ML20248C131
| ML20248C131 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/17/1989 |
| From: | Jordan E, Spessard R NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| Shared Package | |
| ML20248C108 | List: |
| References | |
| NUDOCS 8908090442 | |
| Download: ML20248C131 (125) | |
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...e-DIAGNOSTIC EVALUATION TEAM REPORT FOR THE BRUNSWICK STEAM ELECTRIC PLANT UNITS 1 AND 2 JULY 1989 U.S. Nuclear Regulatory Commission Office for Analysis and Evaluation of Operational Data Division of Operational Assessment Diagnostic Evaluation and Incident Investigation Branch 8908090442 890802 ADOCK0500g"g4 Enclosure {
PDR P
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Licensee:
l Carolina' Power & Light Company 1
Facility:
Brunswick Steam Electric Plant Units 1 and 2
~ Location:
On the Cape. Fear River in Brunswick County. North Carolina Approximately 20' Miles South of Wilmington Docket Nos.:
,50-325 and 50-324 y
- vefuation Period:
April 10, 1989 through May 5, 1989 h
. Team Manager:
l R. Lee Spessard, AEOD Team Leader:
John W. Craig, NRR Team Members:
Frederick R..Allenspach, NRR i
Henry.A. Bailey, AE0D Jesse.L. Crews, RV David Hills, RIII-Eric-J. Leeds, AE00 Bruce H. Little..RIII Ronald L. Lloyd, AE0D Robert L. Perch, AE0D Robert J. Stransky, AEOD Bill S. Thurmond, AEOD Chris A. VenDenburgh, NRR
-Kevin P. Wolley, AE00
~ Consultants:
Robert Gura, NRC Contractor Robert Matlock, NRC Contractor Gary Overbeck, NRC Contractor Jonathan Wert, NRC Contractor Submitted Ey:
t.v>L f /3 9
R. Lee Spessaray Team Manager Date Brunswick Diagnostic Evaluation Team, AEOD Approved By:
7 s
Edward L/ drdan, Director Office to Analysis and Evaluation
'Djfth /
of Opi ational Data
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EXECUTIVE
SUMMARY
)
During the Nuclear Regulatory Commission (NRC) Senior Management Meeting in December 1988, NRC executives recommended that a Diagnostic Evaluation be conducted at the Two Unit Brunswick Steam Electric Plant (Brunswick).
This recommendation was primully based upon (1) the overall plant performance which was poor or declining in several areas as reflected in the most recent Systematic Assessment of Licensee Performance Report, (2) numerous equipment failures, and (3)' repetitive safety system failures.
The equipment failures
)
resulted in two NRC Augmented Inspection Teams sent to the site in January 1988
)
and July 1988.
1 i
Based.on these issues, and the uncertainty about Carolina Power & Light Company's (CP&L) ability to identify and implemer.t effective action to correct their causes, the Executive Director for Operations (EDO) directed the Office for Analysis and Evaluation of Operational Data to conduct a diagnostic evaluation at the Brunswick facility to assess performance and to identify the underlying causes for poor performance at the facility.
The EDO directed that a Diagnostic Evnluation Team conduct a broad-based evaluation of overall plant operations and the adequacy of CP&L's major programs for supporting safe plant-operation.
4 An 18 member team spent 3 weeks at the Brunswick facility during April and May 1989, evaluating the functional areas of management and organization, operations, maintenance, surveillance and testing, quality programs, and engineering design and technical support.
Based upon the team's evaluation, the root causes of poor performance during the past few years have been (1) inadequate corporate mana m ent coincident with a period of past site management weaknesses, (2) the failure to clearly define and communicate site goals, priorities, and expectations, (3) cultural issues including (a) the failure of CP&L management to adequately review and ur.derstand Brunswick's declining level of performance, and (b) the lack of individual accountability and teamwork, (4) an ineffective root cause determination and corrective action program, and (5) an ineffective engineering design and technical support program.
The team noted that many of the current problems at Brunswick were previously addressed in the 1982 Brunswick improvement Program.
Although short-term performance improvements were seen after implementation of this program in 1983, there was a general failure on the part of CP&L corporate and site manegement to ensure that improvement were sustained and broadened.
There was a lack of corporate oversight, leadership, and direction in the mid 1980s during a period of continued weaknesses in site management.
The result, in part, was a subsequent decline in overall performance and a general inability on the part of CP&L to evaluate Brunwick's performance accurately.
As a result of extensive reassignments of CP&L managers at the corporate office and at Brunswick, many managers in the Nuclear Generation Group had held their present positions for less than 6 months.
This management team was in the process of defining and communicating safety performance goals and individual performance expectations and norms.
Although the site-corporate relationship had not been clearly defined, site managers were implementing actions to improve the organizational culture by establishing individual accountability, making commitments to "do it right" at all levels within the Brunswick i
.]
organization, and striving to improve communication and teamwork.
- However, these initial actions were not viewed with optimism by working level CP&L personnel, since they had not been reinforced by incorporation into site directives, procedures, and other administrative controls.
In addition, there was a lack of confidence that these initiatives would succeed since similar ones by past management had not.
Additionally CP&L was ccnducting an organizational analysis to review the company's environment, its internal and external customers, and the manner in which business was conducted.
The results of the organizational analysis were expected to be made known in the fall of 1989 and were expected to result in j
additional personnel and/or organizational changes at the site and corporate level. These anticipated changes and the associated internal review process were creating an increased level of anxiety in the company, but no more than would normally be expected for an organization undergoing changes of this magnitude and duration.
The team concluded that while many of the changes discussed by CP&L managers were considered to be positive, only a few had been formally defined and implemented.
The team found that several of the fundamental weaknesses addressed in the 1982 Brunswick Improvement Plan were still present and, thus, hu not been adequately resolved.
Specifically, the corrective action program lacked provisions for effective problem identification and root cause determination.
Also, the implementation of quality program activities was weak. Audits were ineffective in identifying weaknesses in areas such as engineering design and/or failed to receive adequate attention.
The team found major weaknesses in the engineering design and technical support area.
For example, significant problems were identified during the design review of the service water system, and several of these problems were similar to the findings identified during CP&L's 1987 self-assessment of the high pressure coolant injection system.
Longstanding weaknesses in plant configuration control and er.gineering support activities, as evidenced by these reviews, indicated that equipment problems would continue to be prevals.r at Brunswick.
Thus, the basis for confidence in the reliability and operability of safety and nonsafety equipment under credible off-normal conditions was brought into question.
Persistent equipment problems have fostered an attitude I
of "living with" or " working around" chronic hardware deficiencies.
Frequently, CP&L efforts had focused on the " easy fix" rather than on timely and effective root cause determination and on permanent solutions to problems.
Overall, the team concluded that recent managernent changes and initiatives were having a positive effect.
Of particular note was the involvement and presence of senior site managers in the plant.
The new management team is competent and l
capable of making the changes necessary to develop a safety culture and improve i
l Brunswick's overall performance.
The team determined that several areas l
needed additional management attention.
These included (1) implementation of an effective corporate oversight program to provide leadership and direction, l
and to accurately monitor and assess Brunswick performance, (2) definition of l
site safety goals, priorities, and expectations which are effectively l
l communicated to and understood at all levels, (3) implementation and monitoring the effectiveness of actions to establish the desired culture at Brunswick, (4) implementation of an effective corrective action program having a lower
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threshold for problem identification and effective measures for root cause determination, and (5) implementation of an integrated program to correct engineering design and technical support weaknesses involving both equipment failures and support activity weaknesses such as configuration control and safety evaluations.
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TABLE OF CONTENTS Pag _e EXECUTIVE
SUMMARY
i ACR0NYMS.............................................................
v
1.0 INTRODUCTION
I 1.1 Background..................................................
I 1.2 Scope and 0bjectives.......................................
-2 I
1.3 Me t h o d ol o gy.................................................
3 1.4 Plant Description..........................................
3 1.5 Organization...............................................
3 2.0 EVALUATION RESULTS..............................................
6 2.1 Findings and Conclusions...................................
6 2.2 Root Cause Analysis........................................
15 3.0 DETAI LED EVALUATION RESU LTS.....................................
17 3.1. Management and Organization...............................
17 3.2 Operations.................................................
27 3.3 Maintenance................................................
41-3.4 ' Surveillance and. Testing...................................
48 3.5 - Quality Programs and Administrative Controls Affecting Quality..........................................
61 3.6 Engineering Design and Technical Support...................
69 4.0 EXIT MEETING....................................................
98 APPENDIX A - Exit Meeti ng Summary...................................
100 APPENDIX B - EDO Direction to the Brunswick Diagnostic Eval uati on Te am........................................
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1 ACRONYMS AC Alternating Current ADR Audit Deficiency Report AE0D Office for Analysis and Evaluation of Operational Data AI Adc.inistrative Instruction AIT Augmented Inspection Team ALARA-As-Low-As-Reasonably-Achievable l'
AMMS Automated Maintenance Management System A0 Auxiliary Operator AP Administrative Procedure ASME American Society of Mechanical Engineers ASSD Alternate Safe Shutdown BI Benefit Index BIP Brunswick Improvement Plan BOP Balance of Plant BPV Bypass Valve BSEP-Brunswick Steam Electric Plant BWR Boiling Water Reactor
.CATQ
. Condition Adverse to Quality CD0 Central Design Organization CEO Chief Executive Officer CFR Code of Federal Regulations CM Corrective Maintenance CMOT Corporate Management Oversight Team CNS Corporate Nuclear Safety CP&L 1, Carolina Power & Light Company CQAD Corporate Quality Assurance Department DBD Design Basis Document DC Direct Current DET Diagnostic Evaluation Team D/P Differential Pressure ED0 Executive Director for Operations EER Engineering Evaluation Request EHC Electrohydraulic Control EOF Emergency Operating Procedures EPG Emergency Procedure Guidelines ESF Engineered Safety Featyre E&RC Environmental and Radiation Control EWR Engineering Work Request FP-Q Fire Protection-Q FSAR Final Safety Analysis Report FW Feedwater GDC General Design Criteria GE General Electric GPM Gallons Per Minute v
HPCI-High' Pressure Coolant Injection HPES.
Human Performance Evaluation System HWC Hydrogen Water Chemistry
'I&C-Instrumentation and-Control IE
. Inspection and Enforcement-IGSCC Intergranular Stress Corrosion Cracking IHSI Induction Heat Stress Improvement INPO Institute of Nuclear Power Operations
-IR Incident Report ISI Inservice Inspection
.IST Inservice Testing i
.JC0 Justification for Continued Operation JO Job Order KW.
