plan. Activities were observed to "out run" plans before planning was complete or even begun.
Examples include:
Initially, there was inadequate planning and work instructions for e
correction of improperly engaged spade lugs in safety related terminal blocks.
There was a poorly developed plan based on informal, verbal criteria e
for selection of operating experience items to review in response to an NRC Confirmatory Action Letter.
50
)
4 e
a Cooper Nuclear Station Diagnostic Self Assessment The initial NPPD response to NRC concerns regarding preconditioning e
1 was not comprehensively planned. This resulted in ineffective field direction, communication of management expectations and management oversight. Examples of proceduralized preconditioning-l conditioning were observed that were not properly nor expeditiously dispositioned in accordance with management's expectations.
e The new corrective action program was implemented in April 1994,-
however ownership, accountability, goals, and vision for the long-term program has not been clearly established.
The CAP program manager and root cause team leader organization e
have been staffed but the group has not been institutionalized via charter statement or program plan.
Indications are that the development of a new work control program is j
e
{
proceeding without a comprehensive, management accepted project plan.
Task assignments and parameters for investigation and response to plant problems with valve lineup discrepancies and motor-operated l
valve testing discrepancies were unclear. The vice president, nuclear
{
or the site manager had to intervene in both cases to ensure that safety issues were addressed and adequate plans developed.
e The absence of a centralized maintenance work scheduling process has resulted in additional equipment out of service time, lost 4
maintenance production hours, and increased maintenance backlog.
The lack of a work scheduling process also has placed a heavy
]
administrative burden on the shift supervisor to coordinate work.
Strategic, or long-range planning, was also noted to be historically weak.
Recently there appears to have been improvements in this area. In response o
to a growing awareness of performance problems management initiated a Near Term Integrated Enhancement Program lEP which represented a plan for near term improvement in specific areas identified as deficient. The program was published then updated in May 1994. In parallel to this effort, CNS management recognized the need for a more comprehensive, longer-term focus in today's nuclear environment, and developed a four-year business plan. The actions delineated in the IEP were integrated into the 51
Cooper Nuclear Station Diagnostic Self Assessment Business Plan. In general, the new plan represented a good first step in long-range planning; however, it failed because:
A systematic practice did not hold responsible managers accountable e
for timely completion of their respective actions.
Branch Business plans, referenced in the Business Plan were not developed with appropriate staff involvement and buy in, and with sufficiently detailed tasks and responsibilities assigned to assure accountability.
The " EXPECTED RESULTS" and " PERFORMANCE MEASURES" e
sections of the plan were not specific enough to enhance accountability.
The plan did not get resource loaded along with the base line work load, and with the budgeting and control process firmly linked to the long range planning process to ensure that resources are available for improvement.
In summary, the team concluded that the IEP/BP was not fully successful due to the above factors. Further, it is the team's understanding that the business process is currently undergoing significant revision. The team did not have an opportunity to assess this new process.
2.4.8 Potentially Degraded Safety System Capability Severalissues identified by the station and the DSA team have the potential to reduce the margin of safety in important plant systems. Although some of these issues have been, or are currently being addressed by the station on an individual basis, they currently could represent a potential reduction in the margin of safety when viewed in the aggregate. The individual areas include the following:
(1)
Preconditioning of equipment prior to performance testing may have corrected performance problems before they could be identified. In June 1993, the NRC identified a concern that prior to conducting secondary containment integrity tests, the station was performing preventive and corrective maintenance with the objective of passing the test, thereby precluding any opportunity to identify potential 52
Cooper Nuclear Station Diagnostic Self Assessment J
degradation that may have occurred prior to the test. Subsequently, in May 1994, a similar situation associated with emergency diesel generator load shed testing was identified. In both cases, system performance deficiencies degradations were revealed when followup tests were performed in the absence of preconditioning. Since this time, additional examples of both procedurally established and unintentional preconditioning have been identified. Although actions have been taken to alert station personnel to identify and prevent preconditioning in the future, a review of station procedures is underway to identify additional cases, the DSA team found that insufficient guidance exists for evaluating these cases to determine 1
whether the potential for reduced system capabilities exists due to past practices.
)
{
(2)
Implementation and adequacy of the status control process does not ensure systems and components are controlled in the condition intended. Examples include the following:
many examples of recently identified valve and switch e
mispositioning events i
valve lineup sheets have many known deficiencies clearance order program implementation problems have rerulted e
in components being out of their required position and are violations of procedure requirements in addition, in May 1994, a temporary blocking device (tie-wrap) was found installed on an undervoltage trip assembly of a non-essential 480 volt motor contro center feeder breaker that rendered the load-shed function inoperable and could have potentially resulted in overloading of the emergency diesel generator. The blocking device was installed by procedure during the Spring 1993, refueling outage, but was inadvertently left in place due to lack of a procedure step to remove the device. The station conducted a special review of procedures that identified and corrected additional similar procedure j
deficiencies.
(3)
There have been several recent events or adverse conditions at the station that indicate that lessons that should have been learned from 53
l Cooper Nuclear Station Diagnostic Self Assessment 4
in-house and industry operating experience have not been incorporated into the station's operation. These situations have been caused by failure to conduct thorough root cause investigations, thoroughly evaluate industry operating experience, or implement enduring corrective actions. The station modified its problem j
reporting system, established a corrective action program manager, conducted root cause training, obtained the services of root cause analyses coaches / mentors, and is conducting a review of actions taken in response to some industry operating experience documents that date back to 1982. Nonetheless, there is a lack of rigor in recent root cause analyses, corrective actions that insufficiently address the root cause, unclear responsibility and accountability for the corrective action program, a large backlog of incomplete root cause analyses and corrective actions, questions regarding the adequacy of the industry operating experience review scope, and lack of management follow-J through on the commitment to upgrade the corrective action program.
(4)
The Station and corporate engineering organizations have not provided timely support to the station. Examples of issues that could potentially reduce the margin of safety include the following:
Ongoing monitoring of the reactor equipment cooling piping had not been performed to detect continuing intergranular stress corrosion cracking (IGSCC) caused by previous system chemistry, resulting in the need for extensive system inspections when a leak recently developed.
Only nine design criteria documents have been completed since a reconstitution effort began in 1986. In addition, activities to control station design are not sufficient to ensure analyses are based on correct and current design information; because, in part, many system engineers are unaware of how to locate design basis information.
SORC approved MWRs were sometimes used to expedite modification to the plant. Instances were identified where the subsequent design change package corrected design errors in the MWR-implernented modification. Some design calculations were not preoared until the modification had been installed.
54
1 1
Cooper Nuclear Station Diagnostic Self Assessment e
The station identified deficiencies in the localleak rate test program that resulted in insufficient verification of the integrity of more than 50 containment penetrations. The DSA team j
identified lack of an adequate basis for acceptance criteria and valve stroke times contained in the pump and valve in-service d
testing program, Defic!encies were identified in the control of vendor manuals.
e In addition, about 87 safety related. vendor manuals have not been reviewed to identify preventive maintenance requirements for associated components. A sec,ni teview is required for about 90 additional manuals due ta at inadequate first review.
Some changes in station configuration control are not e
adequately reviewed or controlled to ensure the station configuration reflects station design. Examples include several hundred station-identified drawing discrepancies, relay settings that are not in accordance with current design calculations, standby gas treatment check valves that have been removed, drawings that do not identify expected valve positions, drawings that show valve positions that differ from valve lineup checklists, and procedures that permit shift supervisors to change valve lineups from those shown on drawings.
(5)
Work activities on plant equipment are frequently started before a fully planned work package is available, and without first determining if other related work activities should be performed concurrently. This resulted in excessive system outage durations since systems are repeatedly removed from service because no work was able to be performed in accordance with vendor specifications due to insufficient procedural guidance and inadequate work plans. It was noted that i
these problems may be related to adverse trends over the last three years in HPCI system and diesel generator system unavailability.
(6)
Maintenance is not consistently performed to assure equipment availability. Previous maintenance activities have resulted in nonconforming conditions, degraded plant equipment, increased out-of-service time, and rework. Examples include recent RHR pump overhauls using special instructions in place of approved procedures, replacement of emergency diesel generator components without a 55
4 Cooper Nuclear Station Diagnostic Self Assessment L
procedure, A160 volt circuit breaker misalignment problems, and rework to adjust the service water pump impeller clearance.
Some long-standing equipment problems have not been identified for
- corrective action. In addition, the team found a number of station-identified problems on important equipment that represent a potential challenge to plant operations. Examples include continuing problems with the main turbine bypass valves, excessive silt in the service water system that is compensated by operation of shutdown cooling with full service water flow
. and throttled reactor coolant flow (through a valve that isn't designed for throttling), silting that plugs instrument sensing lines, drywell sump level switch reset problem, excessive seat leakage on a reactor feedwater pump that necessitates closure of a manual valve and extra demands on operators, spurious actuations of the standby gas treatment system fire detector resulting in manualisolation of the deluge valve and the need for local operator action in the event of a fire, and unexpected opening of HPCI, RCIC, and core spray system pump minimum flow valves during surveillance l
tests.
2.4.9 Additional Observations i
2.4.9.1 Resources CNS appeared to have had the financial resources available to conduct a quality operation. Staffing has been appropriately studied and is adequate in most areas. Where deficiencies were noted, appropriate actions are being taken with the possible exception of short term responses to needs j
generated by an accelerated event investigation program. Funding appears to have been adequate. The Electric Utility Cost Group (EUCG) three year rolling average O&M costs, less fuel, $/ installed KW, placed CNS in the l
second quartile, slightly less than the industry median. Senior plant management stated that funding has been adequate. Interviews of 2
corporate financial managers indicated that the budgeting process generally provided the nuclear operation with requested funding.
With regard to staffing, a recent study indicated that staffing tended to be slightly low in the site engineering group and in maintenance. This was based on steady state, non-outage expected staff levels reported in the l
"1994 Staffing Analysis Report" by Tim D. Martin & Associates, Inc. The engineering management indicated that engineering staffing increases were 56
9 Cooper Nuclear Station i
Diagnostic Self Assessment in progress. Maintenance staffing was more complex however, since the study indicated that maintenance was low, and in the judgment of the DSA team, based on ', 'oric backlog performance and current planning and scheduling issue.. Mere has been no apparent significant shortage of mechanics. On the other hand, staffing for the planning and scheduling function may not be sufficient. Recent expansion of the operating experience assessment function has locally stressed station and corporate staffing. In i
summary the team concluded that, although the staffing study indicated only localized shortages, the current performance improvement efforts will-probably place significant additional stress on the organization. However, without the benefit of effective work planning and prioritization and good long range planning, resource utilization effectiveness could not be determined.
l 2.4.9.2 Budget and Control l
The team concluded that the systems in place for budget and control are conventional and adequate to support improving performance if coupled to
[
the new Business Planning process. Budget and control activities have been j
conducted in a manner not atypical to other facilities. Financial requirements are generated at appropriate levels within the organization and rolled up to the corporate level. Reasonable challenges are given throughout the j
process. Reports containing actual O&M expenditures, on a booked basis, versus budget are compiled monthly by a site accountant and forwarded to i
the responsible managers. Nuclear normally budgets an O&M annual l
contingency of approximately 4%
4 j
Capital budgeting was also determined to be conventional. The budget was typically not fully spent due to limitations in the execution of spending plans.
Carry over of unspent capital was practiced giving greater assurance that funding for necessary improvements and repairs was available.
As mentioned previously, funding for the nuclear program appeared to be adequate for normal activities but the budget and control process is not well 4
tied to the long range planning process. Instead, it appears that resource i
planning has traditionally been based on historical performance with programmatic escalators added in.
3.0 ROOT CAUSES l
57
- - ~
i t
Cooper Nuclear Station Diagnostic Self Assessment 3.1 Senior management has been ineffective in establishing a corporate culture that encourages the highest standards of safe nuclear plant operation.
Station and corporate management has been ineffective in fostering a heightened sensitivity and awareness to issues that affen neclear safety.
Weaknesses in nuclear safety consciousness have res'ated in station programs and processes that do not promote the high;rd str.ndards of nuclear plant operation. Key elements of a nuclear culture - continuous improvement, learning from experience, conservative decision making and a questioning attitude - were found to be lacking at CNS. The not result was that long-term performance became governed more by the bounding conditions of problems, often regulations, rather than being under the careful guidance of a management team with high performance standards. These weaknesses were evident in many of the performance issues identified during the assessment including:
work processes and procedures that favor production over doing it in accordance with industry standards 1
programs and processes that are intended to meet requirements rather than high performance standards a lack of critical review and oversight by all levels of station and e
corporate management.
Station and corporate management failed to establish rising standards for I
personnel and plant performance that is evident throughout the nuclear industry. Complacency, exhibited by programs and processes that "do business the way it has always been done," has contributed to the station's inability to keep pace with the nuclear industry's rising standards of excellence. Lack of corporate support in strategic business planning, engineering, human resources and critical assessment of performance further demonstrates weaknesses in senior management understanding of and sensitivity to nuclear plant operations.
58
Cooper Nuclear Station Diagnostic Self Assessment 3.2 Senior Management did not establish the vision supported by adequate direction and performance standards to improve station performance.
The team found that the CNS management was focussed on immediate, real-time issues and frequently did not apply longer range vision, provide the necessary levels of direction with clear ownership and strong contemporary standards of performance to plant programs and problems.
Failure to establish and enforce high performance standards at the station contributes to many of the performance weaknesses observed.