Kilowatt LCO Limiting Condition for Operation LOCA Loss of Coolant Accident LER-Licensee Event Report LOOP Loss of Offsite Power MAC Motor Actuator Characterized MCC Motor Control Center-
.MILSTD Military Standard MOV Motor-Operated Valve MP Maintenance Policy MSIP Mechanical Stress Improvement MSIV Main Steam Isolation Valve MST Maintenance Surveillance Test MTI Maintenance Team. Inspection NCR Nonconformance Report NED Nuclear Engir.eering Department NGG Nuclear Generation Group NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NSSS Nuclear Steam Supply System 0A Organizational Analysis OM Outage Management OP Operating Procedure O&M Operating and Maintenance ONS Onsite Nuclear Safety PAM Procedures Administration Manual PCV Pressure Control Valve PEU Performance Evaluation Unit PID Project Identification PM Preventive Maintenance P/M Plant Modification vi
\\
PMT Post-Maintenance Testing PNSC Plant Nuclear Safety Committee POM Plant Operating Manual PSID Pounds Per Square Inch Differential PSIG Pounds Per Square Inch Gauge PT Periodic Test l
QA Quality Assurance-l QAP Quality Assurance Procedure QC Quality Control Q-Team Quality Team RBCCW Reactor Building Closed Cooling Water RCI Regulatory Compliance Instruction RCIC Reactor Core Isolation Cooling RFP Reactor Feedwater Pump RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RICSIL Rapid Information Communication Service Information Letter R0 Reactor Operator RPV Reactor Pressure Vessel RTT Real Time Training RWCU Reactor Water Cleanup SALP Systematic Assessment of Licensee Performance SAT Station Auxiliary Transformer SCATQ Significant Condition Adverse to Quality SDCD System Design Criteric Document SF Shift Foreman SIL Service Information Letter SJAE Steam Jet Air Ejector 505 Shift Operating Supervisor SPTMS Suppression Pool Temperature Monitoring System SRO
' Senior Reactor Operator STSI Short Term Structural Integrity STSS Surveillance Tracking Scheduling System SW Service Water SWFCG Site Work Force Control Group TDH Total Discharge Heat TIL Technical Information Letter TPC Total Project Cost TQ Total Quality TS Technical Specification TSI Technical Specification Interpretation TSM Technical Support Memorandum T/S Technical Support UAT Unit Auxiliary Transformer UE&C United Engineers and Constructors UFSAR Updated Final Safety Analysis Report vii
VMP Vibration Mcn'itoring Program VR Vendor Recommendation WR Vork Request C
Degree Centigrade
'F Degree Fahrenheit i,
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1.0 INTRODUCTION
1
1.1 Background
An appropriate starting point for the discussion of current performance problems at the Brunswick Steam Electric Plant (Brunswick) is 1982.
As a result of the Nuclear Regulatory Commission (NRC) inspections in July 1982, the NRC issued a Confirmatory Order, dated December 1982, based upon a conclusion i
that the Carolina Power & Light Company (CP&L) had given insufficient attention l
to a number of site activities including the corrective oction program and the l
quality of, and response to, audits.
The Confirmatory Order required that CP&L i
implement the improvement actions contained in the Brunswick Improvement Plan (BIP).
j l
1 In the years immediately following the implementation of the BIP (1983-1985),
performance improved. However, corporate and site management action was insufficient to ensure performance improvements were sustained; momentum was lost and performance stagnated or declined in most areas.
More recently, Brunswick has experienced chronic equipment and safety system failures.
A number of significant events occurred at Brunswick during 1988 which raised NRC concerns about the facility.
In early January 1988, an NRC Augmented Inspection Team (AIT) was dispatched to Brunswick to review events related to the failure of two sets of redundant containment isolation valvet following a manual reactor trip. Among other significant findings, the AIT determined that the licensee's programs implemented to identify and elevate precursor events to appropriate levels of management were ineffective.
Throughout the first 6 months of 1988, a significant number of repetitive failures of direct current (DC) motor-operated valves (MOV) in the high pressure coolant injection (HPCI) and the reactor core isolation cooling (RCIC) systems occurred.
These valve problems, combined with repetitive safety system failures and multiple equipment impediments to operators, raised serious concerns about the licensee's commitment to an effective root cause analysis and corrective action program and the capabilities of the licensee's engineering support staff.
An NRC Confirmatory Action Letter was issued and a shutdown of Unit 1 was commenced on July 13, 1988, to conduct work related to the HPCI injection valve DC motor operators.
During the shutdown, several additional equipment failures occurred between July 13 and 15 which extended the shutdown and challenged all levels of the operations, maintenance, and technical support staff.
On the af ternoon of July 15, an AIT was dispatched to review the Unit I shutdown.
The AIT found a pattern of repetitive equipment failures which were not trended and corrective action was not aggressively implemented.
The AIT concluded that the cumulative effect of the multitude of equipment problems had resulted in Operations Unit personnel who had learned to " live with" or " work around" equipment problems.
The most recent Systematic Assessment of Licensee Performance Report, November 1988, concluded that overall performance of the CP&L Brunswick facility was found to have decreased significantly from the previous assessment period. Although performance was considered to be satisfactory, an overall declining performance trend was noted and several functional areas reuived Category 3 ratings, including Engineering / Technical Support and Safety Assessment / Quality Verification.
Managers' tolerance for operation of the 1
facility with potentially unreliable equipment resulted in a pattern of plant operation with continuous temporary and/or compensatory measures.
During the 1988-1989 period, numerous interactions between NRC and CP&L senior management', and equipment failures at the site, sensitized the licensee to the need to take action to improve the safety performance at Brunswick.
In response to the NRC concerns, CP&L corporate managers established a Corporate Management Oversight Team (CMOT) to evaluate Brunswick site management and staff performance.
As a result, CP&L initiated a Nuclear Management Appraisal conducted by an outside management contractor (Cresap).
During the latter half of 1988, the licensee initiated a number of management changes at both the corporate office and at the Brunswick site.
These CP&L management j
reassignments were substantial as indicated in Figures 1.5-1 and 1.5-2.
The changes' involved rotation of CP&L managers and did not include managers who were new to CP&L.
The current status of CP&L organizational culture and programs is one of change l
i and transition.
Many of the managers responsible for activities at Brunswick had been in their current assignments for less than 6 months at the time of the evaluation.
These recent management changes continuing equipment problems, and declining Brunswick performance were area,s discussed during the NRC Senior Management Meeting in December 1988.
As a result of these discussions, a recommendation was made by senior NRC managers to the Executive Director of Operations (EDO) that a diag'iostic evaluation be conducted at Brunswick to provide additional information regarding performance and to determine the root cause(s) of identified problems.
1.2 Scope and Objectives The EDO directed the Diagnostic Evaluation Team (DET) to conduct a broadly structured evaluation to assess overall plant performance and the effectiveness of CP&L's major initiatives for improving plant performance at Brunswick.
To provide the assessment of plant performance requested by the EDO memorandum, the DET evaluated several functional areas with the following specific goals.
o Functional Area Effectiveness:
Assess the effectiveness (strengths and weaknesses) of the operations, maintenance, surveillance and testing, quality programs, and engineering areas in ensuring safe plant operation; assess the adequacy of procedures, programs, and compliance by the licensee to codes, standards, commitments, and regulatory requirements.
o Technical Support:
Assess the effectiveness (strengths and weaknesses) of the technical support provided to the station in the areas of operations, surveillance testing, maintenance, and operator training and quality verification.
o Engineering Support:
Assess the quality and timeliness of engineering support provided by the engineering departments, including analysis, design modifications, equipment operability determinations, technical program development, and technical advice.
2
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Management and Organization:
Assess the effectiveness (strengths and j
weaknesses) of management leadership, direction, oversight and involvement, and tM organizational climate and culture at Brunswir.k.
- 1. 3 Methodoloov i
The diagnostic evaluation at Brunswick combined several methods of assessment, with emphasis on the int'rfaces and relationships between operations and e
various corporate and plant support groups.
In the course of the etaluation, the team observed plant operaticGs, reviewed pertinent documents, conducted interviews with plant and corporate personnel at all levels, and assessed the functional areas of operations, surveillance and testing, maintenance, l
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engineering design and technical support, quality programs, and management and l
organization.
The team used contractors to assist in the evaluation of engineering design and technical support. and management'and organization.
Before arriving onsite, the team devoted several weeks to in office document review and preparation that included team meetings and briefings by NRC regional and Headquarters staff knowledgeable about CP&L and Brunswick. On April 10, 1989, the team began an initial 2-week evaluation at the station and i
corporate offices.
The team returned to the Brunswick site and corporate offices on May 1, 1989, for an additional week to complete the evaluation.
Throughout the onsite evaluation, team representatives met periodically with f
the plant manager and corporate officers to discuss team activities, j
observations, and preliminary findings.
The team also met at the end of each day to discuss observations and findings in each functional area.
The Brunswick Resident Inspectors frequently attended these meetings and functioned as technical advisors to the team during the onsite evaluation.
The exit meeting with corporate officials and managers was held on June 16, 1989 at NRC Headquarters (see Section 4.0 for details).
1.4 Plant Description 1
i The Brunswick site, located in Brunswick County, North Carolina, is about 20 miles south of Wilmington, North Carolina, and contains Brunswick Units 1 and 2.
Both units are General Electric (GE) Boiling Water Reactors (BWR) 4 with a Mark-1 containment.
The licensed thermal power for both units is 2436 MWt with an electric rating of 821 MWe.
Construction of both units was authorized by the Atomic Energy Commission /NRC by issuance of a construction permit on February 7, 1970.
Unit 2 achieved initial criticality on March 20, 1975, and Unit 1 achieved initial criticality on October 8, 1976.
Full power operating licenses were issued to Unit 2 on December 27, 1974, and Unit 1 on November 3, 1975.
Unit 2 began commercial operation on November 3, 1975, and Unit 1 on March 18, 1977.
1.5 Organization The CP&L organizations directly involving Brunswick, as of April 10, 1989, are illustrated in Figures 1.5-1 and 1.5-2.
Although the Nuclear Engineering Organization currently has a large staff located onsite, CP&L plans to relocate the majority of the engineering organization to corporate headquarters with a small technical su] port staff (10-15) remaining at the site.
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2.0 EVALUATION RESULTS 2.1 Findings and Conclusions Carolina Power & Light Company (CP&L) and the Brunswick site were in a period of organizational renewal and transition.
Several studies or assessments related to organizational performance had been performed by CP&L in the past two years, and a major assessment was in progress during the evaluation.
A fundamental aspect of this transitional period was the reassignment of muy of the senior corporate and Brunswick site managers in the 6 months precedng the evaluation.
This management team was in the process of defining and communicating safety performance goals and individual performance expectations and norms.
Although the site-corporate relationship had not been clearly defined, site managers were implementating actions to improve the organizational culture by establishing individual accountability, making commitments to "do it right" at all levels within the Brunswick organization, and striving to improve communication and teamwork.
However, these initial actions were not viewed with optimism by working level CP&L personnel, since they had not been reinforced by incorporation into site directives, procedures, and other administrative controls.
In addition, there was a lack of confidence that these initiatives would succeed since similar ones by past management had not.
Additionally, CP&L was conducting an organizational analysis (0A) to review the company's environment, its internal and external customers, and the manner in which business was conducted.
The results of the OA were expected to be made known in the fall of 1989 and were expected to result in additional personnel and/or organizational changes at the site and corporate level.
These anticipated changes and the associated internal review process were creating an increased level of anxiety in the company, but no more than would normally be expected for cn organization undergoing changes of this magnitude and duration.