Low performance standards often led the CNS staff to make decisions that expedite the resolution of the issue at hand without full J
consideration of the long term impact on safe and reliable plant operation.
Combined with those low standards, and a lack of vision and direction has helped perpetuate unsuccessful programs and weakly resolved problems. Managers, caught up in immediate activities, have failed to recognize the need for broader, longer range actions. Many issues were exacerbated by narrowly framed solutions. Lack of performance standards resulted in shallow technical evaluations and a lack of recognition of, or acceptance of, long-term problems. The team found high levels of maintenance re-work and excessive reliance on skill-of-the-craft for field problem solutions. In several cases, fundamental quality requirements such as torquing, foreign material exclusion, and vendor instructions were not applied to safety related maintenance. Ongoing problems with plant and system status control, procedure quality and adherence, the lack of a strong work control program, weak industrial safety practices, ineffective independent oversight and quality assurance program, and a general problem of inadequate programs that do not meet regulatory requirements, all reflect standards which have not kept pace with industry practice.
Mid-and long-range planning has only occurred on a limited bases.
The NPG Business Plan has articulated an organizational vision which emphasizes high safety standards, reliability, and cost effective production. Although management has had a growing awareness of a less than adequate performance and has begun to apply their vision of 59
4 Cooper Nuclear Station 4
Diagnostic Self Assessment l
desired performance by way of the Integrated Enhancement Plan and the NPG Business Plan, implementation of these plans have suffered from lack of accountability and have also been overtaken by plant
~
problems and restart activities.
l Corporate management, except for the vice president, nuclear, has e
had little apparent involvement in helping set the direction for the NPG.. Corporate management has not demanded strong oversight of NPG activities, and has been ineffective in providing direction and support in areas where the' corporate staff should be capable, such as r
human resources and organizational and management development.
e The lack of vision and direction has also extended into program development and implementation. For example, many of the plant programs (ISI/IST, Appendix J, engineering programs for vendor manuals, equipment performance monitoring, etc.) have been l
identified as problematic by the station and were included in past l
improvement plans. Few of these have had extensive or structured input from management which reflects their published vision and expectations for performance. Insufficient management direction has been the primary cause for ineffective and untimely engineering support. Although existing programs contain management expectations for engineering duties, management's assignment of reactive workloads to engineers has effectively precluded the staff i
from fulfilling these expectations of dealing with the routine workloads and improvement efforts.
3.3 Ineffective monitoring and lack of critical self assessment have prevented management from recognizing program and process deficiencies and making the necessary improvements.
Many of the performance problems observed by the team and other external organizations could have been identified by effective management monitoring and self assessments of station performance. Examples of this include:
. ineffective engineering support evidenced by their inability to e-recognize and correct system and equipment degradation, excessive backlogs and delays in completing important work such as design basis documents and vendor manual upgrades.
60
Cooper Nuclear Station Diagnostic Self Assessment Failure to recognize long-standing equipment problems noted during e
maintenance, such as the RHR heat exchanger primary water leak.
Excessive rework, which contributed to increased system and o
equipment unavailability, caused by a lack of. monitoring of work in progress, not providing adequate OC, and poor maintenance work procedures and practices.
Lack of monitoring and feedback by the line organizations to the e
training department regarding the quality of, or lack of, training.
ineffective corrective action program monitoring and adjustment..
e Independent quality oversight by NPPD has been similarly ineffective. The SRAB has failed to provide oversight by not challenging QA, not recognizing plant performance deficiencies, and not correcting recognized weaknesses in its own performance. Quality Assurance oversight has been ineffective because of its inability to detect performance deficiencies, inability to influence line management when weaknesses were identified, and an inclination toward compliance oriented performance.
3.4 An ineffective management development program has resulted in a lack of management and leadership skills necessary to ensure that strong leaders and managers are available to fill key corporate and station positions.
NPPD has not adequately addressed the management developmental needs of the organization and its employees. This is evidenced by:
The lack of a human resources professional presence at CNS despite e
i the fact'that one-third of NPPD's employees work at the site.
Supervisory and managerial selection is biased toward technical e
versus managerial abilities. Once placed into a supervisory position, minimal supervisory training is provided. The training that is provided is not based on any assessment of the individual's needs.
e Skills were lacking for conducting comprehensive monitoring of plant / departmental performance, comparison of this performance 7
61
1
' Cooper Nuclear Station Diagnostic Self Assessment against established standards, and holding the responsible management accountable.
There is no apparent succession plan in place for developing a cadre of potential future leaders, managers, and supervisors.
4.0 EXIT MEETING An exit meeting was held on August 19,1994. The exit presentation material is provided at Appendix C.
1 4
j 62
)
l
APPENDIX A COOPER NUCLEAR STATION DIAGNOSTIC SELF ASSESSMENT TEAM MEMBERS Team Manager:
Ralph E. Beedle Assistant Team Manager:
Donald A. Beckman President Beckman and Associates, Inc.
Operations and Training:
David R. Morris Director - Nuclear Assessment Clinton Power Station 1
Wade H. Warren Technical Training Supervisor Farley Nuclear Plant Robert J. Barrett General Manager - Operations James A. Fitzpatrick Nucleai Power
)
Plant Maintenance and Testing:
Richard P. Clemens Outage Director Fort Calhoun Station Steven F. Verrochi Manager, Mechanical Maintenance Division Boston Edison Company A-1
i Cooper Nuclear Station Diagnostic Self Assessment Engineering and Technical Support:
Robert G. Azzarello Director, Design Engineering Waterford 3 Steam Electric Station Charles R. Brooks Program Manager Institute of Nuclear Power Operations Joseph L. Connolley Supervisor - Test and Performance Engineering Fort Calhoun Station Daniel P. Kimball Manager, Safety Review Group Catawba Nuclear Station Gary Welsh Assistant Team Manager Institute of Nuclear Power Operations Management and Organization:
John Doering, Jr.
Chairman, Offsite Review Committee PECO Energy Company i
Steven B. Eisenhart Nuclear Specialist Virginia Power Harry Kister Senior Consultant Beckman and Associates, Inc.
A-2
1 J.
e 4-l Cooper Nuclear Station i.
- Diagnostic Self Assessment 4,
j '
Robert D. Ryan 1
Assistant Team Manager l
Institute of Nuclear Power Operations 4
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APPENDIX B l
'I NPPD/CNS ORGANIZATION 1
i CHARTS i
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8 9
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I APPENDIX C i
EXIT PRESENTATION f
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COOPER NUCLEAR STATION DIAGNOSTIC SELF ASSESSMENT l
t TEAM DEBRIEF I
l Diagnostic Self Assessment Team c1
l i
DESIGN CONTROL Design Basis Calculation Control Change Processes i
l i
Diagnostic Self Assessment Team c2
CONTROL OF STATION CONFIGURATION Undocumented Modifications Drawing Discrepancies Controls for Equipment Alignment l
t I
l f
l Diagnostic Self Assessment Team c3 1
i
INEFFECTIVE ENGINEERING SUPPORT 1
Roles and Responsibilities 1
System Engineering Activities Corporate Engineering Activities i
Monitoring of Performance e
i Diagnostic Self Assessment Team c4 l
1 r
DEFICIENT EQUIPMENT TESTING AND MAINTENANCE PROGRAMS i
Containment Leak Rate Testing In-Service Testing Vendor Manuals 1
1 Diagnostic Self Assessment Team cs
I CORRECTIVE ACTION PROGRAM CNS actions completed:
Single reporting system, low threshold Training, mentors / coaches
-CAP manager /CRT leaders Assessment Team
Conclusions:
Backlog challenging l
Lack of rigor Corrective actions vs. root cause Accountability and vision l
Diagnostic Self Assessment Team a
cs i
I
INDUSTRY OPERATING EXPERIENCE CNS has not benefited from the experience.of others BWR thermal stratification Similar event unlikely at CNS Occurs during December 1993 scram Not detected Additional industry events CNS recogmzes l
i l
Diagnostic Self Assessment Team c7
WORK CONTROL Inadequate Work Planning Resulting in:
L Increased out-of-service time on equipment 4
4 Work not performed in accordance with vendor specifications t
Tendency to work around controls due to lack of independence i
i i
Diagnostic Self Assessment Team ce i
i
t WORK CONTROL i
Inadequate Work Scheduling Resulting in:
Equipment removed from service over and over within short time frame Work is approved on first come, first serve basis No centralized review of work for priority i
i i
Diagnostic Self Assessment Team C9 l
t i
l
P WORK CONTROL i
i Long-standing Equipment Problems not Tracked Supervisor Tied Up in Making Process Work Outage Risk Assessment Continually Challenged j
Increasing Backlog f
l I
t l
Diagnostic Self Assessment Team c10
r WORK CONTROL PLANT OPERATIONS 4
Over-reliance on the SS to manage the control of work Over-reliance on the SS to manage the configuration of plant systems l
Lack of LCO Tracking l
Inability to adequately assure Defense-in-Depth of key safety functions j
Lack of Pre-planning Diagnostic Self Assessment Team cu
QUALITY OF MAINTENANCE ACTIVITIES l
l Rework Required i
Non-conforming and Degraded Plant Equipment i
Increased Safety System Unavailability Inconsistent Quality Verifications Insufficient QC Independence l
l Diagnostic Self Assessment Team c12
LONG-TERM EQUIPMENT PROBLEMS Willingness to Live With Problems / Work Arounds RHR Heat Exchanger Leak REC Piping Degradation RHR Motor Bolting Service Water System Silting Long-standing Temporary Design Changes l
Failure to Follow Through on Root Causes Diagnostic Self Assessment Team cu
l PROCEDURE AND INSTRUCTIONS Inadequate Procedures Work on S/R Equipment Without Procedures Vendor Specifications / Requirements Not Included Procedure Change Process Procedural Adherence j
i l
Diagnostic Self Assessment Team c14 i
?
1
-t INDUSTRIAL SAFETY Standards not Enforced 1
l Work Expediency j
Work Practices 4
Scaffolding and Fall Protection Use of Personal Protective Equipment j
i Clearance Order System Deficiencies I
Performance Indicators i
Diagnostic Self Assessment Team cis
CONSERVATIVE COMPLIANCE AND PROGRAM ADHERENCE Activities Conducted are Inconsistent on Communicating a Conservative Approach l
Programs in Place Work Around Other Programs i
Self Assessment Program Workers Unsure of Expectations t
Diagnostic Self Assessment Team cis l
l
\\
[
e i
TRAINING PROGRAMS
=
Lack of Management Monitoring / Assessment 4
Lack of Management Followup of Expectations Lack of Quality Improvements t
l i
Diagnostic Self Assessment Team c17 I
i
MATERIAL CONDITION b
Not significant as an issue in itself l
Significant to the extent material condition problems result from other master issues and root causes Work Control Standards Weak Processes j
i l
l l
Diagnostic Self Assessment Team cia
1 STATUS CONTROL l
l Weak Standards Deviated from Existing Clearance Order Requirements Clear Standards Did Not Exist for Who Operates Valves i
Strong Ownership Needed i
i i
i By Operations i
Diagnostic Self Assessment Team C19
1 OPERATIONS AND TRAINING t
POSITIVE ATTRIBUTES i
Demonstrated Aggressive Cleanup Effort to Minimize Contaminated Areas l
l l
Simulator Fidelity - Pride of Ownership i
l Demonstrated Efforts and Programs in l
Place to Monitor and Improve Operational Conununication 1
Diagnostic Self Assessment Team c20
f RESOURCES FINANCIAL i
EUCG Data Interview Data l
Sufficient Financial Resources 1
" Accommodating" Budget Reviews i
MANPOWER j
Tim D. Martin Studies Found Deficiencies i
Staffing is Receiving Appropriate Attention (Watch Area)
Diagnostic Self Assessment Team cn
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HUMAN RESOURCES l
CONCERN Human Resource and Organizational Development l
(HR/OD) tools have not been used to improve individual and organizational performance.
Corporate support for HR/OD is not strong.
The On-site HR Support is One Person Management / Supervisory Training Management / Supervisory Selection Long Incumbencies Performance Review Program Change Management I
Diagnostic Self Assessment Team cu
l PLANNING CONCERN CNS is deficient in the organizational discipline of planning and execution of plans.
SELECTED EXAMPLES:
i Numerous difficulties in implementing the Corrective l
Action Program could have been avoided by planning.
Development of a new work control program is being done without a comprehensive plan.
i Plans for needed maintenance program improvements, such as procedures, have not been developed.
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Diagnostic Self Assessment Team c23
PLANNING t
l SELECTED EXAMPLES (continued) t No plans exist for a cobalt reduction program.
Business planning is only now beginning.
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_.. _._ _. _. _ _. ~.. _. _. _ _ _ _ _ _ _.. _. _ _ _ _ _.. _. _
i MANAGEMENT SYSTEMS
(
t l-CONCERN l
Management systems appear to be weak at CNS.
A systematic means is necessary to:
have clear assignment of management i
responsibilities establish clear and challenging goals measure and report performance against goals establish EFFECTIVE management accountability forums track and follow through deficient performance until corrected.
i Change Management Diagnostic Self Assessment Team c2s
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SELF ASSESSMENT 4
CONCERN 1
Self assessment at CNS is sporadic.
i
. Adequate Program Exists I
Quality of Assessments 4
I Failures to Self Assess j
Management Sponsorship t
CNS lacked the requisite self-critical attitude.
I FitzPatrick Response Diagnostic Self Assessment Team c2s 7.
INDEPENDENT OVERSIGHT CONCERN The independent oversight organizations failed to perform their missiens. Declining performance was highlighted by an external oversight function.
SORC/SRAB Failure i
Membership Self Assessment / Learning l
Challenge l
Diagnostic Self Assessment Teant c27
INDEPENDENT OVERSIGHT CONCERN (continued)
QA Failure I
Compliance vs. Performance Resources Interface with Line Management Challenge i
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SYSTEMS FUNCTIONALITY CONCERN Systems indicate a potential reduction in MARGIN OF SAFETY may exist Preconditioning l
Plant Status Control Corrective Action Program Configuration / Design Control Work Control Diagnostic Self Assessment Team C29 I
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ROOT CAUSES Senior Management is ineffective in i
establishing a corporate culture that l
encourages the highest standards of safe nuclear plant operation.
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Diagnostic Self Assessment Team c30
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4 ROOT CAUSES i
i Senior Management did not establish the vision or provide direction supported by high performance I
1 i
standards to improve station performance.
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ROOT CAUSES l
Ineffective monitoring and critical self assessment prevents management l
l from recognizing and taking action to i
correct program and process deficiencies.
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APPENDIX D ABBREVIATIONS AC alternating current ADAM atmospheric dose assessment model ADV atmospheric dump valves AEOD Office for Analysis and Evaluation of Operational Data AO auxiliary operator AOV air-operated valve ASME American Society of Mechanical Engineers BWROG Boiling Water Reactor Owners Group CAL Confirmatory Action Letter CAP Corrective Action Program CCW component cooling water system CEO Chief Executive Officer CFR Code of Federal Regulations CM corrective maintenance CNS Cooper Nuclear Station CO clearance order CRG Condition Review Group CRT Condition Review Team CST condensate storage tank CV control valve DBD design basis documentation DC direct current DE diagnostic evaluation DEH digital electro-hydraulic DG diesel generator DOG deviation from outage guidelines dp or d/p differential pressure DR deficiency report DSA diagnostic self assessment DSAT Diagnostic Self Assessment Team ECCS emergency core cooling system EDG emergency diesel generator (DG)
EDSF electrical distribution system functional inspection EOP emergency operating procedure ESF engineered safeguards features EUCG Electric Utility Cost Group D-1
Cooper Nuclear Station Diagnostic Self Assessment FO fuel oil FSAR final safety analysis report GE General Electric (Corp)
GL generic letter HPCI High Pressure Coolant Injection HPES Human Performance Evaluation System HR Human Resources I&C Instrumentation and Controls IEP Integrated Enhancement Plan IGSCC Intergranular stress corrosion cracking IN information notice INPO Institute of Nuclear Power Operation IPE individual plant examination ISI inservice inspection IST inservice testing JCO justification for continued operation JPM job performance measures KW-kilowatt LAO licensed auxiliary operator LCO limiting condition for operation LER licensee event report LLRT local leak rate testing LOCA loss-of-coolant accident LOOP loss of offsite power LPCI low pressure coolant injection MIS management information system MOV motor-operated valve MS main steam (system)
MSIV main steam isolation valve MSLB main steam line break MWR Maintenance Work Request MSSV main steam safety relief valve D-2
f 3
Cooper Nuclear Station Diagnostic Self Assessment NPG Nuclear Power Group.
NPPD Nebraska Public Power District NPRDS Nuclear Plant Reliability Data System NPSH net positive suction head NRC Nucle'ar Regulatory Commission NRR Office of Nuclear Reactor Regulation OD organizational development
.OE operating experience OER operating experience review O&M Operations and Maintenance PCS primary coolant system PCN procedure change notice PM preventive maintenance PMWT
. primary makeup water tank PRA probabilistic risk assessment PTM plant temporary modification OA quality assurance QV quality verification RB reactor building RCM reliability-centered maintenance REC reactor equipment cooling RFP reactor feed pump RHR residual heat removal system RCIC Reactor Core Isolation Cooling RPS reactor protection system RPV reactor pressure vessel RR reactor recirculation (system)
.SALP Systematic Assessment of Licensee Performance SE shift enginee.
SER Significant Euat Report SFHM spent fuel handling machine SGTS standby gas treatment system Si special instructions SORC Station Operations Review Committee D-3
Cooper Nuclear Station Diagrastic Self Assessment SRAB Safety Review and Audit Board SRM startup rate monitor SS shift supervisor STO switching and tagging order SW service water system TBV turbine bypass valves TDC temporary design change TOL thermal overload TPCN temporary procedure change notice TS Technical Specifications UFSAR Updated Final Safety Analysis Report USQ unreviewed safety question UVTA undervoltage trip assemblies VM vendor manual VOTES valvo operation test evaluation system VP Vice President WO work order D-4
9/7/W DRAFT NOTICE OF VIOLATION COOPER NUCLEAR STATION 9414-01 10 CFR Part 50, Appendix B, Criterion III, states, in part, that "[m]easures shall be established to assure that... the design basis... are correctly translated into... specifications, drawings...
These measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled."
1.
The Cooper Nuclear Station Updated Safety Analysis Report, Appendix F, "Conformance to AEC General Design Criteria," sates, in part, the "...
the purpose of this appendix [is] to show that the decign and construction of the Cooper Nuclear Station has been performed in accordance with these general design criteria."
Contrary to the above, Flow Diagram No. 2028, " Reactor Building and Drywell Equipment Drain System," contained safety-related isolation valves but was not included on the safety-related drawing list as of July 1, 1994, and some safety-related components were not included on the drawing.
2.
Draft General Design Criteria, Criterion 53, July 1967, in accordance with Appendix F to the USAR, states that "[a]ll lines which penetrate the primary containment and which communicate with the reactor vessel or l
the primary containment free space [were] provided with at least two J
isolation valves (or equivalent) in series."
1.
Contrary to the above, as of May 14, 1994, many penetrations were identified without redundant valving. These penetrations included, but were not limited to, penetrations X-21, X-22, X-25, X-29E, X-30E/F, X-33E/F, X-209A/B/C/D, and X-218.
2.
Contrary to the above, as of February 22, 1994, ten manual operated vents, drains, or test connections had single manual valves for containment isolation.
3.
Draft General Design Criterion 1, in accordance with Appendix F to the Updated Safety Analysis Report, states that "... those systems and components of the station which [had] a vital role in the prevention or mitigation of consequences of accidents affecting the public health and safety [were] designed and constructed to high quality standards..."
General Electric Design Specification No. 22All53, " Codes and Industrial Standard," Revision 1, states, in Note 3 of the Appendix, that
"[p]iping, which is an integral part of the primary containment for isolation purposes, shall have at least the same quality and levels of assurance as the primary containment."
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_-Contrary'tk.theabove',thelicenseefailed'todesign,.fabricateand erect approximately 300 containment penetrations to the standards
.specified in USAS B31.7-1969.
9414-02 Technical Specification 4.7. A.2.f.1 states, in part, that " local leak rate tests (LLRT's)- shall be performed on the primary containment testable.-
- penetrations and isolation valves... The total' acceptable leakage for all valves and. penetrations other than the MSIV's is 0.60'La."
1.
. Contrary to.the above, as of May 14, 1994, the licensee failed to-provide for' Type C local leak rate testing of _68 components passing through 54 containment penetrations.
2.
Contrary to the above, as of July 11,'1994, the total leakage for the valves and penetrations that had-never been. tested, with three. tests.
remaining, exceeded the 0.60 La limit allowed by Technical Specifications. The 0.60 La limit was 5.37 scmh (189.60 scfh) and'the leakage for the valves that had never been tested was in excess of 17.66 scmh (623.57 scfh).
3.
Contrary to the above, several instrument pressure switches had not had
' local leak rate testing performed after being isolated from the containment integrated leak rate test.
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GENMAL OmCE P.O box 490. COLUMBUS. NFBRASKA 68002&99 Nebraska Public Power District "Tt4&Ts="
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BONAL.D W. WATKINS Presadant er CSO (400 Se&M96 NIA960040 Jac isry 30,1995 Mr. James M. Taylor Emocutive Director for Operations i
U.S. Nuclear' Regulatory Commission Washington, D.C. 20555-0001 Suhdect:
Response to letter from James M. Taylor to Ronald W. Watkins dated November 29,1994 Hoferences:
(1)
Cooper Nuclear Station Diagnostic Self Assessment, July - August 1994 4
(2)
NRC Special Evaluation Team Report Cooper Nuclear Station, August 15-19, 1994 4
Dear Mr. Taylor,
On September 1,1994 the Nebraska Public Power District (the District) issued a Cooper Nuclear Station (CNS) Diagnostic Self-Assessment Team (DSAT) report which documented the results of an intensive third party evaluation conducted between July 25 and August 19, 1994.
'Ihe purpose of this effort was "to identify areas requiring improvement and to determine the root causes for the station's declining performance."(Reference 1) Subsequent to the issuance of this report, the NRC performed a Special Evaluation Team (SET) inspection to assess the " effectiveness of licensed activities performed by (the District) in ensuring safe operation at CNS, and [to determine) the causes of performance deficiencies."
(Reference 2) In the November 29,1994 transmittal of the SET inspection report, the NRC requested the District to provide its plans for addressing the identified root causes of the deficiencies observed in both the SRT and DSAT reports.
As you may be aware, the District began responding to DSAT and SET issues beibre the reports were published.
In several cases, the reports provided post-documentation of deficaencies that had been recognized through self improvement activities. Forexample, some of the root cause issues and corrective actions discussed in these reports were addressed in the July 28 and August 8,1994 responses to NRC Confirmatory Action Letters (CAL) dated May 27, June 16, July 1, and August 2,1994, and as part of the Nuclear Power Group's (NPG's) Phase 1 Porformance Improvement Plan (PIP). Also, the District provided specific written responses to SET members during and shortly after the SET inspection.
t Most recently, the District's Reply to a Notice of Violation and Proposed Imposition of Civil Penalties dated January 18, 1995 provided further insight regarding how the District is respondmg to performance and hardware concerns. Accordingly, the attachment to this letter reamnne the related information contained in the previous correspondence, and summarizes the corrective actions (taken and planned) that address the stated root causes and related erene.
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- Mr. James M. Taylor January 30,1995 Page 2 of 2 N District has taken, and will continue to take aggressive actions responsive to maanagement, programmatic, and oversight issues that have negatively impacted performance a(the NPG. The progress to date in addressing the issues noted during the SET and DSAT inspections has been significant, and the District believes that CNS is currently performing at a level necessary for a return to power operations.
Should you have any questions concerning this matter, please contact my ofrice.
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R. W. Watkins President and C.E.O.
Attachmenta oc:
Regional Administrator USNRC Region IV NRC Resident Inspector Cooper Nuclear Station NPG Distribution 1
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' Attachment 1 to NLS950040 Page 1 of 6 RESPONSE TO LETTER FROM JAMES M. TAYLOR TO RONALD W. WATKINS DATED NOVEMBER 29,1994 COOPER NUCLEAR STATION NRC DOCKET NO. fio-298, LICENSE DPR-46 N DBAT report identified the following root causes:
1.
Senador rnanagement has been inefHvtive in establishing a tvrporute culture that anaeoeutwes the highest staruhutis of safe nuclearplant openstion.
A badew nuuuwernerst did not establish the vision supportal by adequate dirtstion cuul per$6rwearuv staradants to impetwe station perfornuuuv.
A hand linctive rnonitoring arul lack ofcritiad selfassessenent luweprevental nuoungernent pones rvcqqnizing prignon arul prtxtss depciencies arul making the necessary huyrvoements.
A Aos heetfective rnatuwernent developmentprigrtun has ivsultalin a lack ofinanagernent amant leadership skills necesscuy to ensure that strong laulers and truuusgers arv anneuikable to fill key anporute <md station ponitwns.
N SET cited the following root causes:
1.
Knocutive euul senior numagement of the Nebnxska Public P<nver District mponsible pw the Cooper Nuclear Station fallat to provide the policy, laulership cuul distetton sman==me=y to rnaintain apprvpriate tvrponste wide statukutt of perfannarun NPG nanemoners luut raot effestively implemental csppropriate statukutis and capectations jbr eerponate and station personnel or prtwidal apprvpriate dirwtion cuul supervisioru A
hrp6rweance of CNS had been charneterizal by rnidor pingituns and pnutsses which nearv poorly definal arul lacked the tvenprehensive guidarum necessary to assure eeneristerst and elfective implernentation.
A W660s she Extvption of the DSAIT], NPPD's assessment and independent twerwight annivities luul been ineffretive in prtunptly identifying significcud depciencies which annew subsapsently identifial by regulatory or thini party assessments arul failed to anaeste that lawsons learned frian industry operuting etperience were appropriately sopised at CNS. The Corrective Action Program did not effectively support the
- -%s arul avsolution ofplant problems.
N District has closely examined the DSAT and SET reports both for the root causes and the specific examples addressed in the reports. As previously noted during several public meetings with the NRC, the District has taken or will take broad corrective actions to ensure innamediate and long-term resolution of the issues identified in the subject reports. N discussions below summarize the District's response to the above root causes. Sinco most of this information has been discussed in previous NRC correspondence, only summary p
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- lehrunation is provided. Please refer to the referenced documents for a more detailed dieeussion of the District's plans for corrective action. Also, related root causes have been grouped together to allow for more focused issue-directed responses.
I.