The team concluded that while many of the changes discussed by CP&L managers were considered to be positive, only a few had been formally defined and implemented.
The new site-corporate relationship had not been clearly defined.
The team found that several of the fundamental weaknesses addressed in the 1982 Brunswick Improvement Plan (BIP) were still present and, thus, had not been adequately resolved.
Specifically, the corrective action program lacked provisions for effective problem identification and root cause determination.
e Mso, the implementation of quality program activities was weak.
Audits were u.J fective in identifying weaknesses in areas such as engineering design and/or failed to receive adequate attention.
The team found major weaknesses in the engineering design and technical support area.
For example, significant problems were identified during the l
design review of the service water (SW) system, and several of these problems were similar to the findings identified during CP&L's 1987 self-assessment of the HPCI system.
Longstanding weaknesses in plant configuration control and engineering support activities, as evidenced by these reviews indicated that equipment problems would continue to be prevalent at Brunswick.
Thus, the basis for confidence in the reliability and operability of safety and nonsafety equipment under credible off-normal conditions was brought into question.
Persistent equipment problems have fostered an attitude of "living with" or s.
6
" working around" chronic programmatic or hardware deficiencies.
Frequently, CP&L efforts had focused on the " easy fix" rather than on timely and effective root cause determination and on permanent solutions to problems.
Overall, the team concluded that recent management changes and initiatives were having a positive effect.
Of particular note was the involvement and presence of senior site managers in the plant. 'The new management team is competent and capable of making the changes necessary to develop a safety culture and improve Brunswick's overall performance.
The team determined that several areas needed additional management atter. tion'.
These included (1) implementation of an effective corporate oversight program to provide leadership and direction, and to accurately monitor and assess Brunswick performance, (2) definition of site safety goals, priorities, and expectations which are effectively communicated to and understood at all levels,-(3) implementation and monitoring the effectiveness of actions to establish the desired culture at Brunswick, (4) implementation of an effective corrective action program having a lower threshold for problem identification and effective measures for root cause determination, and (5) implementation of an integrated program to correct engineering design and technical support weaknesses involving both equipment failures a.id support activity weaknesses such as configuration control and-safety evaluations.
The findings and conclusions for each functional area evaluated are summarized below with a reference to specific report sections for additional details.
2.1.1 Management and Organization 1.
Carolina Power & Light Company had spent an excessive amount of time studying potential organizational change issues and plant performance problems such that needed changes and fixes had been unduly delayed.
For example, the delayed implementation of the Central Design Organization (CDO) at Brunswick had adversely affected its engineering design and technical support.
The 0A had been undcrway for approximately 2 years, and the results and conclusions of the analysis were not to be implemented or made known to employees until Fall 1989. The delay in implementation of the conclusions of the analysis was, based upon interviews, the single most significant factor affecting employee morale, attitudes, and motivation.
(Sections 3.1.1 and 3.1.2) 2.
A lack of a sense of ownership was evident throughout the organization (corporate and site), and there was a lack of a commitment to "do it right the first time." However, improvements were beginning in these areas.
Employee morale at Brunswick was typical of a company going through major reorganization and transition, except for the technical support group where it was lower.
(Section 3.1.2) 3.
Corporate oversight, leadership, and direction had been inadequate to i
compensate for past site management weaknesses.
The corporate approach to managing site activities could generally be described as laissez-faire.
The lack of corporate involvement was evidenced by Quality Assurance (QA) programmatic weaknesses, a poorly planned and implemented reorganization l
of engineering design and technical support, and the failure to correct repetitive equipment failures.
(Section 3.1.3) 7
s 4.
Current senior site managers were substantially involved in day-to-day plant activities and one of the most significant actions initiated by this team had been to increase the amount of time managers spent in the plant.
Additionally, these managers were sensitive to cultural issues and had l:
L implemented some corrective action measures, such as communications and teamwork quality teams.
However, there was not an overall effective means to respond to people issues.
Despite existing programs ar.d methods, the prevalent culture at Brunswick was still largely comprised of the traditional culture characteristics.
(Sections 3.1.2 and 3.1.3) 5.
Site safety goals, priorities, and expectations were not clearly defined and communicated to all organizational levels.
However, the Total Quality (TQ) communication team recently made recommendations regarding revision
)
and clarification of Brunswick goals that coul.1 translate general goals and policies into meaningful working goals.
There were indications that
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teamwork and communications had recently improved.
(Section 3.1.3) l 6.
In the past,. problem solving, decisionmaking, and prioritization activities were largely reactive and driven by regulatory, industry, or equipment availability pressures.
Brunswick was still largely a reactive organization and it will remain that way until more of its people, management, organizational transition, and equipment problems are corrected.
Additionally, the different organizational unit prioritization systems were ineffective and resulted in delays in completing actions.
(Section 3.1.4) 7.
The Corrective Action Program, as dis:ussed in paragraph 2.1.5.2 below, was inadequate.
There was no focal point of root cause expertise within the Brunswick organization, the threshold criteria for formal root cause (by procedural guidance) was too high, and training given to date, concerning the various methods of root cause determination was rudimentary.
Also, there had been a lack of corporate office sensitivity and commitment to the Corrective Action Program in that there was no focal point within the corporate office, to assure oversight and direction and assess the effectiveness of corrective action programs and processes throughout the Nuclear Generation Group.
Additionally, Brunswick had not implemented a Human Performance Evaluation System (HPES) which could improve the analysis and evaluation of human performance problems at a low, "near-miss," threshold.
(Section 3.1.4) 8.
The process for business planning at Brunswick was ineffective because it l
l hampered effective communication within the site organization as well as between the site and corporate office on Business Plan / Budget related matters.
It also resulted in a mismatch between the Five-Year Business Plan and Budget causing a substantial lessening of site management's sense of ownership of this plan.
(Section 3.1.5) 9.
The current management team possesses good human relations, technical, and management skills.
This team was competent and capable of making the changes necessary to establish a safety culture at Brunswick and improve i
overall plant performance.
Increased emphasis was being placed on human resource development and people-related issues.
(Section 3.1.6) 1
L 10.
Management succession plans had'been developed down to the supervisory level at Brunswick.
However, little evidence of effective career plannirg and development existed, including job rotation.
(Section 3.1.6) 2.1.2 Operations 1.
The operators' conduct within the control room was professional.
Control room' access and noise level were well controlled by the Shift Foremen.
Shift relief turnovers and crew briefings were performed in a thorough and disciplined manner.
(Sections 3.2.2 and 3.2 2.2) 2.
The Shift Operating Supervisors and Shift Foremen exercised strong l
-leadership and control of the shift crews during both routine and l.
unplanned evolutions.
(Section 3.2.2.1) 3.
Control room log entries were rudimentary or nonexistent for many significant occurrences. The log entries frequently lacked sufficient information to allow management assessment of operational problems for cause and correction.
(Section 3.2.2.3) 4.
Communications practices within the individual shift crews were adequate.
Communications within the Operations Unit and between the Operations Unit i
and other site lnits, were improving as the result of several management l
initiatives.
Despite these initiatives, some difficulty in promoting management goals and objectives was still evident.
(Section 3.2.2.4) 5.
The operations staff demonstrated an adequate level of knowledge of plant systems and integrated plant operations.
The Auxiliary Operators l
exhibited a level of plant knowledge and skill higher than expected for their position.
(Section 3.2.2.6) 6.
Procedures were generally adequate to perform the required tasks, although some were cumbersome. While observed, the opcrators adhered to procedures during plant evolutions with the exception of minor deviations.
- However, several operators did not exhibit an attitude of strict procedural adherence.
(Section 3.2.3) 7.
Standing Instructions were not being used effectively to provide instructions and were an unnecessary burden to the operators.
An excessive numser of miscellaneous instructions were in effect that were neither indexed nor administratively controlled.
Two currently active instructions had already been incorporated into procedures, but not deleted from the Standing Instructions.
(Section 3.2.3.1) 8.
The Emergency Operating Procedures (EOP) were not consistent with the BWR Owners Group Emergency Procedure Guidelines.
The procedure format prioritized operator actions according to a predetermined significance and incorporated specific response strategies such as post-scram recovery and station blackout.
This format caused the operators to delay implementation of accident mitigation actions during the execution of the E0Ps on the simulator.
(Section 3.2.3.2) 9.
There were an excessive number of control room instrumentation and plant equipment deficiencies that placed an unnecessary burden on the operators and detracted from their ability to operate the plant.
This burden was 9
I further exacerbated by a recent program to reduce the number of trouble i
tags in the control room.
This resulted in no indication on the main control board to acknowledge the abnormal status of equipment.
(Sections 3.2.4.1 and 3.2.4.2)
- 10. Many operators had grown accustomed to operating the plant with an excessive amount of inoperable or poorly functioning equipmer.t.
Operators indicated that they did not consider the number of outstanding work requests on plant equipment to be a problem and exhibited a c.omplace attitude towards equipment problems.
The team concludad that the operators attitude and complacency towards equipment problems in generai
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had been caused by years of operation while living with undesirable conditions.
(Section 3.2.4.3) 11.
The current management team was more involved in plant activities than the past management team.
Operations management demonstrated an increased level of attention and support of plant activities.
Improvement initiatives,'although positive, in many cases lacked clear definition of responsibility and accountability and had not been effectively implemented.
(Sectior 3.2.5.2) 12.
The overall training program was of high quality and effectively implemented.
However, excessively high instructor workload and a pay freeze resulted in low instructor morale.
(Sections 3.2.6.2, 3.2.6.3 and 3.2.6.4) 13.
The simulator had severe modeling deficiencies involving the core and the nuclear boiler models and their interface with the other simulator models.
Although the licensee was aware of these deficiencies and was in the process of making improvements to the simulator fidelity, the current simulator responses were misleading to the operators and could affect their response during transients.
The simulator was not certifiable in its present configuration because of these modeling limitations.
(Section 3.^.6.5) 14.
The Real Time Training group, which was part of the Operations Unit, provided excellent training to the operators in the areas of industry concerns and plant modifications.
(Section 3.2.6.6) 2.1.3 Maintenance 1.
Morale within the Maintenance Unit was good and craft personnel were knowledgeable.
The standardization of technical training and the use of qualification signoff cards to formalize and document the training was a program strength.
(Section 3.3.1) 2.
The institution of duty day and backshift maintenance coverage was a positive step toward more efficient utilization of the maintenance staff.
(Section 3.3.1) 3.
The use of the Site Work Force Control Group process was a good work planning practice, but the low level of formalized administrative control of the group's activities was a potential weakness.
(Section 3.3.2.1) i 10
L
,4 x
L 14.
The Automated Maintenance Management System was an excellent system for controlling maintenance activities and maintaining maintenance records.
This was a computerized work request generation, planning, scheduling, r.nd retrieval system.
(Section 3.3.2.2) 1 5.
The Maintenance Unit procedures were consistently formatted and well
' organized for. ease of use.
The procedures reviewed were technically accurate and provided a high level of detail.
(Section 3.3.2.3) 6.
Although the maintenance work backlog had been steadily trer. ding downward since early 1988, it was still too large, and continued effort was needed in this area.
(Section 3.3.2.4) 7.
The reliability and availability of plant systems and equipment, including control room instrumentation, was poor.
(Sections 3.3.3 and 3.3.4) 8.
Licensee-development of corrective actions for chronic equipment problems was often excessively slow, root cause analysis was poor and ineffective, and expediting repairs that would reduce the burden on operators was a low priority in the Maintenance Unit.
Once resources were focused on a problem, the corrective actions were generally of high quality.
(Sections 3.3.3 and 3.3.4) 9.
The length of time consumed in effecting repairs'was often excessive, and maintenance efforts were often hampered by slow and ineffective assistance from the Technical Support Unit.
(Sections 3.3.3 and 3.6.1) 10.
The Brunswick motor-operated valve (MOV) maintenance program had many strong provisions, but these were offset by significant weaknesses in program _ implementation.
Significant additional effort and management attention were needed to ensure the many strong provisions of the program were consistently implemented in the plant.
(Section 3.3.5) 11.
Better communications and teamwork among organizational units were needed to recognize, analyze, and correct problems in a timely manner.
(Sections 3.3.3 and 3.3.4) 2.1. 4 Testing 1.
The Surveillance Tracking and Scheduling System (STSS) was an effective method to schedule and track technical specifications (TS) surveillance tests.
The system was computerized and used for identifying, scoping, scheduling, tracking and closing all surveillance and regulatory commitments and requirements.
However, there was no schedule to verify the accuracy of the TS data base.
(Section 3.4.1.1) 2.
The offsite to onsite electrical distribution system was not periodically tested as required by the TS.
The licensee had never performed an analysis or test to demonstrate that the design of this distribution system met the requirements of the General Design Criteria (GDC) 17 concerning the availability of the alternate offsite electrical source.
In addition, the limiting conditions for operation of the TS were not observed when one of the two sources of offsite to onsite power were out of service. These deficiencies were largely due to the implementation of 11
L t
o two technical specification interpretations (TSI) that were based on erroneous assumptions regarding GDC-17 requirements.
(Section 3.4.1.2) 3.
The licensee had not performed stroke time testing for some of the containment; isolation valves specified in the TS.
Although a TS change request had been submitted in 1984 to remove these valves from the surveillance requirements, periodic testing had not been performed in the interim.
(Section 3.4.1.2) 4.
The instrument and control surveillance testing procedures were consistently formatted and provided a high level of technical detail.
The Procedures Administration Manual, intended to standardize procedures, as required by the BIP, was not being effectively implemented.
As a result,
.the overall standardization of site procedures had not been accomplished.
(Section 3.4.1.3) 5.
There was no corporate guidance provided for the development of the Inservice ~ Inspection / Inservice Test (ISI/IST) program and no formal provision to incorporate lessons learned from other CP&L facilities into the programs at each site.
(Section 3.4.1.4) 6.
Nuclear SW system IST controls were inadequate to provide standardized surveillance test conditions and permit proper evaluation of pump performance.
(Section 3.4.1.4) 7.
Technicians and operators observed performing surveillance testing were knowledgeable and activities were coordinated with plant operation.
(Section 3.4.2) 8.
The program to correct the numerous plant labeling deficiencies was ineffective.
The organization responsible for tt-labeling program was understaffed and a systematic and comprehensive program for the identification, evaluation, and prioritization of plant labeling deficiencies had not been developed.
(Section 3.4.2) 9.
There was poor coordination between the preventative maintenance and IST vibration monitoring and testing groups within the TS unit.
The preventative maintenance vibration program had many strengths and good practices which were not being transferred to the IST program.
(Section 3.4.3.1) 10.
Weaknesses existed in the maintenance work planning and performance processes that failed to ensure adequate post-maintenance testing on safety-related equipment.
(Section 3.4.3.2) 2.1.5 Quality Programs and Administrative Controls Affecting Quality 1.
The onsite QA organization consisted of experienced, well qualified personnel.
(Section 3.5.1) 2.
The Corrective Action Program was inadequate due to (a) weaknesses in the problem identification process as a result of an inconsistent and high threshold for determining significance, (b) an ineffective trending program, (c) investigations which often lacked sufficient depth to identify the root causes and major contributing factors, (d) untimely s.
12
g - - - - - - -, - -, - -
s implementation of corrective actions, and (e) employee perceptions concerning adverse personnel actions resulting from identification of deficiencies.
(Section 3.5.2) 3.
Corporate QA activities were ineffective and reflected a corporate attitude of noninvolvement in site activ; ties.
There was a lack of corporate ownership to assist sites in resolving concerns identified in trend reports.
The programmatic focus of audits performed by corporate QA were inadequate, focused on document reviews, and were noc performance based.
(Sections 3.5.2 and 3.5.3) 4.
Onsite QA surveillance activities were focused on activities which provided meaningful information and an increased use of performance-based surveillance was evident.
(Section 3.5.4) 5.
The Brunswick safety review committees were performing required review functions, except that Onsite Nuclear Safety (ONS) was not reviewing industry advisories or efforts to reduce personnel errors.
Prior reviews by the Plant Nuclear Safety Committec (PNSC) of TSI regarding minimum offsite to onsite electrical circuits and primary containment isolation valves were inadequate.
(Sections 3.5.5 and 3.4.1.2) 6.
The BIP specified that QA would perform a 100 percent review of TS surveillance requirements every 3 years.
This item, imposed by NRC order, was not being properly implemented.
For example, initially the TS surveillance requirements had been 100 percent reviewed, but procedures were later revised to use a batch methodology which was not consistent with Item III-3 of the BIP.
(Section 3.5.4) 2.1.6 Engineering Design and Technical Support 1.
Numerous design and operational weaknesses were identified with the SW system that collectively challenged its operational readiness.
Examples included: a vulnerability to single failure, lack of nuclear to conventional SW header leakage testing, unavailable preoperations/startup test data, improperly performed modifications, and the high potential for water hammer of the residual heat removal SW loop keep fill system.
The licensee also failed to recognize existing nuclear.SW system flow distribution and capa:ity inadequacies during the performance of SW studies and modifications.
The licensee subsequently wrote a
" justification for continued operation" (JCO) which included numerous short and long-term corrective actions. (Sections 3.6.3.1 and 3.6.3.2) 2.
In some instances, the licensee appeared to lack an understanding of the design basis of the SW system, and the necessity for traceability of design input to design output.
This was caused, in part, by a general lack of hydraulic design calculations for the SW system.
(Sections 3.6.3.3 and i
3.6.5.2) i 3.
In many instances, des.gn basis information was not readily available, was j
in the process of being reverified, or could not be located. This situation, in combination with the SW system deficiencies, just discussed, end similar deficiencies in the HPCI system found during CP&L's 1987 -
self-assessment, raises questions about the reliability and operability of i
l safety and nonsafety equipment under credible off-normal conditions.
)
i (Sections 3.6.3, 3.6.5.1 and 3.6.5.4)
I 13
E o
l-r 4.
Plant modifications contained an excessive number of field revisions, marginal installation instructions, and failed to address known discrepancies between design requirements and as-built conditions, indicating a iack of attention to detail or competence by the original g
design engineers and the design checkers / verifiers.
(Sections 3.6.6,
)
3.6.6.1, ar.d 3.6.6.2) 1 5.
Weak engineering safety evaluations (10 CFR 50.59) were noted during review of modifications.
The licensee had also made similar conclusions regarding safety evaluations as evidenced by nonconformance reports (NCR) l 88-055 and 88-056.
Licensee corrective actions associated with the NCRs l'
1 failed to address the concern or effect of poor, past evaluations, and the I
l' existence of potential unreviewed safety questions.
(Section 3.6.5.3) 6.
A large backlog of scheduled, but unbudgeted work existed in the form of i
Engineering Work Requests (EWR) and Project Identifications (PID).
Approximately 50 percent of the open (dispositioned) EWRs were due to j
material problems and obsolete parts, yet there was no program at Brunswick to resolve the obsolete parts issue with the exception of direct replacement of small obsolete valves.
Also, the engineering support to complete effective corrective action of EWRs and PIDs was both untimely and inadequate in numerous instances.
(Section 3.6.1.2.2) 7.
The licensee had not been aggressive in identifying or closing out vendor recommendations.
Many General Electric (GE) vendor recommendations were over 10 years old and were only recently being dispositioned.
Scheduling and implementation of corrective actions (once dispositioned) were also i
generally delayed to the future.
Procedures to control vendor recommendations were inadequate and had not been revised to reflect current work practices.
(Sections 3.6.9, 3.6.9.1, and 3.6.9.2) 8.
The design change program was in a state of change and not well supported by up to date site procedures.
Conflicts between the "new" corporate modification procedure and Brunswick procedures also existed.
(Section 3.6.4) l 9.
Inconsistencies existed between current and future (projected) modification closecut rates as documented in the Brunswick Five-Year 4
l Business Plan.
The Business Plan forecasted a significant drop in the I
number of modifications performed on a yearly basis.
If the actual number of completed (operable) modification packages drops to be consistent with the Business Plan, the current modification backlog would not be reduced in a timely manner, and might actually grow.
(Section 3.6.7) 10.
On an individual basis, plant modifications (and other projects) were properly prioritized initially using a computer program, although the actual scheduling of work appeared to be more dependent upon subsequent budget concerns rather than initial plant needs.
(Section 3.6.7.1) 11.
Engineering personnel perceived Brunswick as always one of the last BWRs in the industry to make needed upgrades in hardware or programs.
Examples include (1) closeout of Inspection and Enforcement (IE)Bulletin 79-14 which was not expected to be complete until 1992, and (2) permanent corrective actions to resolve the chronic intergranular stress corrosion 14
L,:
y cracking (IGSCC) issue have moved very slowly since the first discovery in 1976,.but were; expected to take place within the next two refueling outages.
(Section 3.6.7.2) 12.
Both.CP&L Corporate and Brunswick site engineering organizations had undergone changes in function, size, and responsibilities within the last 2 years to become more aligned as an uperating plant rather than a construction project.
The environment of continuing change has had a negative impact on the effectiveness of engineering support to the Brunswick site.
For example:
The transition to a CD0 was poorly planned and implemented with a.
regard to the Brunswick plant.
The process had been time consuming, was still being implemented and the licensee was expected to create additional organizational and programmatic changes as various-management studies and assessments were finalized.
(Section 3.6.2.2.1) b.
The performance of the Technical Support Unit has continued to suffer from instability and morale problems due to numerous reorganizations, indecision on the part of management to solve problems and set priorities, and phasing out the nuclear pay supplement.
(Section 3.6.1.1.2)
The responsibilities of the Modification Project Section of Outage c.
Management were not well defined.
(Section 3.6.1.1.3)
Despite potential drawbacks of this reorganization, once fully and adequately implemented, the resultant engineering product should be an improvement over the fragmented and weak engineering support previously provided to Brunswick.
I 13.