Management Issues (SET Root Cause 1. DSAT Root Cause L 1 and 4) h SET and DSAT root causes listed for this section were important areas of focus during perforrnance improvement efforts, and accordingly, received prompt and extensive change at CNS (as noted in the District's November 7,1994, letter to Mr.
~
L. J. Callanh Continued improvement in management effectiveness is essential for ensuring long term excellence as discussed in the Phase 2 and 3 Performance Improvement Plans. The following discussion addresses areas that contributed tho most to redressing the subject root causes.
e Personnel and Practices. An important initial step during early performance improvement assessment elTorts was to determine current management's ability to effectively and promptly improve performance. As necessary, managers were hired who had higher performance standards.
Several of the individuals hired had significant experience in successfully changing culture and management practices at other utilities. Specifically, the CNS management now includes a now: Site Manager; Quality Assurance Manager; Plant Manager; Safety Assessment Manager; Licensing Manager; Operations Manager; and Plant Engineering Manager. Additionally, an Events Analysis Manager was hired and assigned responsibility for the Operating Experience Review and Corrective Action Programs.
The new managers are providing the organization with leadership role models and I
netting high standards and expectations as the first step in performance improvement.
This will unable the formulation of efTective management development and rotational plans, that will provide the management depth necessary to maintain high performance standards for the long term. Continued assessment of management performance will occur, and additional changes will be made as necessary.
Changing management pera<mnel is only one aspect of ensuring continued performance improvement. The NPG is also making the following changes in basic 3
management skills and processca to better ensure long-lasting high performanec:
Self-assessment and problem solving is being instilled as an inherent management and organizational value such that instinctively, problems are identified and resolved and the generic implications with respect to safety are fully addressed.
Higher expectations for performance and communication of standards both vertically and horizontally within the organization have been established.
Accountability is being fully embraced by all levels of NPG personnel. Excuses for substandard performance on the part of management or staff are not acceptable.
Management has clear responsibility, accountability, and
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J Attaehment 1 to NIE960040 Page 3 of 6 ownership of programs and processes to ensure continuing improvement in levels of performance.
Adherence to detailed objective-based planning (with defined success criteria) developed with the participation, buy'in, and ownership of the organization has been monitored through the impicinentation of the Phase 1 Performance i
Improvement Plan.
1 Steps have been established for ongoing management development. This includes formal training for NPG managers and supervisors in areas such as teamwork and communications, as well as planning for the longer-term establishment of baseline management capabilities.
Also an enhanced succcasion planning process is scheduled for Phase 3 PIP implementation as a means to continuously increase the depth of the management team and to determine priorities for recruiting and development.
Management information systems are being improved to enhance the NPG Management's ability to make critical and timely assessments of stafT performance. Part of this efTort is to evaluate additional software tools for use in such arons as budget, inventory control, and maintenance work management and control.
A parallel effort is the development of meaningful NPG Performance Indicators.
1 Planning. Ownernhip. and Accountabilitv-An important early step that addressed deficiencies in planning, ownership, and accountability was the Phase 1 Performance Impmvement Plan, which clearly identified activitics to be completed prior to restart.
This plan was owned by line management, with accountability for results being enforced by senior management. The Phase 1 PIP Action Plans are complete and have proven to be an essential tool for ensuring NPC staf1's grasp on the skills of ownership and accountability while simultaneously addressing those activities required to restart the plant.
'he Phase 2 and 3 Performance Improvement Plans address activities that will occur shortly after restart and within the next several years, respectively. They are focused on elevating the overall performance of CNS to meet the long-term objectives of emcellence in safety, production, and economics.
The Phase 2 and 3 PIPS, in co1 junction with the NPG budgets and financial plans, will comprise the NPG Business Plan. In total, the Business Plan will provide the baseline management planning document acting as an integrating tool for normal work activities and Performance Improvement Plan actions, and will become the primary planning tool for communicating priorities, allocating resources, and budgeting for the long term.
II.
S==**mir Defielegies of Maior Procrams (SET Root Cause 2)
The following discussion addresses the broad corrective actions that have been implemented to address this root cause. These activities have been incorporated into the Phase 1,2, and 3 Performance Improvement Plans.
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a Attachr.3ent 1 to ML8960040 Page 4 of 6 Conduct of Onerations-Past activities were often compliance-oriented with too much emphasis on production. The new management team, in conjunction with realigning responsibility and accountability for performance results, provides the appropriate balance between production and safety. For example, the NPG has already made significant changes in critical areas including preconditioning prevention, elimination of the ability to bypass the normal engineering process through SORC-approved Maintenance Work Requests (MWRs), and a substantial improvement in personnel ownership of key programs such as work control and surveillance testing.
Additionally, the NPG has increased its focus on meeting both the letter and intent of the Techni al Specifications through an extensive surveillance verification effort and developn ent of allowed outage times for surveillance testing.
rMn Basis In6rmation-The District recognizes that an important contributor to many of the programmatic issues was the CNS staffs reliance on the correctness of the initial plant design. This was partly caused by not always having adequate design
~
basis information available in a timely manner to support critical activities, such as operability assessments. To improve performance in this area, the District has accelerated the schedule for the Design Criteria Document (DCD) Program. Also, accompanying the DCD effort is a verification and validation program which will help ensure that design basis information is accurately contained in the critical output documents.
% rational Experience Review-Thorough review ofindustry operating experience is a key activity that significantly improves the NPG's ability to detect and respond to plant issues. Increased resources and new leadership provided to the Operational Paperience Review (OEIO program already has resulted in improved performance.
Additionally, as discussed in the District's August 8,1994 response to Confirmatory Action Letter 4-94-08, a comprehensive screening and review of OER documents that could impact safety has been performed to ensure the proper disposition of previously closed OER items which could affect restart.
hineerine Support-In addition to the management improvements discussed previously, a comprehensive Engineering study is underway to better integrate the resources at the General Ollice and at CNS. This study will addresa the need to:
Refocus Plant Engineering on day-to-day system engineering and operations needs with additional stafiing and training as necessary.
Create a strong engineering and project management organization that will promoto engineering ownership and accountability for plant performance results.
Commit the remaining engineers to discipline-oriented design engineering.
An interim on-site engineering organization has been implemented to support plant The long term engineering requirements are being evaluated and will be restart.
implemented in the near future.
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Page 5 of 6 Work Control Practices-A critical arca of focused NPG attention has been work control. For example, the work control process has been reorganized into a more centralized work control program with tools for closely monitoring work progress.
l This has already reduced the work load on the Shift Supervisors. In addition, it will positively impact safety in the future by minimizing unnecessary divisional outages and increasing safety system availability.through efficient scheduling of system outages for maintenance. Process improvements of this typo, when implemented at plants in similar conditions, have doubled work through-put by removing inefficiencies. These changes have increased CNS's ability to reduce work backlogs while simultaneously improving safety performance. Other important process changes have been made such as enhanced torquing controls and a new foreign material esclusion program.
III.
hlf-Annessment and Oversight (SET Root Cause 3. DSAT Root Cause 3)
To achieve the performance results required, the NPG must have an efTective independent oversight capability. Previously, SRAB and SORC were not effective in identifying and ensuring correction of safety issues. In response to this, new SRAB 3
and SORC members have been introduced who have broader ind ustry experience. The charters have been revised, the focus on mission reestablished, and expectations have i
been clearly communicated. This has led to SRAB and SORC being moro effective at i
identifying the important safety issues for the station, and in providing a broad overview of CNS activities.
Effective oversight also depends on having an active Quality Assurance (QA) organization. QA is now providing the needed confidence for long-term compliance.
Their assessment function also continues to improve. As previously noted, QA has new leadership, which has had a positive impact on the quality of self-assessments.
A cornerstone ofNPG's performance improvement is the identification of problems and their satisfactory and timely resolution. NPC has made significant progress in ensuring that condition reports (CRs) are written on all identified problems, corrective actions are effective, and generic implications of problems are identified. The major increase in CR initiation rate is a testament to rising standards. To address the impact of CRs, performance indicators for open CRs have been elevated as a topic at regular management review meetings, allowing prioritization and direction of resources to resolve the important issues being faced. Tho NPG is improving its ability to resolve CRs through the Condition Review Group and improving the CR closeout process by management review through Corrective Action Review Boards.
'Ibe new Eventa Analysis Manager along with an increased staff have improved the quality and efficiency of corrective actions.
To enhance corporate oversight, Industry Advisory Group (IAG) has been an established. This group will provide independent oversight of NPG activities and feedback to the Board of Directors and Corporate Executive Committee. The IAG is comprised of three members with broad regulatory, industry, and design experience.
A charter has been established to govern the activities of the group.
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Summary The DSAT and SET inspections provided valuable independent insight into the challenges that the NPG was facing. The reports' observations and root cause anaessments have been thoroughly reviewod and the District has carefully developed and closely monitored performance improvement efforts. In this spirit, positive changes in the way business is dono at CNS have already taken place through new management and the Phase 1 Performance Improvement Plan.
The lovel of improvement seen to date has given the District confidence that Cooper Nuclear Station can return to power operation and be a good performer. Furthermore, the management, resources, and planning for the future that have been established within the NPG set the stage for realizing the District'a longer-term vision and commitment in achieving recognized industry excellence.
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- iamh-ant 2 to ML8960040 Page 1of1 RELATED CORRESPONDENCE I
1.
letter from Mr. L. J. Callan (USNRC) to Mr. G. R. IIorn (NFPD), dated May 27, 1994, Confirmatory Action Letter (CAL 4-94-06).
2.
Ietter from Mr. L. J. Callan (USNRC) to Mr. G. R. Horn (NPPD), dated June 16, 1994, Confirmatory Action Letter-Revision 1 (CAL 4-94-06A).
-8.
14tter from Mr. L. J. Callan (USNRC) to Mr. G. R. Horn (NPPD), dated July 1, 1994, Confirmatory Action Letter-Revision 2 (CAL 4-94-06B).
4.
Ietter from Mr. L. J. Callan (USNRC) to Mr. G. R. Horn (NPPD), dated August 2, 1994, Confirmatory Action Letter (CAL 4-94-08).
5.
Letter from Mr. G. R. Horn (NPPD) to Mr. L. J. Callan (USNRC), dated July 28, 1994, Response to Confirmatory Action Letter.
8.
14tter from Mr. G. R. Horn (NPPD) to Mr. L. J. Callan (USNRC), dated August 8, 1994, Response to Request for Additional Information.
-7.
14tter from Mr. G. R. IIorn (NPPD) to Director, Office of Enforcement (USNHC),
dated January 18,1995, Reply to a Notice of Violation and Proposed Imposition of Civil Penalties.
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ARLINGTON. TEX AS 760118064 August 27. 1993 Docket:
50-298 License:
DPR-46 i
j Nebraska Public Power District 4
ATTN: Guy R. Horn. Vice President. Nuclear P.O. Box 98 Brownville. Nebraska 68321
SUBJECT:
FINAL SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE (SALP) REPORT This forwards the final SALP report (50-298/93-99) for the Cooper Nuclear Station for the period of January 19. 1992. through April 24. 1993.
This j
final SALP Report includes:
1.
The cover letter for the initial SALP report (no revisions to the initial SALP report were made).
2.
A summary of our July 12. 1993. meeting at the Cooper Nuclear Station security building auditorium in Brownville Nebraska.
3.
Your August 11. 1993. response to the initial SALP report.
We have reviewed your letter dated August 11, 1993. in response to the NRC recommendations in each of the SALP functional areas.
It was noted that your response has identified specific actions to improve performance in each of the SALP functional areas.
We will review your progress to achieve these improvements in inspection efforts during this SALP period, The next SALP period for Cooper Nuclear Station is scheduled to last approximately 18 months. from April 25, 1993, to October 22. 1994.
As 1dentified in our letter dated August 11. 1993, from Mr. A. B. Beach.
Director Division of Reactor Projects, to Mr. G. R. Horn. Vice President.
j Nuclear, the revised SALP program will be utilized.
i Sincerely.
1 James L. Milhoan Regional Administrator
Enclosures:
1.
Cover letter for the initial SALP report 2.
NRC Meeting Summary 4
3.
Nebraska Public Power District response to the initial SALP report cc:
(see next page)
Nebraska Public Power District cc w/ enclosure:
Nebraska Public Power District ATTN:
G. D. Watson. General Counsel
.P.O. Box 499
- Columbus. Nebraska 68602-0499
'ooper Nuclear Station C
ATTN: -John M. Meacham. Site Manager P.O. Box 98 Brownville. Nebraska 68321 Nebraska Department of Environmental Control ATTN:
Randolph Wood. Director P.O. Box 98922 Lincoln.. Nebraska 68509-8922 Nemaha County Board of Commissioners ATTN: Richard Moody. Chairman Nemaha County Courthouse 1824 N Street Auburn Nebraska 68305 Nebraska Department of Health ATTN:
Harold Borchert. Director Division of Radiological. Health 301-Centennial Mall South P.O. Box 95007 Lincoln Nebraska 68509-5007 Kansas Radiation Control Program Director
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. J. L. Milhoan Resident Inspector DRP-Section Chief (DRP/C)
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Project Engineer (DRP/C)
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G. F. Sanborn. E0 C. J. Gordon D:DRP Commissioner Remick (MS:
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June 23. 1993 Docket:
50-298 License:
DPR-46 Nebraska Public Power District ATTN: Guy R. Horn. Nuclear Power Group Manager P.O. Box 499 Columbus. Nebraska 68602-0499
SUBJECT:
INITIAL SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE ($ ALP) REPORT This forwards the initial SALP report (50-298/93-99) for the Cooper Nuclear Station.