Communications within the engineering groups were adversely affected by the continual changes in personnel and their assignments. The lack of communications in one instance caused an estimated delay of 14 to 32 days in completion of the Unit I reload outage No. 6.
(Section 3.6.1.2) 14.
Corporate or onsite engineering support to perform effective root cause analysis, define corrective actions, and resolve issues to prevent recurrence of significant events depended greatly upon event visibility and was generally reactive in nature.
(Sections 3.6.8, 3.6.8.1, 3.6.8.2,
- 3. 6. 8. 3, and 3. 6. 8. 4) 15.
Corporate Nuclear Engineering Department (NED) personnel were technically competent with an adequate amount of nuclear and professional experience, however, the educational background of the onsite NED was below the
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industry average and may have been a contributing cause of the poor l
quality of work produced by NED.
(Sections 3.6.1.1.1 and 3.6.2.1.1) 3
- 2. 2 Root Cause Analysis i
Based upon the team's assessment of management effectiveness and Brunswick's performance, the root causes of poor performance during the past few years *have been (1) inadequate corporate management, coincident with a period of site management weaknesses, (2) the failure to clearly define and communicate site 15 l
goals, priorities and exp:ctations, (3) cultural issues including (a) the failure of CP&L management to adequately review and understand Brunswick's i
level of performance, and (b) the lack of individual accountability and j
teamwork, (4) an ineffective root cause determination and corrective action 1
program, and (5) an ineffective engineering design and technical support program.
j The team noted that many of the current problems at Brunswick were previously addressed in the 1982 BIP.
Although short-term performance improvements vere seen after implementation of this program in 1983, there was a general failure on the part of CP&L corporate and site management to ensure that i
i irnprovements were sustained and broadened.
There was a lack of corporate oversight, leadership, and direction in the mid-1980's during a period of l
continued weaknesses in site management.
The result, in part, was a subsequent decline in overall performance and a gerieral inability on the part of CP&L to evaluate Brunswick's performance accurately.
Brunswick personnel had the perception that significant improvements had been made since 1982 and that overall performance was generally good.
Brunswick's declining performance was, in part, caused by the failure to clearly define and communicate safety goals, priorities, and expectations.
This was evidenced by the failure to achieve full and lasting implementation of the BIP and other improvement initiatives such as the MOV program.
Failure to fully implement improvement programs and initiatives resulted in multiple equipment problems and the development of a culture of living with these problems.
This was exacerbated by a large number of repetitive Equipment failures and a high number of outstanding plant work items.
The Corrective Action Program was inadequate to identify, trend, and determine the root causes for these problems.
This program was also inadequate to correct problems even in cases where the problems and their causes were identified (e.g., BIP) and the corrective actions seemed straightforward. As a result of personnel avoiding responsibility for these program failures, a lack of individual accountability and poor teamwork became the norm.
i The most serious functional area performance problem that has resulted is
~
ineffective engineering design and technical support.
This problem has, in turn, exacerbated some of the above weaknesses and was found to also be a root cause of performance weaknesses.
Engineering problems have their root in a poorly documented design basis beginning during initial design, construction, and testing.
Engineering responsibilities were fragmented and received
' inadequate management oversight.
The CD0 was an attempt to correct these problems. However, the CD0 was poorly planned and implemented and has not yet l
solved the problem of fragmentation and oversight.
l The CMOT, initiated by the licensee in July 1988, also identified several causes that are "ery similar to those above.
Licensee actions in response to i
the CMOT finding! were beginning to show evidence of correcting some of these Other actions, such as the OA and Cresap appraisal were still ongoing.
causes.
Thus, it was too early to judge if these actions would succeed in the long-term
{
correction of the above root causes.
]
I 16 l
3.0 DETAILED EVALUATION RESULTS 3.1 Management and Organization This section discusses the evaluation of the overall effectiveness of management activities involving Brunswick Steam Electric Plant (BSEP) and included both onsite and corporate management functions.
The evaluation focused upon issues which contributed to (strengths) or detracted from (weaknesses) plant safety performance. The evaluation included the following organizational culture; leadership, direction and control; problem areas:
solving, decisionmaking and prioritization; planning, scheduling and organizing; and human resources.
The evaluation included document reviews, j
interviews, and direct observation of managtment and staff activities.
i Documents reviewed included Carolina Power & Light Company (CP&L) reports, plans, newsletters, memos, charts, manuals, handbooks, audits, and policies.
Approximately 170 interviews were conducted from the Chairman / President to operator / technician level covering a cross section of personnel.
It is important to note that at the time the team was at Brunswick, many of the senior corporate and site managers had been in place less than 6 months.
See Figures 1.5-1 and 1.5-2.
3.1.1 Organization CP&L and the Brunswick site were in a period of organizational renewal and transition due in large part to (1) the completion of the company's third nuclear facility (tha Harris Nuclear Power Plant), (2) economic pressures which were forcing CP&L to become more cost-competitive, (3) retirement of senior managers, (4) management rotations, and (5) reaction to adverse findings of NRC and industry groups.
Substantial changes in senior corporate as well as Brunswick site management personnel had occurred within the past 6 months.
Recent evaluations and analyses of the organizational structure (Organizational Analysis of CP&L) and an independent Nuclear Management and Operational Effectiveness Appraisal (Cresap) for all CP&L nuclear activities are ongoing.
The results of these evaluations are expected to result in additional organizational and personnel changes.
While the self-assessments are valuable, a number of the current problems such as an ineffective corrective action program and ineffective quality program had been previously identified as early as 1982.
The team concluded that CP&L has spent an excessive amount of time studying potential organizational change issues and plant performance problems such that needed changes and fixes had been unduly delayed. The climate at Brunswick is one of continuing change due to the items stated above and is reflected by a new corporate and site managexent team, new programs, continuing assessments, and ongoing equipment problems.
The new site management team has implemented a number of activities intended to change the organizational culture and the methodology for managing day-to-day activities at Brunswick.
The evaluation findings, as discussed in this and subseque.t sections, reflect past performance, equipment and engineering issues and the current site management team's initial efforts to implement corrective actions.
Many of the programs or initiatives had been in place for less than 6 months at the time the diagnostic evaluation was performed and consequently j
could not be fully evaluated to determine their effectiveness.
)
The organizational structure of CP&L in relation to Brunswick is depicted in Figures 1.5-1 and 1.5-2.
The Manager, Brunswick Project at Brunswick reports j
i 17
)
to the Vice President, Nuclear Generation Group who was based at the corporate offices.
In addition to Brunswick, he was also directly responsible for CP&L's other two nuclear projects, Harris and Robinson. -The Vice President, Nuclear Generation Group, reports to an Executive Vice President and the latter to the Chairman / President.
A Manager, Nuclear Engineering, Vice President, Nuclear Services, and Vice President, Operations Training Technical Services report to the Vice President, Nuclear Generation Group and provide support for all three nuclear facilities.
At the site, four section managers report to the Brunswick Project Manager:
Manager, dite Planning and Control; General Manager, Brunswick Plant; Manager, Outages; and Manager, Special Projects.
There are 15 Directors and/or Managers (Unit Heads) reporting to.the 4 Section Heads.
Approximately 65 supervisors (second-line) report to Directors and/or Managers, and approximately 111 Foremen (first-line supervisors) reported to the supervisors.
This comprised a management staff of approximately 195 people.
The following additional positions were onsite, but reported to corporate headquarters:
Resident Engineer; Manager, Training; Director, Quality Assurance / Quality Control (QA/QC); Director, Onsite Nuclear Safety; Site Personnel Representative; Director, Visitor's Center; and Engineer, Onsite Licensing.
Full-time staff and employee positions numbered around 1000 and with an additional 794 contractor positions as of February 1989.
The projected tctal work force in the 1989-1993 Business Plan for 1989 was 1726 and 1510 for 1990.
Staffing level and qualifications overall were adequate with the exception of Nuclear Engineering Department personnel at Brunswick as discussed in Section 3.6.1.1 and 3.6.2.1.
One aspect of the current organizational structure which requires continued management attention is the transition to a central design organization (CDO).
The team concluded that the CD0 concept has been poorly planned and its delayed implementation is a weakness that was adversely effecting engineering design and technical support activities.
Some organizational movements had been made, and some personnel had been transferred between departments.
A transition agreement had been developed to guide the exchange of responsibilities between the site and the corporate office.
New scopes of responsibilities were being established in the Technical Support Group.
This organizational transition was not yet complete; the final scope of that transition, and the relative scopes and responsibilities of the new departments were not final.
Substantial discussion was held with corporate officers and managers at Brunswick and within the Nuclear Engineering Department (NED) regarding the e,
role of NED'in support of plant operations both during and after CD0 implemen-tation. The centralization of NED at the corpcrate office is moving toward full implementation. The NED senior management expressed the view that the extent of NED's proactive involvement in plant operation would depend largely upon the budget support that each plant was willing to provide.
The role of NED had not been clearly established, procedures had not been implemented which define the responsibilities of organizational units providing engineering support activities.
As discussed in Station 3.6 and as reflected by recent SALP ratings, engineering support was an area which demanded increased management attention.
There was, however, a high level of NED and site teamwork and coordination to address the team's preliminary findings concerning the SW system design and operational deficiencies (discussed in Section 3.6).
p 18 l
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3.1.2 Culture and Climate The team concluded that there was a lack of a sense of ownership throughout the organization (corporate and site) and a lack of a commitment to "do it right the first time." The team defined organizational culture as the unique blend of attitudes, values, beliefs, practices, and self-image that Brunswick employees had about their work environment.
An essential aspect of culture and climate which is a direct result of leadership, direction and control is safety culture.
As used in this report, safety culture includes the personal dedication and accountability of all individuals engaged in any activity which bears on the safety of. nuclear power plants.
Through interviews and analysis of documents, the team characterized the traditional Brunswick culture and cultural climate as follows:
consistency in promotion opportunities, competitive pay and generous benefits, permanent
. employment offered to employees, job satisfaction, low employee turnover and high employee loyalty, large numbers of contract employees, over dependence on contractors, focus on, solving technical over people-related problems, a tendency toward reactive versus proactive response, little or no job rotation, excessive overtime and symptoms of job burnout in selected (sometimes key positions), and little sense of. economy or cost consciousness.
In addition, personnel interviewed at corporate and site offices, expressed their perception of other traditional cultural characteristics included:
a kill-the-messenger mentality; treat the symptom not the cause; live with problems, temporary repairs and quick fixes; keep the plant online; Brunswick is unique; loyalty to work unit first, Brunswick second and CP&L last; and place the blame on the other guy or corporate personnel.
The team found that site safety goals, priorities, and expectations were not clearly defined or communicated.
The team analyzed the traditional culture at Brunswick in relation to the desired culture as expressed by the new management team in terms of mission, values, beliefs, etc.
The cultural characteristics desired by current management were described during interviews and included a greater emphasis on:
safety, cost consciousness, teamwork, cooperation, coordination, effective communication, improved leadership and supervision, increased individual responsibility, authority and accountability, tecoming more proactive and responsive in solving technical and people problems.
improved job satisfaction, loyalty and management trust, more centralization of activities based upon effectiveness, improved recognition and reward based upon performance, on developing human resources, planned job rotation and career planning, a more open problem solving culture, open door policy, and involvement of more people at all levels in the decisionmaking process, e.g.,
participation management. Another important cultural characteristic desired by the new management team was the attitude of putting CP&L first, Brunswick second, and individual work unit last.