The SALP Board met on May 20 and June 15. 1993, to evaluate the licensee's performance for the period January 19. 1992. through April 24, 1993.
The performance analyses and resulting evaluations are documented in the enclosed initial SALP report.
In accordance with NRC policy. I have reviewed the SALP Board's assessment and concur with their ratings, as discussed below:
Overall licensee performance declined in several functional areas from the previous SALP evaluation.
A large number of equipment problems occurred during the latter part of this appraisal period that were caused, in part by the failure of licensee employees to aggressively pursue the root cause of potentially significant equipment problems and to assume effective ownership of systems and components.
The problems were also caused by the willingness of licensee personnel to live with problems rather than thoroughly evaluate degraded or potentially degraded equipment issues. The Cooper Nuclear Station staff appears to be satisfied with working around these problems and, as a result, the licensee's problem resolution process and corrective action systems have been weak.
Many of these equipment problems were long-standing, and the failure to self-identify and correct the problems are viewed as demonstrated fundamental weaknesses in the oversight and self-assessment functions.
These concerns were most evident in the areas of Maintenance / Surveillance and Safety Assessment /Ouality Verification and as a result, these areas were assigned a rating of Category 3.
In Engineering / Technical Support, significant weaknesses were observed in problem resolution by the site engineering group. The board was concerned with the examples of insufficient rigor applied to the evaluation and-resolution _ of identified problems.
The evaluations relied heavily on verbal information and there was lack of formality in the approach to the resolution of these problems which contributed to escalated enforcement actions.
The board assigned a rating of Category 2 because of the performance of the I
corporate engineering group and the improvements in operations training.
I
-t Nebraska Public Power District Performance in the functional area of Operations was mixed and assigned a rating of Category 2.
Routine operations remained strong, but there was a lack of a questioning attitude on the part of the operating staff for some engineering operability determinations.
This lack of a questioning attitude may have contributed to some of the plant problems identified during this period.
The relationship between the operations and training staffs has improved but requires some additional attention.
In Radiological Controls, performance has improved.
The radiological controls staff has made major strides in improving the overall program.
The board was concerned, however, with the apparent lack of aggressiveness in identifying radiological performance weaknesses.
Nevertheless overall performance was
. assigned a rating of Category 2 and was assigned an improving trend.
Recurring problems in the areas of offsite notification. emergency assessment.
and decisionmaking tended to offset the improvements noted in the area of Emergency Preparedness.
The failures to follow up on previously identified findings and the additional violations indicated a need for increased management attention.
This area was assigned a rating of Category 2 with a declining trend.
The area of Security continues to be a strength and was assigned a rating of Category 1.
On the basis of the SALP Board's assessment. the length of the SALP period will be approximately 15 months.
Accordingly. the next SALP period will be from April 25, 1993. to July 30, 1994.
A management meeting has been scheduled with you and your staff to review the results of the initial SALP report.
The meeting will be open to the public and held at the Cooper Nuclear Station security building auditorium on July 9, 1993. at 10 a.m.
Within 20 days of this management meeting you may provide comments on and amplification of, as appropriate. other aspects of the initial SALP report.
Your written comments. a summary of our meeting, and the results of my consideration of your comments will be issued as an appendix to the enclosed initial SALP report and will constitute the final SALP report.
Sincerely.
James L. Milhoan Regional Administrator
Nebraska Public Power District
Enclosure:
Initial SALP Report 50-298/93-99 cc w/ enclosure:
Nebraska Public Power District ATTN:
G. D. Watson. General Counsel P.O. Box 499 Columbus. Nebraska 68602-0499 Cooper Nuclear Station ATTN: John M. Meacham. Site Manager P.O. Box 98 Brownville. Nebraska 68321 Nebraska Department of Environmental Control ATTN:
Randolph Wood. Director P.O. Box 98922 Lincoln. Nebraska 68509-8922 Nemaha County Board of Commissioners ATTN: Richard Moody. Chairman Nemaha County Courthouse 1824 N Street Auburn. Nebraska 68305 Nebraska Department of Health ATIN:
Harold Borchert. Director Division of Radiological Health 301 Centennial Mall. South P.O. Box 95007 Lincoln. Nebraska 68509-5007 Kansas Radiat1or, Control Program Director J
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'C A. Hackney. RSLO Senior Resident Inspector - Fort Calhoun J. T. Gilliland. PA0 1
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C. J. Gordon LCommissioner Remick (MSi 16-G-15)
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INITIAL SALP REPORT U.S. NUCLEAR REGULATORY COMMISSION REGION IV SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE INSPECTION REPORT 50-298/93 99 NEBRASKA PUBLIC POWER DISTRICT l
COOPER NUCLEAR STATION January 19, 1992, through April 24, 1993 E SLE OF CONTENTS I.
INTRODUCTION 1
h9f[9k
1 2
II.
SUMMARY
OF RESULTS I I I '.
CRITERIA 4
IV.
PERFORMANCE ANALYSIS 4
A.
Plant Operations...
4 8.
Radiological' Controls 7
C.
Maintenance / Surveillance.
10 D.
E.
' Security 16 F.
Engineering / Technical Support 18-G.
Safety Assessment /Ouality Verification 20 V.
SUPPORTING DATA AND SUMMARIES 24 A.
Major Licensee Activities 24 8.
Direct Inspection and Review Activities 25 1
f
~
I.
INTRODUCTION The Systematic Assessment of Lice... ' Performance (SALP) program is an integrated NRC staff effort to colk t available observations and data on a periodic basis and to evaluate licensee performance based upon this R
information.
The program is supplemental to normal regulatory processes used to ensure compliance with NRC rules and regulations.
It is intended to be sufficiently diagnostic to provide a rational basis for allocating NRC resources and to provide meaningful feedback to 'icensee management regarding the NRC's assessment of their facility's performance in each functional area.
An NRC SALP Board, composed of the staff members listed below met on May 20 and June 15. 1993. to review the observations and data on performance and to assess licensee performance in accordance with NRC Manual Chapter 0516.
" Systematic Assessment of Licensee Performance."
Thu report is the NRC's assessment of the licensee's safety performance at Cooper Nuclear Station for the period January 19. 1992, through April 24, 1993.
The SALP Board for Cooper Nuclear Station was composed of:
Chairman A. B. Beach. Director. Division of Reactor Projects (DRP). Region IV Members J. W. Roe. Director. Division of Reactor Projects III/IV/V. Office of Nuclear Reactor Regulation (NRR)
S. J. Collins. Director. Division of Reactor Safety (DRS). Region IV L. J. Callan. Director. Division of Radiation Safety and Safeguards (DRSS). Region IV J. E. Gagliardo. Chief. Project Section C. DRP Region IV H. Rood. Project Manager. Cooper Nuclear Station. NRR R. A. Kopriva. Senior Resident Inspector. Cooper Nuclear Station. DRP.
Region IV The following personnel also participated in or observed the SALP Board meeting:
J. L. Pellet Chief Operations Section. DRS. Region IV T. F. Westerman. Chief. Engineering Section. DRS. Region IV P. H. Harrell. Chief. Technical Support Staff. DRP. Region IV I. Barnes. Chief. Technical Assistant. DRS. Region IV B. Murray. Chief. Facilities Inspection Programs Section. DRSS. Region IV D. B. Spitzberg, Emergency Preparedness Analyst. DRSS. Region IV C. J. Paulk. Reactor Inspector. DRS, Region IV E. E. Collins. Project Engineer. Project Section C. DRP Region IV W. C. Walker. Resident Inspector. Cooper Nuclear Station. DRP Region IV
i L
.2 f
II.
SUMMARY
OF RESULTS Overview
. Performance in the area of plant operations was mixed.
The plant operations staff performed its duties in a conservative manner during routine operations.
i Command, control, and communications within operating crews and within the operations department has improved but remains inconsistent.
Management
. attention and oversight of routine plant operations was evident.
There has' 4
been a lack of a questioning attitude by the plant operations personnel of
The relationship between operations and training improved; however, the operations department appeared to not totally support and reinforce the training department's formal training program.
Tne
. emergency and abnormal operating procedures still exhibited some weaknesses.
i
+
In radiological controls, management provided strong support.
External radiation exposure controls were implemented effectively.
Excellent programs were maintained in the radiation protection area.
One enforcement action involved numerous operators and an operations supervisor that showed.a lack of respect for the special work permit process.
The licensee effectively implemented planning and preparation for.the 1993 refueling outage.
Excellent coordination existed between the radiation protection department and other departments and a strong as-low-as-reasonably-achievable (ALARA) program was maintained.
Management has not been aggressive in identifying radiological performance weaknesses.
In maintenance and surveillance the licensee's preplanning and work practices i
were coordinated and well controlled, and their work item tracking system was excellent.
The performance of maintenance activities was mixed, although communications and supervisory oversight were good.
Maintenance of motor-operated valves was generally good, but there were weaknesses noted with the j
installation of terminal lugs.
Weaknesses were found in the licensee's l
~
maintenance of the reactor building and safety-related check valves.
Several licensee event reports were submitted during the appraisal period because of improper maintenance.
Program procedures for control and scheduling of surveillance activities were controlled and explicit.
Weaknesses were found in the adequacy of technical justifications to verify the operability of equipment when Technical Specification testing acceptance criteria had not been met.
Weaknesses were also seen in the licensee's testing of the pressure isolation valves, secondary containment isolation valves, and manual valves needed for safe shutdown of the plant.
i
-In emergency preparedness, improvements were observed in certain important performance areas.
Recurring problems were noted, however, in the-areas of offsite notifications and emergency assessment and decision making.
These
. problem areas, combined with certain failures to promptly followup on findings affecting. emergency preparedness, and the violations which were identified, j
' indicate a need'for increased management attention in this program area.
i
' l Y
e,m m
p 3
Performance in the security area continues to be excellent.
The program was effectively managed by personnel within the security department.
Upper management provided strong support for the security program.
Excellent
. programs were noted in the areas of testing, maintenance, staffing, audits, and the response to audit findings.
In engineering and technical support, performance was good.
The interface between corporate engineering and site engineering was effective.
The overall process to control projects and design modification activities appeared to be very effective.
The temporary modification process was found to be well implemented.
Configuration management was found to be effective.
The licensee's plant procedures were generally well controlled and technically adequate to perform the desired actions.
Improvements were seen in training; however, licensed operator training continued to need management attention and priority.
Significant weaknesses were observed in problem resolution, and several examples of a lack of rigorous problem resolution were seen.
Examples of over-reliance on verbal information and informality were seen which directly contributed t.o escalated enforcement actions.
In safety assessment and quality verification the licensee implemented an effective operability determination and evaluation process and deficiency report process.
While some problems were effectively resolved, others were not, continuing to show significant weaknesses in the licensee's approach to the resolution of issues.
The causes for ineffective problem resolution included informality, apparent unquestioning deferment of corrective actions for generic problems. the absence of corrective action for those instances where explicit regulatory requirements did not exist and poor personnel aerformance in bringing deficiencies to management's attention.
The licensee las planned or implemented extensive initiatives to improve performance in problem resolution, however, the effectiveness of the licensee's initiatives to address personnel performance and personnel attitudes remains to be seen.
The licensee's oversight and self-assessment activitics were not always acceptable and will require additional management attention to assure that these activities provide management with the critical insights into the performance of the plant and the operating staff.
Rating Last Period Rating This Period Functional Area (07/16/90 to 01/18/92)
(01/19/92 to 04/24/93)
Plant Operations 2
2 Radiological Controls 2
2*
Maintenance / Surveillance 1
2**
Security 1
1
..J.
l 1
Engineering / Technical 2
2 Support Safety Assessment /
2 3
Ouality Verification i
- ! Improving Trend - Licensee performance was determined to be improving during this assessment period.
Continuation of the trend may result in a change in the performance rating.
- D Declining Trend - Licensee performance was determined to be declining during this assessment period and the licensee had not taken meaningful steps to address this pattern.
Continuation of the trend may result in a change in the performance rating.
III.
CRITERIA The evoluation criteria, category definitions, and SALP process methodology that were used, as applicable. to assess each functional area are described in detail in NRC Manual Chapter 0516. dated September 28. 1990.
This chapter is available in the Public Document Room files.
Therefore. these criteria are not repeated here but will be presented in detail at the public meeting to be held with licensee management.
IV.
PERFORMANCE ANALYSIS A.
Plant Operations 1.
Analysis This functional area consists primarily of the control and execution of activities directly related to operating the plant.
Evaluation of this functional area was based on routine inspections performed by the resident inspectors.
The Region-based inspections included two operator examinations, two Emergency Plan inspections, one plant procedures inspection, and one unannounced followup inspection to observe licensed operators' conduct during in-house requalification examinations.
The previous SALP report (NRC Inspection Report 50-298/92-99) noted that management's attention and oversight was not always conservative; procedures were not always used properly; and that significant weaknesses were identified in the command, control, and communications activities when the operating staff was presented with simulated nonroutine emergency events.
Command, control, and communications within operating crews and within the operations department has improved but remains inconsistent.
A training guide and an operations directive have been issued in this area.
However, formal training to implement the guide and directive had not been provided and none of the on-shift supervisors questioned shortly after its issuance were aware of the operations. directive.
Management expectations and reinforcement of
i a
management was not expeditiously informed by a shift crew-(by written or oral.
training.in these areas'is an ongoing challenge.
For example, operations communications) that a problem with the control room annunciator computer resulted in 60 annunciators being in an alarmed condition.
Control room logbook entries for the: event were also unclear.
The.last SALP report cited weaknesses :in event diagnosis and' implementing I
emergency and abnormal procedures effectively.
During this SALP period these problems appear to have been effectively addressed as indicated by improved diagnosis and procedure use during operator -license and requalification
. examinations and emergency preparedness exercises and inspections.
The last S. ALP also described concerns related to emergency and abnormal procedure
-validity.
During this SALP period, the licensee was cited for the failure to
-incorporate changes reflecting plant modifications into the emergency support procedures-in a timely fashion.
This could have resulted in the procedures being unusable during certain accident sequences involving the release or potential release of radioactive material.
This indicates that procedure implementation continues to be of concern, although for reasons differer;t than described in the previous SALP.
The enforcement history in this functional area involved the failure to incorporate changes into the emergency support procedures and the failure to i
follow procedures which.resulted in a loss of shutdown cooling.
The procedure violations were not repetitive of those addressed in the previous SALP report but are indicative of the fact that procedure implementation continues to be of concern.
l While' the licensee has implemented significant effort to formalize and document the evaluation of the immediate impact of deficiencies on the i
operability of systems, there has been a lack of a questioning attitude by plant operations of operability determinations pre]ared by engineering.
i Examples included the operability-determinations t1at were prepared to address a temporary strainer in the suction of the reactor core isolation cooling c
system.-leaking shutdown cooling suction valves pressurizing the low pressure j
residual heat removal system. and particulate contamination in emergency diesel generator fuel oil above the limits specified by the station procedures.
In each case, the conclusion of operability was accepted without
- challenge.
The operability determination for the temporary strainer contained assessments that the strainer could be back-flushed, but the physical configuration precluded back-flushing and no procedures existed telling operators how to perform the evolution.
For the leaking valves, a vent path l
was established to bleed the pressure. but no limits were specified'
^
identifying how much leakage would be considered unacceptable, and no evaluation of the containment isolation function was made.
For the high particulate, the condition was accepted without an evaluation of the impact of
'the deficiency on the fuel delivery system and the operability of the T
The acceptance.of these operability 4'
determinations with apparent weaknesses shows an absence of a questioning attitude and a lack of ownership'by plant operations.
,C,_
..w,
6-Management attention and oversight of routine plant operations was evident.
Senior site management routinely toured the control room on a daily basis and, during major evolutions and/or plant changes, management personnel were present in the control room, providing on overview of the activities.
Management's actions in response to operational events were usually appropriate.
On two occurrences the licensee elected to shut down the plant to implement corrective actions (replace batteries in April 1992 and repair the motive power to the low pressure coolant injection valves in September 1992).
The licensee also made a decision to reduce reactor power after the design basis reconstitution group identified a problem with the control power for some emergency core cooling system valves.
The plant operations staff performed its duties in a conservative manner during daily, routine, steady-state power o)erations; reactor startups: and plant shutdowns.
Few plant operational pro)lems or perturbations were experienced during the reporting period and the actions taken by the operators in response to a feedwater transient and reactor recirculation pump trip were accurate and timely.
There were no automatic plant trips during this assessment period.
Observed communications between operating staff and other departments during the performance of maintenance and surveillance activities have improved from those observed in the previous SALP period.
Managements' efforts had been successful in reducing the number of illuminated annunciators on the main control room boards during steady-state operations.
The relationship between operations and training improved.
However, the operations department appeared to not totally support and reinforce the training department's formal program.
Instances were noted where more emphasis was given to on-crew input into training content than to that prescribed by the formal training program.
This may account for the differences identified in crew performance.
Some cross-crew normalization 3rogress has been made by rotating operators into the training department; lowever, the full benefit of the program has not been realized.
The licensee's operations staff was a very experienced and knowledgeable group of licensed senior reactor and reactor operators.
During this assessment period, the licensed operator staffing remained adequate to maintain a six-shift rotation of operating crews.
Housekeeping in the plant was good.
Most of the areas have been painted and have been provided adequate lighting.
Labeling has been completed for most components throughout the. plant and found to be of a quality to support component manipulations by plant personnel.
There remain some less-trafficked areas in the plant, which are not up to the housekeeping equivalence exhibited by the majority of the plant areas.
In summary, overall performance in the area of plant operations was mixed.
The plant operations staff performed its duties in a conservative manner
-7 during routine operations.
Command, control, and communications within operating crews and within the operations department has improved but remains inconsistent. Management attention and oversight of routine plant operations was evident.
Although different. the emergency and abnormal operating procedures still exhibited some concerns identified in the previous SALP report.
There has been a lack of a questioning attitude by plant operations of operability determinations.
The relationship between operations and training improved, however, the operations department appeared to not totally support and reinforce the training department's formal training program.
2.
Performance Ratina The licensee is considered to be in Performance Category 2 in this functional area.
3.
Recommendations a.
NRC Actions Review the licensee's actions and training with respect to operator communications during nonroutine operating activities.
Review the licensee's actions to enhance their operability determination process.
b.
Licensee Actions Licensee management needs to take appropriate measures to a.ssure that the long-term 1ssue of operator communications during nonroutine operating activities has been included in the training process for all operators.
The licensee should implement an effective process for the evaluation of deficient conditions that impact the safe operation of the facility.
B.
Radiological Controls 1.
Analysis This functional area consists primarily of activities related to radiation protection, radioactive waste management. radiological effluent control and monitoring, water chemistry controls, radiological environmental monitoring, and transportation of radioactive materials.
This area was inspected seven times by Region-based radiation specialist inspectors ano on a continuing basis by the resident inspectors.
During the previous assessment period, concerns were identified involving the implementation of the radiological protection program during outages and routine, day-to-day activities.
During this assessment period, the licensee improved implementation of the radiological protection program during routine, day-to-day activities. but still experienced some problems during outages when activity levels were high.
l i
? :
Enforcement was taken when several plant operators did not follow the c
. requirements of a special work permit requirement.
This. example was-of particular concern because numerous operators and an operations supervisor were-involved.
This event reflected a lack of respect for the special work l
permit process as an essential part of the radiation protection program.
i Senior management's support for the radiation protection program, and'the
(
' radiological protection management's oversight of day-to-day activities, was
. excellent Strong programs had been developed and were maintained..in the areas-of control of radioactive materials and contamination, surveys, monitoring, and radiation instrument calibration.
Janagement has not been aggressive in identifying radiological performance weaknesses.
During this assessment period, the_ licensee generated only five radiological safety incident reports.
Given the number of plant areas
'that are: contaminated and the magnitude of work performed, the absence of
' incident reports reflects a site attitude of not documenting, and consequently i
not aggressively pursuing, radiological problems.-
Communications among the radiation protection department and other departments were instrumental in the progress made to reduce the number of contaminated areas within the radiological controlled area.
The licensee planned to implement a program for controlling radiation exposures, which included a new radiological support system that used a state-of-the-art computer-based electronic dosimetry system and access control system.
?
The licensee effectively implemented planning and preparation for the 1993 refueling outage.
The strengths of this program included an inventory of-radiation protection supplies and equi 3 ment, coordination between the radiation protection department and otler departments, and an appropriate number of contract radiation protection personnel to provide the required radiation 3rotection coverage of outage activities. The contract technicians were brougit on site several weeks prior to the outage to receive training.
External radiation exposure controls were implemented effectively by monitoring whole body exposures using thermoluminescent dosimeters, self-reading dosimeters, radiation surveys, radiation work permits, and l
administrative dose limits.
Radiation areas and high radiation areas were
. properly posted and controlled, Special work permits were improved to provide enhanced. guidance to workers and make them easier to understand.
Isolated examples were noted of workers not following all of the instructions of special work permits. The licensee had implemented a good internal exposure controlLprogram.
The licensee had implemented an excellent ALARA program.
The radiological protection. department
- proactive ;in the area of ALARA briefings, which were conducted. prior to '
trformance of complex. maintenance and operational activities and/or w
.le potential.for nigh radiation exposure was present.
?
The ALARA prejob' brie,ings were thorough and well organized, addressed all important issues:.~and' emphasized. good radiological protection practices.
4
_u
9 Prior to the 1993 refueling outage. the plant utilized a " soft" shutdown, which provided good control of crud bursts and improved reactor water cleanup.
reducing external exposure.
The ALARA suggestion program received an increase in ALARA suggestions and was given excellent support from management and workers from other departments.
ALARA personnel performed daily reviews of the doses accrued by jobs during the 1993 refueling outage and made frequent tours of the drywell to observe work activities.
Person-rem exposures and personnel contamination events were maintained below outage goals.
The licensee's liquid and gaseous radioactive waste effluent program, water chemistry and radiochemistry programs, and radiological environmental monitoring program were effective and well managed.
The sampling results from all these programs compared well with NRC independent measurements.
The solid radwaste and radioactive materials transportation programs included excellent procedures for the preparation and shipment of radioactive waste and other radioactive materials.
The licensee ~s performance of characterizing, classifying and preparing radioactive waste for shipment and burial during this assessment period was excellent.
Radioactive materials and waste shipments were made without incident or problems.
Staffing was maintained at appropriate levels in the radiological controls areas.
The various departments in the radiological controls areas had experienced a very low turnover of technical personnel.
The radiation protection staff was supplemented with contract radiation protection technicians during outages. but reliance was not placed on contractor personnel during normal operating periods.
Accredited training and qualification programs were established and being implemented for personnel in this functional area.
The radiological controls area personnel were well trained and qualified.
Training instructors were well qualified.
Coordination existed between the training department and the various departments that received training in this functional area.
The licensee's overall training efforts were excellent.
The quality assurance audits and surveillances performed in the radiological controls area identified pertinent findings, and the corrective actions for the findings were timely and comprehensive.
The audit teams included qualifled auditors and technical specialists who were knowledgeable of the applicable requirements to be reviewed in specific program areas.
A self-assessment of the radiation protection program. including source term reduction. work control, communications, radiation protection during outages.
ALARA. and training, was performed and the assessment identified several recommendations for program improvement.
In summary, management provided strong support for the radiological controls External radiation exposure controls were implemented effectively.
1 area.
Excellent programs were maintained in the radiation protection area.
One enforcement act1on involved several operators and an operations supervisor that showed a lack of respect for the speciai work permit process.
The
.. i i
licensee effectively implemented planning and preparation for the 1993 refueling outage.
Excellent coordination existed between the radiation protection department and other departments, and a strong ALARA program was maintained.
Management has not been aggressive in identifying radiological performance weaknesses.
2.
Performance Ratina The licensee is considered to be in Performance Category 2 in this functional area with an improving trend.
3.
Recommendations a.
NRC Actions None b.
Licensee Actions i
The licensee needs to implement measures to assure that the facility staff is more aggressive in the pursuit of issues which are to be documented in the 1
radiological safety incident report process established by site procedures.
C.
Maintenance / Surveillance 1.
Analvsis This functional area consists of activities associated with the predictive.
preventive. and corrective maintenance of plant structures, systems, and components.
This area also includes the conduct of surveillance testing.
1 inservice testing. and inspection activities.
NRC inspection efforts consisted of routine inspections by the resident inspectors and five inspections performed by region-based inspectors.
In the last SALP report. no recommendations were made for the overall program j
improvement.
During this assessment period. maintenance work practices were performed in a coordinated controlled manner.
One exception to procedure compliance was observed during emergency diesel gererator maintenance where workers did not obtain a system engineer inspection as required by the work package.
The licensee continued to have an excellent work item tracking system, which is effective in assuring that work in progress is properly documented and work needing to be performed is prioritized appropriately.
The licensee's performance in implementation of maintenance activities was mixed.
Preplanning of maintenance activities and attention to detail by maintenance personnel were good with good communication between maintenance personnel in the field and other organizations.
Supervisory personnel
. presence was noted during complex activities and periodically during the i
performance of more routine efforts.
+
Maintenance of motor-operated valves was generally good.
Some weaknesses were seen however, in the maintenance of motor-operated valves.
Discrepancies involving improper terminal lug installations and evidence of corrosion and dirt in the-limit switch compartment for environmentally qualified motor-operated valves were not identified or corrected by maintenance personnel.
In mid-1992, the licensee initiated the development of a formal check. valve program based on NRC and, industry recommendations.
A significant weakness existed, however, in the licensee's check valve maintenance and testing activities.
While many check valves were tested in the inservice testing
- program and others were inspected by the preventive maintenance program.
' reactor coolant pressure isolation check valves were neither disassembled for inspection nor leak rate tested.- The licensee's maintenance and testing activities did not ensure that these valves were capable of performing the
. safety-related pressure isolation function.
At the end of the assessment i
period, the licensee was implementing plans to perform leak rate testing of l
these check valves.
3 During the refueling outage. testing of the secondary containment showed that the licensee had not effectively tested or maintained secondary containment.
The secondary containment integrity test did not effectively address adjacent building status, and this masked identification of a significant deficiency.
Also, features such as secondary containment isolation valve timing were not effectively tested, The licensee had not effectively maintained door seals, which were wcrn from use during the operating cycle, degrading the secondary containment.
At the end of the assessment period the licensee was implementing corrective actions to address these deficiencies.
During this assessment period, safety-related systems were declared inoperable and licensee event reports were issued as a result of ineffective, or lack of.
maintenance on plant equipment.
The instances involved:
(1) the clogging of a steam trap, due to a lack of preventive maintenance, that raised questions about the operability of the reactor core isolation cooling system.