This would also, according to management, mean applying more lessons learned from one site to others as well as drawing strengths from individual site programs and practices in formulating improved programs and practices at all sites.
The traditional culture was in conflict with the characteristics of the desired culture.
This transition in culture was having both positive and negative effects.
It is the negative effects which are the challenges facing CP&L and Brunswick management as they deal with increased employee anxiety, and 19
accompanying adverse effect on attitudes, morale, and motivation.
These issues required continued CP&L management attention with emphasis upon training for first and second level supervisors.
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The team analyzed employee morale at Brunswick and found it typical of a company going through major reorganization and transition, except for the Technical Support Group where it was lower. The team also concluded that an excessive period of time has been spent by management in studying the need for organizational change.- For example, an organizational analysis (OA) has been underway for approximately two yeer<, srd the results and conclusions of the analysis are not to be implemented or made known to employees until late (October) 1989. The apparent slowness in the decision on implementation of the conclusions of the analysis was, based upon interviews, the single most significant factor affecting employee morale, attitudes, and motivation.
The same, to a lesser extent, applies to an independent Nuclear Management and Operational Effectiveness Appraisal.
The results and conclusions of this appraisal, essentially complete with regard to Brunswick, are not to be made known to employees until late 1989.
Current Brunswick managers are sensitive to cultural problems, and they had studies initiated by an independent outside organization (Cresap) and had implemented some corrective action measures, such as communications and teamwork quality teams.
However, the team concluded that there was not an overall effective means to respond to people issues.
Even though the Quality
-Check Program had been implemented and a corporate site representative was available and utilized, the team found that the prevalent culture at Brunswick was still largely comprised of traditional cultural characteristics.
3.1.3 Leadership, Direction, and Control The team found that corporate v.ersight, leadership, and direction were previously inadequate to compensate for past site management weaknesses.
The failure to implement an effective corrective action program as discussed in the 1982 Brunswick Improvement Plan (BIP) is an example of an area of continuing significant weakness due to ir. adequate direction and control.
A number of recent changes have been made which will redefine the level of corporate involvement at Brunswick as well as the role of senior site managers.
The principal changes were the reassignment of a number of CP&L corporate and site managers and consolidation of nuclear activities under the Vice President, Nuclear Generation Group.
Recent senior management changes that included Executive Vice President, Power Supply; Vice President, Nuclear Generation Group (NGG); Vice President, Nuclear Support; Vice President, Nuclear Services; and Manager, Nucleer Engineering were intended to provide improved corporate leadership and direction to each nuclear site.
The newly appointed Executive Vice President, Power Supply and Vice President, NGG had been in their positions for less than two months at the time of the diagnostic evaluation.
During interviews the President indicated that he was aware of the cultural and management problems at Brunswick.
He had initiated the Total Quality (TQ)
Program and described his commitment to excellence and safety and to reshaping the organization.
The new Vice President, NGG expressed his opinion that -
individual site autonomy must be replaced by the concept of placing the NGG success ahead of other organizational units (sites, Nuclear Engineering 20
^
~
Department, etc.) and his vision of NGG as being in continual pursuit of excellence.
He stated his view that CP&L and NGG, in particular, will be measured by the performance of the weakest unit and that it was essential that all work together, willingly, to strengthen the weakest performer.
In the past, the corporate approach to managing site activities could generally be described as laissez-faire which was demonstrated by the virtual absence of effective corporate efforts to assess site performance.
The sites were, for the most part, autonomous. While recent organiza 'nnal changes were made to increase corporate pretence onsite and rovir" i..aased direction, corporate leadership and direction was in the past limiteo cn. Brunswick. The lack of corporate involvement was evidenced by Quality Assurance (QA) programmatic weaknesses (discussed in Section 3.5), the poorly controlled and implemented reorganization of the engineering design and technical support function, and failure to utilize knowledgeable corporate expertise in responding to Bulletin 79-14 for a third time (discussed in Section 3.6), and the failure to implement an effective corrective action and root cause determination program (discussed in Sections 3.3, 3.5 and 3.6).
However, there were several instances in which corporate support or programs have provided direction to the site in technical These include, for example, operator training programs (discussed in areas.
Section 3.2), and the automated maintenance scheduling system and maintenance technician training program (discussed in Section 3.3).
A recent activity which reflects increased corporate involvement was initiated in 1988.
This effc' was the establishment of a Corporate Management Oversight Team (CMOT) to evd ae the nature and extent of problems that were evident at Brunswick.
The CMOT effort was reactive in nature to continuing problems at Brunswick and in response to meetings with the NRC.
The CMOT completed its assessment in August 1988 and identified six problem areas and listed both short and long-term recommendations including several general recommendations.
The latest status report on actions recommended was that some items have been completed, some are in process, and some are behind schedule.
The Cresap study of Brunswick and CP&L in general, is another example of recent management oversight and involvement.
This study was initiated by CP&L upper management to evaluate the effectiveness of its internal management processes and systems.
The results of the study are to be used as a basis for improving those systems and processes.
A third example is the response to SW system questions identified by the team and discussed in Section 3.6.
A number of Brunswick personnel noted that CP&L corporate officers visited the i
site on a regular basis.
There was evidence of personal contact with site personnel at lower organizational levels.
The new Vice President, NGG described his intention to visit the site 2 or 3 days a month; the new I
Executive Vice President indicated similar intentions.
While these recent examples are indicative o.f increased corporate oversight at Brunswick, administrative controls, procedures, and daily activities do not yet reflect a strong site-corporate relationship.
This relationship is in the process of being defined.
Effective formal reporting and assessment of the status of site actions and activities to upper management was limited.
Work item tracking systems and problems resolution tracking and trending systems were maintained at the department or unit level at Brunswick, i.e., Technical Support, Maintenance, and Outage Management and are discussed in Section 5.5.
Status information was 21
-also contained in the monthly Brunsvick Project management meeting handouts.
The team did not see similar evidence of such formal reporting to higher corporate levels, such as at the Senior Management Meeting.
It was also apparent that a single, centralized action tracking, commitment tracking, and problems resolution tracking system was not in use.
The team found the recently appointed senior site management to be substantially involved in day-to-day activities.
The new Brunswick Project l
Manager, senior ranking manager on site, expressed his vision that Brunswick become one of the best operating BWRs in the country.
Having headed the CMOT during the period July-August 1988 prior to appointment to his present position in November 1988, he had an indepth knowledge of the numerous problems (both human relations and equipment) at Brunswick and has initiated actions to foster a sense of teamwork, communications, and individual accountability at Brunswick. One example was the initiation of a Communications TQ Team to improve horizontal and vertical communications throughout the Brunswick organization.
The new Plant General Manager, appointed in August 1988, has initiated similar actions such as working lunches to improve teamwork, communications, and individual accountability at all organizational levels.
The team concluded
-that one of the most significant actions initiated by the new Brunswick management team had been to increase the amount of time managers spend in the plant. This was demonstrated by the Plant General Manager's daily plant tour
.(approximately 5:00 a.m.-7:00 a.m.) and his actions to ensure that unit level managers are actively involved in daily activities in the plant.
This level of management involvement was not the case in the past. These actions and personal involvement of site managers had resulted in evidence of near-term success in communications as seen by the team during interviews and discussions with a large cross section of individuals throughout the plant organization.
Management's expectations in terms of teamwork, compliance to procedures, do it right the first time, and personal accountability were articulated by many of the plant staff members interviewed.
There were indications that communication and teamwork had improved.
The new managers were serving as role models, leading by example, and providing needed focus.
The team concluded that site goals, priorities, and expectations were not clearly defined and communicated to all organizational levels.
CP&L corporate and Brunswick senior management had provided statements on company missions, values, visions, and beliefs.
These statements are used in establishing goals and objectives and in planning in some instances.
Brunswick had mission statements for each of its sections and goals and objectives down to the manager / director (unit head) level.
However, discussions with individuals at the supervisor / foreman level and below revealed many instances where individuals had only a general awareness of goals and objectives of their work group. Although there was evidence of the development of group or team goals in some instances, several individuals expressed concern that either goals and objectives had not been developed for their work group or where they existed they were not adequately linked to the performance review process.
An essential aspect of direction and control of activities is the development and implementation of administrative controls including methods to assess ongoing activities to determine whether or not the desired results are being achieved. As discussed in Sections 3.2, 3.3, 3.5, and 3.6, various weaknesses in the administrative control system were identified by the team.
An example 22 I
is the corrective action program.
Although this was a problem area identified in 1982, and specifically addressed in the BIP, currently the corrective action program is not effective.
Marginal execution was a cause of many problems at Brunswick.
Greater focus was needed on analyzing performance discrepancies in the execution of corrective action to determine their cause.
This is particularly f rue at Brunswick since major changes in the organization have and will continue to occur and managers are trying to change the culture of the site.
3.1.4 Problem Solving, Decisionmaking, and Prioritization The teata analyzed. work at Brunswick to determine the extent that management actions were reactive or proactive/ preventive in solving problems. The team found, that in the past, problem solving, decisionmaking and prioritization activites were largely reactive and driven by regulatory or industry pressures or the system or equipment needed attention for continued availability.
As discussed in Sections 3.2, 3.3, 3.5, and 3.6, an attitude of living with problems was evident by the large number of temporary repairs and outstanding work items.
A significant weakness in this area is the failure to identify the cause of equipment problems or failures and to implement adequate corrective action. The longstanding problems of SW system pump motor overheating is an example (Section 3.3).
The team concluded that Brunswick was largely a reactive organization, and that it would remain that way until more of its people, management, organizational transition, and equipment problems were corrected.
Interviewees confirmed that Brunswick was overly reactive and driven extensively by outside agencies.
Those interviewed, indicated the following constraints to becoming more proactive and responsive (1) heavy administrative burden or workload, (2) failure to see the significance or magnitude of technical or personnel concerns, past them up the chain of command, indecisiveness, and failure to act until a crisis, (3) failure to prioritize problems or untimely responses, (4) excessive time to get parts, (5.' failure to plan for day to day events, (6) failure to do the job right the first time, and (7) poor or marginal execution including monitoring, involvement and control, including feedback to employees about the work.
The team concluded that the Corrective Action Program and its implementation are inadequate.
In terms of problem solving, Brunswick has a history of serious weakness in searching out and understanding the root cause of problems, be they people or equipment related.
As discussed in Section 3.5, the team reviewed recently issued policy and procedural guidance, and training given to members of the Brunswick staff in the areas of corrective action and root cause analysis.
The team concluded that there is no focal point of root cause expertise within the Brunswick organization, that the threshold criteria for formal root cause (by procedural guidance) is too high, and that training given, to date, concerning the various methods of root cause determination was rudimentary. There has been a lack of corporate office sensitivity and commitment to effective root cause and corrective action programs and processes based on the longstanding corrective action program deficiencies at Brunswick.