(2) inoperability of a damper in the control room heating and ventilation system because the linkage was not routinely lubricated. (3) failure of a motor-operated valve to operate due to a stripped stem nut on the valve which was not detected because of the lack of appropriate acceptance criteria in the maintenance work procedure, and (4) failure of a battery charger to operate properly due to a lack of preventive maintenance.
The systems engineering organization was involved in maintenance and surveillance activities.
The oversight provided by the engineers helped to ensure that the maintenance and surveillance activities were acceptably implemented.
However the issues discussed in the four preceding paragraphs indicate shortcomings in program technical definition and technical resolution
-of identified problems.
l Early in the assessment period. a significant weakness was found in the licensee's surveillance test program involving the station batteries.
The program allowed that safety-related equipment could be considered operable without an adequate technical justification when Technical Specification test acceptance criteria were not met.
Following identification of this issue, the licensee effectively implemented corrective actions to ensure that Technical Specification test acceptance criteria reflected actual operability criteria and that test discrepancies were formally evaluated and approved.
Program procedures for control and scheduling of surveillance activities were controlled and explicit.
There were very few missed or overdue surveillance tests.
The surveillance schedule consistently reflected planning and assigned priorities.
Procedures for conducting surveillances were well written and easy to follow.
Personnel conducting surveillances were qualified.
Senior technicians and senior operations personnel provided oversight and guidance to trainees while conducting on-the-job training.
During surveillance performance, the licensee's staff continued to demonstrate good communication and coordination.
The performance of nondestructive examinations in the inservice inspection program was observed to be good.
The nondestructive examinations were performed by contract personnel that were well qualified for the specific processes.
The repair and replacement program was effectively implemented by well-documented work packages and the performance of work activities was observed to be good.
The scope of the inservice inspection program did not include all safety-related heat removal systems, such as the service water and reactor equipment cooling system.
These systems consequently have not received all the inspection activities specified by the Technical Specifications. including pressure testing.
The licensee's third party review of the inservice inspection program did not identify these systems as needing to be included in the inservice inspection program.
The licensee's testing did not include periodic verification of many manual valves that were specified to be operated, using emergency operating procedures, or would need to be operated in other emergency conditions.
One example was the emergency diesel generator fuel oil storage tank cross-connect valve.
A weakness was seen in the licensee's primary containment leak rate testing program.
The licensee had tested 26 containment isolation valves with test pressure applied in a direction opposite to containment pressure without an adequate basis that the test results would be equivalent or conservative.
Licensee testing with the test pressure applied in the direction of accident pressure demonstrated, for some valves, that the testing was nonconservative.
At the end of the assessment period, the licensee was implementing corrective actions to either test the valves in the direction of accident pressure or provide an adequate Justification that testing in the reverse direction was t
equivalent.
The licensee also did not verify that instrumentation cabinets that would be exposed to primary containment pressure after the accident were tested.
The hydrogen / oxygen analyzers were not tested at accident pressure.
In summary the licensee's preplanning and work practices were coordinated and well controlled, and their work item tracking system was excellent.
The performance of maintenance activities was mixed, although communications and supervisory oversight were good.
Maintenance of motor-operated valves was generally good, but weaknesses were noted with the installation of terminal lugs.
Weaknesses were found in the licensee's maintenance of the reactor building and safety-related check valves.
Several licensee event reports were submitted during the appraisal period because of improper maintenance.
. Program procedures for control and scheduling of surveillance activities were controlled and explicit.
Weaknesses were found in the adequacy of technical justifications to verify the operability of equipment when testing acceptance criteria had not been met.
Weaknesses were also seen in the licensee's testing of the pressure 1 solation valves, secondary containment isolation valves, and manual valves needed for safe shutdown of the plant.
2.
Performance Ratina The licensee is considered to be in Performance Category 3 in this functional area.
3.
Recommendations a.
NRC Actions The NRC should conduct inspection activities with the focus of assessing the technical adequacy of activities and the appropriate scope of activities and to review maintenance and surveillance program identification and resolution of conditions advi_rse to quality.
b.
Licensee Actions The licensee should review the scope and depth of maintenance / surveillance activities to make sure that the maintenance and surveillance programs for safety-related equipment are adequate to assure that the equipment can and will continue to perform its safety functions.
The licensee should also increase the emphasis on oversight by plant management and systems engineering to provide an increased level of technical support to the maintendnce and surveillance activities at the plant.
Management should provide additional emphasis on generation of thorough and detailed maintenance and surveillance procedures, and on the need for maintenance / surveillance personnel to carefully follow the procedures.
D.
Emeroency Preoaredness 1.
Analysis This functional area includes activities related to the establishment and implementatten of the emergency plan and implementing procedures, onsite and offsite plan development and coordination support and training of emergency response organizations, licensee performance during exercises and actual events that test the emergency plans, and interactions with onsite and offsite emergency response organizations during planned exercises and actual events.
The previous SALP report noted a Performance Category 2 in the emergency preparedness area.
The report recommended licensee action to implement proactive corrective actions for identified weaknesses and to enhance its self-assessment capabilities.
Evaluation of this functional area was based on the results of two inspections conducted by the regional emergency preparedness analyst and observations by the resident inspectors.
The two inspections included evaluation of the 1992 emergency exercise and an operational status inspection which included a regional inspection initiative to evaluate the knowledge and performance of duties of emergency response personnel.
During the assessment period, there were six emergency declarations associated with actual events, all at the Unusual Event classification level.
Five of the declarations were made following initiation of a shutdown required by Technical Srecifications.
The sixth declaration was made following a minor earthauake detected onsite.
During two of these events, the licensee experienced some difficulties in implementing portions of the emergency plan and implementing procedures.
S)ecifically, following one event there was a delay in event classification, w1ich indicated a weakness in the decisionmaking process.
In addition, a violation was cited for the licensee's failure to complete notifications to offsite authorities in a timely manner following the declaration of this event.
Following a subsequent Unusual Event declaration, notification of one offsite organization was untimely.
The licensee identified the problems noted above and initiated corrective action.
In one instance, however. the licensee's process of investigating, formulating, and documenting the needed corrective action was slow.
The 1992 exercise resulted in five NRC identified weaknesses.
The weaknesses involved:
(1) weak analysis and technical assessment of plant conditions.
(2) failure to take steps to ensure habitability of the Technical Support Center / Operational Support Center. (3) failure to detect and classify General Emergency conditions promptly. (4) failure' to make the offsite notification of the General Emergency in a timely manner, and (5) use of multiple dose assessment programs for. decisionmaking purposes without clear guidance on reconciling conflicting results.
The weakness concerning analysis and technical assessment of plant conditions was found to be a repeat of a similar weakness identified during the previous exercise.
During the exercise. the NRC noted licensee improvements in several areas from the performance in previous exercises.
Most notable were improvements in the performance of control room operators, tracking of response teams. and the licensee's self-
J 15-1 critique process.
The 1992 exercise was not evaluated by FEMA however, the licensee demonstrated an excellent working relationship during the exercise with the state response organizations that participated.
As a result of the 1992 exercise weaknesses and the previously mentioned findings related to actual event declarations a management meeting was held with the licensee to discuss NRC concerns in emergency preparedness.
The operational status inspection found that emergency response facilities had been'well maintained.
A good program of emergency response training had been administered and a good number of trained personnel had been assigned to the emergency response organization.
Quality assurance audits of emergency pre)aredness were of good scope and depth.
During emergency preparedness wal tthroughs. operating crews perfcrmed well and demonstrated an improved
_ knowledge and performance of duties in all areas found to be weak in recent inspections.
Two violations were identified during the operational status inspection.
One violation was for failure to conduct required tests of the pagers used to notify members of the emergency response organization.
The second violation was identified for failure to conduct a drill critique and for failure to follow up as required on drill weaknesses.
A noncited violation was identified and corrected by the licensee for failure to submit to NRC one emergency plan implementing procedure revision within the required time frame.
4 In response to NRC recommendations from the previous SALP report, the licensee formed an emergency preparedness task force to review and recommend actions in areas such as emergency preparedness program effectiveness, the emergency plan, command and control of the emergency response organization. emergency preparedness training, exercises and drills, and other programmatic areas.
The task force report was issued midway through the SALP period.
Substantive recommendations and initiatives were made by the task force.
Additional corrective actions and improvement initiatives were presented during the October 1992 emergency preparedness management meeting with the licensee.
Many of the corrective actions and improvement initiatives arising from these efforts were scheduled for completion beyond this SALP period.
Therefore. the overall effectiveness of these actions had not been evaluated by the NRC.
Despite these self-assessments and licensee identified recommendations.
however, the NRC continued to identify instances where the licensee was neither aggressive nor proactive in response to some emergency preparedness findings during the SALP period.
In summary during the SALP period, improvements were observed in certain performance areas important to emergency preparedness.
Recurring problems were noted, however, in the areas of offsite notifications and emergency assessment and decisionmaking.
These problem areas. combined with certain failures to promptly follow up on findings affecting emergency preparedness, 3
and the violations which were 10entified, inoicate a need for increased management attention in this program area.
A i
2,--Performance Ratino.
- The111censee 'is considered to be in' Performance Category 2 in this area, with
- a. declining trend.
- 3. LRecommendations a,
NRC Actions' Conduct an. assessment to. verify _that the ~ recurring problems of offsite notifications.. emergency assessments,: and decisionmaking have been corrected.
- b '.' Licensee Actions Licensee needs to take actions to assure that the recurring issues in offsite s
-notification, emergency assessments. and decisionmaking have been corrected.
- E.
Securit_Y
.1.
Analysis This functional area consists of activities associated with the security of' the )lant. including'all aspects of access control.. security background chects. safeguards information protection, and. fitness-for-duty activities and n
controls.
Evaluation of this functional area was based on the results of two-security inspections performed by regional inspectors and obser fations made by the resident inspectors.
- The previous SALP report identified the security area as a Performance
-Category 1 and-did not include any specific recommendations.
Two violations of program requirements were identified during the SALP period involving the failure to maintain control of a visitor and the failure to change locks after termination of security guards for cause.
Licensee
. management took prompt and effective action to correct the violations.
identify the root causes, and strengthen procedures to prevent' recurrence.
The security program was effectively managed.
Plant and corporate security management personnel maintained an excellent knowledge of current industry-trends by being actively involved in industry groups.
Security management and the: staff were well: trained and qualified security 3rofessionals with an -
excellent understanding of nuclear plant security o]jectives.
- The security system received excellent maintenance support.
Instrumentation
' and controls technicians.were provided to promptly repair or replace any l security equipment that. required corrective maintenance.. Repairs were-
'normally completed in a' timely manner which. in turn, reduced the time spent by security officer.s on compensatory posts.
The support and cooperation among security. plant maintenance. and the instrumentation and controls group
v was excellent and there was strong evidence of management's commitment to maintain a high quality and effective security program.
An excellent security reporting program had been implemented.
The security event reports and reporting procedures were well understood by security supervisors and consistent with NRC requirements.
The security staff conducted excellent analyses of security events identifying trends and developing sound resolutions to problems.
The security organization was staffed with an appropriate number of personnel to ensure that the security program was properly implemented.
The security training program was aaministered by a well qualified full-time staff.
The program was consistent with the requirements of the NRC-approved Security Force Training and Qualification Plan.
Personnel training records were urrent and well maintained.
Personnel were knowledgeable of their respons1bilities and performed their duties competently.
However, the training section did not have any training aids available for hands-on type training in the early part of the SALP period.
For example. there were no simulated weapons or explosive devices to use during training on x-ray equipment or during bomb search tactics.
The video film library, at the time.
was limited tc three or four recently acquired films.
The licensed developed some additional training aids toward the end of the SALP period.
However, the lack of training aids detracted from an excellent training program.
The submitted revisions to the Security Plan. the Security Contingency Plan, and the Security Training and Qualification Plan under the provisions of 10 CFR Section 50.54(p) were technically sound and reflected well-developed policies and procedures.
Security personnel involved in maintaining program plans current were knowledgeable of NRC requirements and objectives.
A comprehensive annual audit of the security program was conducted by the licensee's quality assurance group.
The audit team included an auditor with nuclear security experience from another power reactor utility.
The audit was performance-based and very well documented.
The security department implemented prompt and effective actions in response to the audit findings.
In summary, the licensee continues to maintain an excellent security program.
The program was effectively managed by personnel within the security department.
Upper management provided strong support for the security program.
Excellent programs were noted in the areas of testing, maintenance, staffing, audits, and the response to audit findings.
2.
Performance Ratino The licensee is rated as Category 1 in this functional area.
3.
Recommendations None.
I F.
Enoineerina/ Technical Sucoort-1.
Analysis This functional area consists of technical and engineering support for-all plant activities.
It includes all licensee activities associated with the design of plant modifications; engineering and technical support for operations: outages'. maintenance, testing. surveillance and procurement activities; and training and configuration management.
-NRC inspection efforts consisted of routine inspections by~the resident inspectors, four region-based inspections. and one structural audit team inspection..The inspection effort included team inspections to assess the
- motor-operated valve Generic Letter 89-10 program and engineering and technical support functions.
Additionally, two sets of licensed operator examinations were administered at Cooper Nuclear Station.
The previous SALP resort recommended that licensee management should implement actions to correct tie ongoing concerns identified with the licensed operator training program.
During this assessment, improvements were seen in training; however, licensed operator training continued to need management attention and
-priority, as previously discussed in the Operations functional area.