There is no focal point within the corporate office, to assure oversight and direction and assess the effectiveness of corrective action programs and processes, particularly root cause determination, throughout the Nuclear j
Generation Group.
Brunswick has not implemented a Human Performance Evaluation System (HPES) which could improve the analysis and evaluation of human 23
)
performance problems at a low, "near-miss", threshold.
The success of an HPES program is in large measure dependent upon the selection of a highly qualified and motivated individual for the position of HPES Coordinator.
There has been an historical lack of continuity in this position at Brunswick, and, in fact, the position has remained unfilled for the past year despite attempts by site management to find a suitable candidate.
There has been a lack of corporate oversight and direction in this matter.
The team did note individual examples of effective corrective action / root cause determinations at Brunsw ;k.
Typically, these examples were instances "here 1 3
special task force or teem was formulated to address specific technical or organizational performance problems.
Examples included an assessment of technical and programmatic problems at Brunswick by the CMOT conoucted in July-August 1988 and an equally impressive effort by a Brunswick Motor-0perated Valve (MOV) Task Group, during the period August-December,1988, to address repetitive, multi year duration problems with the performance and reliability of both alternating current (AC) and direct current (DC) motor operated valves.
In each instance, multi-discipline teams were utilized in the conduct of a comprehensive and thorough analysis, actions plans (short and long range) were developed, and progress in the implementation of the plans is being tracked to completion.
However, as discussed in Section 3.3.5 numerous weaknesses in implementation of MOV preventative maintenance were identified.
Also, the formulation of the task efforts of both the CMOT and MOV Task Group were in reaction to external (NRC and Institute of Nuclear Power Operations) prompting more so than by self-initiation from within CP&L/ Brunswick.
3.1.4.1 Prioritization The team concluded that the different site organizational unit prioritization systems were ineffective.
Another aspect of management control and direction reviewed by the team was work prioritization.
Prioritization of plant activities is described in Administrative Instruction (AI) 80 dated January 6, 1986.
This Al describes five priority classification and provides examples for each classification.
It also notes that the priority classification of actions may be increased or decreased based upon a risk assessment of the item.
Each of the Brunswick organizational units (Operations, Maintenance, Technical Support, etc.) had developed its own system to prioritize work tasks and needs within their organizational unit.
However, there was a lack of uniformity among the individual prioritization systems.
This lack of compatibility made j
it difficult to translate the different priority needs (equipment problems, inoperable control room instrumentation, plant labeling, etc.) into a t
comparable priority within Maintenance and/or Technical Support.
An example is that only 50% of the items identified or the " Ten Most Wanted List" have been corrected (Section 3.2.4.1).
As discussed in Section 3.3, the Site Work Force Control Group was established to coordinate maintenance activities and has resulted in a more uniform approach to completing actions and increased teamwork between units.
3.1.5 Planning, Scheduling and Organizing The team examined the process of planring, scheduling and organizing at I
Brunswick through an examination of business and work plans, discussions with managers and their staffs, and observation of the preparation and implementation of work plans.
a.
24
The CP&L top-tier document for the integration of business plans and resource allocation is the Five-Year Business Plan (Business Plan).
The Brunswick Business Plan, in its present form has evolved over the past three years -
culminating in a linking of the Business Plan and budgec (Capital and Operating and Maintenance (0&M)) in fiscal year 1988.
Recognizing that, as stated by CP&L Management, there are numerous improvements yet to be made in the process of Business Plan development, the team nevertheless found fundamental weaknesses (discussed below) in the process, as implemented in the past, and concluded that the process for business planning at Brunswick was ineffective.
These weaknesses tended to hamper effective communication within the site organization as well as between the site and corporate office on Business Plan / Budget related matters, and had resulted in what the team concluded to be a substantial lessening of a sense of ownership of the Business Plan at Brunswick.
The process, or at least the perception conveyed by management representatives interviewed, was that a proposed Business Plan and supporting budget is first developed by the site, staff and submitted for corporate office review and approval.
At various levels of review within the corporate office, reductions are made in the proposed budget.
These cuts, mandated by the corporate office, are conveyed to the site with instructions to effect the reduction in the budget without providing an explanation.
The net result, according to site management, is a mismatch between the. Business Plan and budget such that there has developed a perception by site personnel of a lack of sensitivity, and perhaps interest, on the part of corporate office management as to the impact of proposed budget reductions. Without a corresponding revision to specific elements of the proposed Business Plan, a mismatch between the plan and budget is left. This mismatch, in turn, seems to have left site management without a strong feeling of ownership of past Business Plans.
Corporate managers acknowledged that the perception of the Business Plan development process may be accurate.
Steps were being taken, according to both site and corporate management, to improve the plan development process and communication.
The team did not identify instances where necessary modifications had failed to receive adequate funding.
The team noted that projected budget and personnel reductions for the next several years are inconsistent with CP&L's statements in the Business Plan that the existing backlog of work items would be reduced (see Section 3.6.1.2.2 for a discussion of engineering work requests and outstanding work items).
The +aam also examined the decision making process whereby the Brunswick staff has, to date, elected to repair indications of intergranular stress corrosion cracking in the piping systems. This item is discussed in Section 3.6.7.2.
At the team's request the Radiation Protection staff prepared an analysis of the impact on total occupational exposure at the plant associated with examination and repairs of the piping in recent years.
The results of this analysis revealed an annual Man-Rem exposure per unit of approximately 400, 200 and 300 for the years 1986-88, respectively, attributable to these activities.
This incremental occupational exposure was of sufficient magnitude that it ranked Brunswick well above the average occupational exposure of operating BWRs, whereas if this occupational exposure had been avoided Brunswick would have ranked below the average exposure of operating BWR's in each of the years 1986-1388.
25
The team found recent evidence of good work planning practices such as the Site Work Force Control Group (SWFCG).
A meeting of this group was observed by the team, and the details can be found in Section 3.2.
3.1.6 Human Resource Utilization and Development l
The changing financial climate, completion of the Harris facility and problems l
with Brunswick and Robinson resulted in CP&L initiatives to reevaluate its k
policies and improve the performance of its people.
Promotional opportunities
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have become more limited as a result of reorganizations and reduction in personnel.
CP&L is encouraging a " work smarter" philosophy and emphasizing the need for greater productivity and results from its work force.
Management succession plans had been developed down to the supervisory level at Brunswick.
However, little evidence of effective career planning and development existed, including job rotation.
Brunswick management did acknowledge the need to improve planning and programs in this area.
A principal program aimed at improving the quality of people and their performance throughout the CP&L organization is the TQ Program.
This program was initiated in 1986, and has the strong support of the Chairman / President and other top executives of the company.
The program was describec by senior management as a long-range strategic process to improve company performance in every area, and is linked to company mission and senior management beliefs toward overall company and people performance.
Managers expressed their desire that all employees participate in the program.
The program has had wide visibility by way of recognition in articles in the company newsletter and Brunswick memo / flyers.
Examples of the application of TQ concepts include the Communication Team at Brunswick, wherein employees representing a wide spectrum of the plant organization (from all levels) are working to improve communications and the understanding of employee / management needs, expectations, etc.
This TQ team recently made recommendations regarding revision and clarification of Brunswick Goals.
Recommendations included the development of goals, with input from all levels of employees, that would promote teamwork, be challenging, be reasonaule and measurable, and be supportive of other group and site goals.
This process would translate general goals and policies into meaningful working goals.
The team found the TQ program initiatives at Brunswick to be effective mechanisms for assessing and improving resource utilization and performance.
The CP&L OA is also intended to improve financial performance.
This analysis includes input and participation from all parts of the company and the analysis was being done by CP&L personnel.
Consultant assistance is limited to providing the design of a structured process, provide data processing capability, train CP&L staff in the process, and facilitate an outside view of
)
issues.
i Although the team found that management was aware of the need to improve its responsiveness to human relations issues discussed earlier, and noted signs of improvement, many individuals indicated that they either had difficulty in getting their superiors to listen or that their superiors did not act in a timely manner to solve or mitigate problems which could lead to performance deficiencies.
These employees said that some supervisors were not sensitive to the significance of concerns identified and failed to realize the impact they 26 l
l L
could have on performance, e.g., human errors.
Additionally, interviews indicated that employees believed that management was reactive rather than proactive, too frequently waiting until a crisis arose before directing resources to solve the problem.
This ret Jited in a conflict between the stated goal of identifying problems and the actual practice of living with problems, as discussed in Section 3.2 The team concluded that the new senior management team possesses good human relations, technical and management skills ard is competent and capable to make the necessary changes to establish a safety culture at Brunswick and improve overall plant performance.
Based upon interviews with these managers and a wide cross section of employees at Brunswick, the team found that increased emphasis was being placed on human resource development, human relations, and people-related issues.
3.2 Operations In evaluating plant operations, the team observed control room and in plant activities of both licensed and nonlicensed operators, conducted tours of all areas of the facility, examined the interface between the operations unit and other organizations, assessed managerial involvement and effectiveness, examined operations improvement initiatives and conducted reviews of logs and records. The team interviewed both licensed and non-licensed operators as well as Operations Unit management.
The team also evaluated the effectiveness of the operator training program by interviewing training unit personnel, observing operator training classroom and simulator sessions, and reviewing initial and requalification training programs, training and simulator facilities, training staff qualifications, and management oversight and support for the program.
3.2.1 Operations Unit Organization 3.2.1.1 Management The Operations Unit was led by the Operations Unit Manager, who reported directly to the Plant General Manager.
The Operations Manager, a licensed Senior Reactor Operator (SRO) with 22 years of nuclear experience, had been the j
Operations Mananger for approximately ten months.
Reporting directly to the Operations Manager were six shift crews, a Staff Principal Engineer who was responsible for the personnel in the Shift Technical Advisor and Real Time Training groups, two Unit Operations Engineers and the Radwaste/ Fire Protection Supervisor.
3.2.1.2 Shift Staffing Operations staffed six shift crews which operated according to a 12-hour shift rotation.
Each shift crew consisted of a Shift Operating Supervisor (505), a licensed SRO, responsible for both units' Shift Foremen, who were also licensed SR0s.
Each Shift Foreman was responsible for a Senior Control Room Operator, a licensed SRO, and two Control Room Operators, licensed Reactor Operators (R0s).
In addition, each shift crew had approximately 5 auxiliary operators.
Shift rotation was performed such that a relief crew was available on weekdays.
Interviews with many operators indicated that the 12-hour shifts were preferred as opposed to 8-hour shifts because they allowed for more days off.
27
l l
l 3.2.2 Conduct of Operations i
The control room staff conducted themselves in a professional manner and wore uniforms and nametags which clearly identified their organizational positions.
Control room access and noise level were well controlled by the Shift Foremen.
Control Room Operators also deterred unnecessary personnel from approaching the main control boards during evolutions. The strengths and weaknesses of the staff in the conduct of operations are discussed as follows.
3.2.2.1 Shift Leadership The 505s and Shift Foremen exercised strong leadership and control of the shift crews during operational activities.