During this assessment period, a review of design modification activities was performed.
The overall process to control projects and design modification activities appeared to be very effective, with a small backlog of work.
Procedures to control design changes and modifications were found to be comprehensive and well written as were the plant modification packages. A great deal of conservative engineering effort was usually incorporated into the modification process.
The temporary modification process was found to be well implemented. and temporary modifications were not -left in place over six months.
Particular strengths were noted in the weekly audit performed by senior licensed operators and the use and control of temporary modification tags.
The interface between corporate engineering and site engineering appeared effective. There was a very stable engineering staff with a low turnover rate; Good morale was observed, and staffing levels appeared consistent with the workload.
Engineering personnel were qualified and trained and their responsibilities defined.
Of particular note was the emphasis on certification of system engineers as shift technical advisors.
Engineering appeared to have good credibility and working relationships within the
-licensee's organization.
~ Configurat. ion management was found to be effective.
Although the licensee's design basis. reconstitution process was found to be somewhat delayed, issues have been identified by this program which were promptly addressed.
1.
The scope.of the licensee's program to-test motor-operated valves was
. consistent with Generic Letter 89-10 and was managed by knowledgeable personnel.
During NRC reviews, a number of weaknesses were identified
< including calculations, us'e of design basis parameters, and testing.
Additionally,'the licensee had addressed the recommendation of Generic Letter 89-10 to evaluate and trend motor-operated valve failures but had not yet implemented the procedures.
Inspectors observed the conditions of.the.
valves to be very good.
Overall,:the licensee's motor-operated valve testing was good.
In the area of engineering, the licensee's plant procedures were generally well controlled and technically adequate to perform the desired actions.
Examples of weaknesses:in procedure support were noted including a lack of-jndependent verification of a calculation, providing timely procedure change information to plant operators and a lack of information in relay maintenance procedures.
In one case. support procedures were known_to be in error and
-timely corrective action had not been performed to correct the errors.
The licensee's program for the training of candidates for an 03erating license was determined to be adequate.
One weakness was observed in t1e origin of learning objectives.
Actions to strengthen this program continued with the reallocation of resources to training, but at a slow rate.
Enlarging the training staff through direct hiring and implementation of the program to bring in licensed operators from the operations department had a positive affect on the o]erations department's acceptance to training.
Some improvement was noted in t1e formal communication process between the operations and training department management staffs.
Significant weaknesses were observed in problem resolution.
One cause for ineffective problem resolution was informality and this has manifested itself as a tendency to rely on verbal information over documentation or plant records.
Plant engineers relied on verbal information from maintenance personnel, without verification that no temporary strainers existed in the system, in deference to the information that was on approved drawings that showed that strainers were installed.
This verbal information was found later to be in error.
Plant engineers also relied on verbal information regarding the existence of' documentation that temporary strainers had been removed during preoperational or startup testing, even though the documentation that the engineer reviewed indicated the exact opposite.
This was presented to the NRC as justification-that temporary strainers had been removed and was later found to be incorrect; temporary strainers were, in fact, in the. system.
Informality was also seen in the licensee's resolution of a secondary containment integrity test failure as discussed in maintenance and surveillance.
A lack of rigorous resolution of a high particulate concentrations in the diesel fuel oil and 1eaking shutdown cooling suction isolation valves was alsoiseen.
The secondary containment was declared operable without a good understanding of the causes for the test failure and without action to prevent recurrence.
The licensee subsequently found that a loop seal was missing causing a 10-inch flow path between the reactor building and the radwaste building.
Overall. the performance in this functional area was mixed.
The interface-between corporate engineering and site engineering was effective.
The overall process to control projects and design modification activities appeared to.be very effective.
The temporary modification process was found to be well implemented.
Configuration management was found to be effective.
The licensee's plant procedures were generally well controlled and technically adequate to perform the desired actions.
Improvements were seen in training:
however. licensed operator training continued to need management attention and priority.
Significant weaknesses were observed in problem resolution and several examples of-a lack of rigorous problem resolution were seen.
Examples of over-reliance on verbal information and informality were seen which directly contributed to escalated enforcement actions.
2.
Performance Ratina The licensee is considered to be in Performance Category 2 in this functional area.
3.
Recommendations a.
NRC Actions None.
b.
Licensee Actions The licensee needs to resolve plant problems by correcting the root cause, with the objective of closing the issue with finality, rather than by using a quick-fix approach to mitigate the immediate symptoms.
The licensee should put more thoroughness, formality and attention to careful documentation into the process.
The licensee should also give management oversight and/or system engineering function more emphasis. with more responsibility and authority for reviewing all aspects of a problem.
G.
Safety Assessment /Ouality Veri fication 1.
Analvsis 4
This functional area includes all licensee review activities associated with the implementation of licensee safety policies, including licensee activities related to amendment exemption. and relief requests and other regulatory initiatives.
In addition. it includes licensee activities related to the resolution of safety issues.. safety committees, self-assessment activities.
and the effectiveness of the verification function in identifying and correcting substandard or anomalous performance, in identifying precursors of potential problems, and in monitoring the overall performance of the plant.
NRC inspection efforts in this area consisted of the core inspection program.
regional initiative inspections, and NRR program reviews.
The previous SALP l
report identified a high threshold for initiating nonconformance reports and tl.at the licensee was not proactive in identifying potential safety issues in this area.
During this assessment period. the licensee expanded the corrective action program to capture those deficient conditions that did not rise to the threshold of a nonconformance report.
The programmatic features appeared to be an improvement in that additional itas were captured for resolution that would not have been documented under the previous program.
Problem resolution. however, continued to show significant weaknesses.
While some problems were effectively resolved from a safety perspective. Others were not addressed or evaluated with sufficient rigor to assure that potential safety issues were clearly brought to management's attention and subjected to the comprehensive corrective action which would correct the root cause and prevent recurrence of the problem.
Examples of effective problem resolution were the items identified from the licensee's design basis reconstitution efforts, such as a single failure vulnerability in the emergency core cooling systems and the vulnerability of safety-related switchgear to missiles.
In these examples the licensee's understanding of the safety implications of the vulnerabilities was good, and the licensee implemented effective compensatory / corrective actions to resolve the problems.
Problems which were not adequately resolved included copper contamination in station batteries, temporary startup strainers in safety-related systems.
repetitive feedwater check valve leak rate test failures. primary coolant system relief valve drift problems, informal documentation of deficiencies in emergency condensate storage tank inspections, emergency diesel fuel oil high particulate leaking shutdown cooling suction valves, reactor building surveillance test failures, and, emergency operating support procedures with previously identified deficiencies that were not corrected.
The apparent causes for ineffective or protracted problem resolutions included:
(1) apparently unquestioning deferment of corrective actions until the " generic" or " industry" problems have been solved: (2) reluctance to take corrective action in those cases where explicit regulatory requirements did not exist: and (3) reluctance by working-level personnel to bring problems to the attention of plant management.
The licensee's protracted resolution of feedwater check valves that failed local leak rate testing repetitively and the absence of action to prevent recurrence or to mitigate the pr_imary coolant system relief valve setpoint drift are examples of a willingness to defer corrective action until generic issues are resolved.
The licensee's operability conclusion for emergency diesel fuel oil high particulate and their ineffective initial corrective actions for leaking shutdown cooling suction isolation valves are examples of a reluctance to take corrective action without explicit regulatory requirements.
The emergency condensate storage tank coating blistering which
_ _ _ _ was found during an inspection, but not documented in the work package, was an example of the type of problem not brought to management's attention.
Plant management has shown the ability and desire to effectively resolve issues once they are made aware of the deficiencies.
However, management continues to be, for the most part, reactive in identifying deficient conditions.
Historically. the licensee had established a performance indicator which placed an upper limit on the number of open corrective action documents.
This was viewed as a reward for a low number of corrective action system documents and may have discouraged the documentation of deficient conditions.
The initiation of nonconformance reports. historically, has been linked to reportability and/or operability.
This fostered the practice of documenting only reportable conditions in the corrective action systems rather than documenting deficient conditions and then giving them the appropriate review for reportability.
Deficiencies identified when equipment was not operable, or not required to be operable. were not likely to be captured by the licensee's corrective action systems.
The licensee's initiatives in implementing a deficiency report process. while very positive, have not yet corrected the attitudes that remain from the historical approach to corrective action systems.
At the end of the assessment period, the licensee had taken corrective actions to improve performance in resolving problems, many of which had not yet been implemented.
The licensee's programmatic initiatives appear sound however, the effectiveness of the licenseeLs corrective actions to address personnel performance and personnel attitudes have not yet been evaluated.
Licensee efforts have also been expended to develop and implement formal operability determination and evaluation processes.
These efforts were initiated in response to an operability determination which did not receive approval from the Station Operations Review Committee as required.
The licensee had generally been effective in evaluating the immediate impact of deficient conditions on the operability of safety-related equipment, but the immediate conclusion of operability may have encouraged delay of prudent corrective actions in some cases.
Also, some operability determinations contained weaknesses as discussed in plant operations.
The licensee's performance of oversight and critical self-assessment activities were marginally satisfactory.
The Station Operations Review Committee and the Safety Review and Audit Board met frequently to evoiuate emerging safety issues and to review other issues required by their charters and the Technical Specifications.
The oversight activities of these committees had not been effective in identifying the numerous problems which were found by the NRC inspectors in the special strainer inspection and in the corrective action inspection.
Although the quality assurance department issued quarterly trend reports that contained a comprehensive compilation of activities the reports did not highlignt problems or provide any assessment or recommendations as a result of indicated trends.
The audit and surveillance activities of the quality assurance department had not been effective in providing effective oversight of site activities to provide early identification of many of the issues that were identified in the special inspection on strainers and the corrective action inspection.
Station performance indicators had received limited distribution and did not contain an assessment of the indicators or draw conclusions that would have been of benefit to management in their oversight of site activities.
The licensee's system for identifying and evaluating internal and external operational experience and events had been effective as a management tool.
The Document and Event Review Committee actions to identify training work requests for improving training effectiveness based on operational experiences was a strength.
During the assessment period, the NRR staff reviewed a large number of license amendment requests and the safety analyses performed by and for the licensee.
Generally, the licensee's submittals were acceptable.
The number of licensing actions and activities appears to be appropriate for a plant of Cooper Nuclear Station's vintage.
Overall. the licensee's performance for this element of this functional area is average and could be improved by increased attention to timeliness, accuracy, and completeness.
The licensee's performance has been good. however. when it focussed its resources on an issue.
An example of this is the well-thought-out comments the licensee submitted regarding the j
staff's draft position on the generic dedication issues that resulted from the pilot inspections.
In summary, the facility has generally been operated in a safe manner.
While some problems were effectively resolved, others were not continuing to show I
significant weaknesses in the licensee's approach to the resolution of issues.
The causes for ineffective problem resolution included informality. deferment of corrective actions for generic problems, the absence of corrective action for those instances where explicit regulatory requirements did not exist, and poor personnel performance in bringing deficiencies to management's attention.
The licensee has planned or implemented extensive initiatives to improve performance in problem resolution. however. the effectiveness of the licensee's initiatives to address personnel performance and personnel attitudes remains to be seen.
The licensee's oversight and self-assessment activities were not always acceptable and will require additional management attention to assure that these activities provide management with the critical insights into the performance of the plant and the operating staff.
2.
Performance Ratina The licensee is considered to be in Performance Category 3 in this functional area.
l l
t 1
- 3. -Recommendations 7
- a. -NRC Actions Review the licensee S actions to enhance their process for performing critical
.self-assessments of their. performance and providing more depth to their corrective action processes.
b.
Licensee Actions Licensee management needs to ' perform a critical assessment of their corrective action processes in light of the problems identified by the NRC and correct-the process to assure that the process is teeting-licensee and NRC expectations.
l
'V.
SUPPORTING DATA AND SUMMARIES A.
Ma.ior Licensee Activities 1.
4a.ior Outaces
?
On February 10. 1992, the plant was shut down to replace degraded 250-volt i
battery cells.
The plant was returned to full' power on February 15.
On April 19, 1992, the plant was shut down to replace additional cells.in 250-volt batteries.
The plant was returned to full power on April 27.
j
'l On July 30. 1992, the licensee imposed a restriction of 90 percent power.to assure' emergency core cooling capability because of a single failure vulnerability. On September 11, 1992, the plant was shut down to implement a modification to eliminate the single failure vulnerability.
The plant was returned to full power on September 15.
' On October 1,1992, the licensee experienced a recirculation pump trip and operated in single loop at 50 percent power.
The plant was returned to full power on October 5.
'On January 24, 1993, the licensee reached the all-rods-out condition and began end-of-cycle coast down.
On March 5. 1993, the plant was shut down from about
- 80. percent power to.begin the refueling' outage. At-the end of the assessment period, the plant was-in the refueling outage with the core off-loaded.
2.
License' Amendments Eleven licensing: amendments were issued during this assessment period.
'3; : Ma.ior Modifications
~
.During the current' refueling outage'. the_ licensee planned to:
(1) install a hardened wet-well: vent at Cooper Nuclear Station in response to Generic 1
+
I i
25-Letter 89-16. (2) remove the rod sequence control system from the plant, and (3) remove the main steam line radiation monitor scram and containment isolation function from the plant.
B.
Direct Insoection and Review Activities NRC inspection activity during the assessment period included 40 inspections.
Approximately 5190 direct inspection hours were expended. which did not include operator licensing examinations or contractor hours.
- - -