The Shift Foremen provided guidance to the Control Room Operators during several planned and unplanned evolutions.
An example was an unplanned transient involving a reactor feedwater pump (RFP) trip.
During the transient, the Control Room Operators had problems restarting the RFP and actally tripped the pump a second time.
The Shift Foreman then took control and directed the specific actions of the Control Room Operators which restored the unit to a stable condition.
Although the SOS office was situated outside the control room, the office was positioned such that the SOS could observe all control room activit'.es through a window.
All SOSs observed were present in the control room durbg planned evolutions.
The SOS on shift during the unplanned transient responded quickly and was in the control room for the majority of the event.
3.2.2.2 Shift Relief and Turnover Shift relief and turnover were performed in a thorough and disciplined manner.
Counterpart relief included thorough briefings, joint log reviews and panel walkdowns.
The 50Ss held crew briefings in which prior incidents and upcoming activities were discussed.
Although relief sheets were completed, the team observed that information entered on the relief sheets was often brief or j
r nonexistent for problems experienced during the previous shift.
Instructions governing use of the relief sheets lacked well defined performance standards j
relating to subject and detail.
3.2.2.3 Logs and Records Control room log entries were rudimentary or nonexistent for many significant occurrences.
Log entries for some events did not provide sufficient information to reconstruct what occurred during the event.
Inadequate log-keeping resulted in the loss of key information, impacted managers' ability to assess the conduct of operations and the ability to conduct root cause analysis.
Examples of poor log-keeping included:
1.
On April 11, 1989, while reducing power on Unit 1 to "the point of adding heat", a sudden drop in reactor pressure caused the only operating RFP to trip.
See Section 3.2.2.7 for details concerning this transient.
i, l
Although the operators successfully recovered from the event, the control room logs and relief sheets did not state the cause of the RFP trip, did l
not include that the pump was restarted and tripped a second time or that the reactor water cleanup (RWCU) system was mistakenly isolated during the event.
28
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2.
While placing the steam jet air ejectors (SJAE) into service during the Unit 1 startup on April 15, 1989, both the normal and alternate SJAE pressure controllers were found to be set at 115 psig resulting in fluctuations in the aftercondenser shell drain levels.
The operators reset the controllers to 110 and 105 psig, respectfully, to stop the fluctuations.
No log entry was made to indicate that the problem occurred and no additional corrective actions were initiated.
However, in response to the team's inquiries, the licensee determined that the applicable procedures provided insufficient guidance for setting these controllers.
3.2.2.4 Communications Poor communications between various levels of management and the staff at Brunswick had been previously identified by the NRC and the licensee.
Current communications practices within the individual shift crews were adequate.
Operators in the Control Room typically informed each other of activities that could affect the plant, annunciators were properly acknowledged and shift supervision interacted effectively with the operators.
Repeat-backs of instructions were sporadic, however, and operators performing activities in the plant did not always keep the control room operators informed.
For example, during the performance of a service water system test with the plant at power, the control room operator was not kept informed of the test progress and had to follow the test progress through equipment and alarm indication in the control room.
Communication within the Operations Unit was improving.
A number of operators indicated that in the past, reporting problems or deficiencies often resulted in punitive actions against the identifier.
This caused guarded communications and a lack of trust of management among the operators.
Current management recognized this problem and had implemented a number of initiatives to improve communications.
These actions included periodic safety meetings between the 50Ss and their respective crews and periodic meetings between the Operations Manager and the 50Ss.
The Operations Manager had also recer.tly issued a written policy statement delineating his position on self-identification of problems.
This policy statement included examples of problems and mistakes which would not lead to disciplinary action if brought to managment's attention by the individual responsible.
Despite recent actions taken to improve communications between operations management and the shift crews, some difficulty in promoting current management philosophy was evident.
For example, a number of operators were questioned on the Operations Unit goals and objectives for 1989.
Other than stating that Brunswick was striving to be the number one plant in the country, the operators could not relate any specific unit goals, such as a numerical limit for disabled annunciators or personnel errors (see Section 3.2.5 for additional information on management initiatives).
Although it was apparent that management was F+ressing a much needed reduction in the number of trouble tags involving control room equipment, discussions with operators indicated that they did not possess the same expectations and were, in fact, complacent towards further improvements (see Sections 3.2.4.1 and 3.2.4.3).
The control room operators apprecined the recent addition of a second reactor operator on both units, however, they resented the required periodic logging of control i
room indications (see Section 3.2.2.5).
Although these initiatives appeared promising, they had not been in place long enough for the team to judge their effectiveness.
29 i
v
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Communications between the Operations Unit and other site units were improving.
.A daily morning meeting was conducted among the various site units to discuss and provide details of planned activities.
During the diagnostic evaluation, significant activity was focused on trouble-shooting problems with the Unit 1 electro-hydraulic control (EHC) system circuitry.
For this activity, interaction between Operations,. Technical Support and Maintenance was thorough and appropriate.
However, methods for the operators to expedite completion of specific work requests by interfacing with the maintenance planners were not being effectively utilized (see Sections 3.3.2.2)
- 3. 2. 4. 5 attention to Detail Inattention to detail among the operations staff had been previously identified by the NRC (SALP Report 50-324/88-32 and 50-325/88-32) and CRESAP.
The team observed a reactor startup, several surveillance, including service water system testing, and other evolutions. During these evolutions, the operators followed. procedures, anticipated changes in equipment / plant status and L
communicated well within the shift.
However, a few instances of lack of attention to detail were observed.
Examples of inattention to detail included the following:
- 1.
On April 3,1989, with the main stack radiation monitor inoperable, limiting conditions of operation (LCOs) were in effect under Technical Specification (TS) 3.3.5.9, radiation effluent monitoring instrumentation.
However, TS 3.3.5.3, accident monitoring instrumentation was also applicable to this equipment but was not recognized by the operators.
Chemistry personnel identified this and alerted the operators to the applicability of TS 3.3.5.3 on April 10, such that no action statements were violated.
Cases of operators not consistently recognizing all applicable LCOs had previously been documented in licensee event report (LER)88-027, on November 15, 1988 and LER 89-006, on March 9, 1989.
In both cases, tiie operators recognized the nonapplicability of TS 3.6.5, Seconda y Containment Integrity, but failed to implement an hourly fire watch as required by TS 3.7.8, Fire Barrier Penetrations, and thus, failed to satisfy the TS action statements.
2.
On April 11, 1989, an auxiliary operator (AO) identified a labeling discrepancy associated with a breaker cover panel on Motor Control Center t
(MCC) 1XD.
The panel contained multiple labels of " Spare", "ASSD" (Alternate Safe Shutdown), and "RCIC (Reactor Core Isolation Cooling)
Steam Supply Line Isolation Valve 1-E51-F007 ASSD Fd" which was attached with tape.
The A0 returned to the control room and discussed the labeling discrepancy with the shift foreman (SF) and inquired how the item should be reported. The SOS present during the discussion instructed the A0 to glue the taped label on the panel.
In addition, the SF instructed the A0 to first check the electrical drawing (LL92039) and operating procedure (OP-16).
The A0 performed the review as directed.
However, during the review the A0 failed to note a plant modification (P/M) Number 89-023 which was referenced on the drawing microfiche card and mistakenly believed the taped on label was the correct labeling for the panel.
The team discussed the incident with the operation's manager.
Subsequent-licensee (system engineering) review determined that the correct labeling was " Spare", and that the additional labels had not been properly disposed t.
30
.o of following the plant modification.
The team considered that the A0 was
{
-attentive to the labeling deficiency and took appropriate action notwithstanding the oversight made during the drawing review. Operations supervision showed a lack of attention to detail in the dispositioning of the incident and a lack of interest toward cause identification and correction relating to the mislabeling.
In response to events involving inattention to detail identified by the NRC during the previous SALP assessment period, the licensee has initiated a s
program which placcd a second control room operator in each unit.
The operator's funccion wLs.to monitor control room indications to ensure attentiveness to plant status and early recognition of equipment problems.
Required periodic logging of specific control room indications was also instituted for the same purpose.
Although the program had the potential to increase operator awareness of plant status, the program was too recently implemented for the team to judge its overall effectiveness.
3.2.2.6 Level of Knowledge i
The operations staff demonstrated an adequate level of knowledge of plant systems and integrated plant operations during the evaluation.
The operstors were generally cognizant of equipment and conditions which affected plant The operators level of experience at Brunswick was particularly high; status.
several 50Ss had been at the site in excess of 18 years and most of the control room operators had at least 6 years experience at Brunswick.
Discussions with the operators concerning the service water system indicated a thorough systems knowledge.
The level of knowledge and skill demonstrated by the auxiliary operators observed during the performance of their rounds was excellent.
The operators were observed checking rotating machinery for heat, vibration and lubrication levels, scanning valves and piping for leaks and checking indicating lights on alarm annunciators and switchgear.
In conversations, the auxiliary operators exhibited a higher level of plant knowledge than expected for their position.
One instance was noted in which control room operators exhibited a 1cck of understanding or integrated plant response.
On April 11, 1989, while reducing Unit 1 power to below "the point of adding heat", a sharp drop in reactor pressure caused the only operating RFP to trip.
The control room operators had not anticipated that the new core had almost no decay heat and that the ensuing loss of steam pressure would cause reactor water level to swell high, resulting in the RFP trip on high level.
Without understanding what occurred, the operators isolated the RWCU system and restarted the RFP, which caused a second pump trip on high level.
Shift supervision then took control of the operators actions following the second pump trip and restored the plant to stable operation.
3.2.2.7 Morale i
The morale of the operating staff was fair.
The more senior operators (the 505s, shift foremen and senior control room operators) interviewed did not specify any issues which caused a negative impact on morale.
They indicated that the improved cleanliness M the plant and the improved work environm'eht in the control room (carpeting ano furniture) had resulted in a positive impact on morale.
Some of the more junior operators (the control room operators and 31
ev-v-
-r,---
auxiliary operators) interviewed indicated that career path and compensation concerns negatively impacted morale.
One control. room operator indicated that if he had stayed in a nonlicensed technical area he would be making more mor.ey than he is as a licensed operator. Another control room operator indicated that Instrument and Controls (I&C) technicians received better pay than control room operators.
Many of the junior operators interviewed expressed deep concern over a perceived lack of promotion potential.
These operators indicated that fewer auxiliary operators are being selected to participate in licensing classes than in the past.
This also pertained to licensed R0s that were anxious to receive SRO t'. v'ng and licensing.
These operators had the perception that management was:
' dng back training to cut costs.
3.2.3 Procedures The. team reviewed plant procedures associated with various ongoing activities, such as; plant startup and shutdown evolutions, special tests relating to reactor core isolation cooling (RCIC) injection, emergency diesel generator loading, and surveillance activities.
The team also observed the operating crew's performance of those tasks to assess procedure adequacy and procedure adherence.
These procedures were generally adequate for accomplishing the tasks although some were cumbersome.
The procedures were adhered to with the exception of minor deviations.
However, several operators did not exhabit an attitude of strict procedure adherence.
1 a
An example observed in which operators did not adhere to a procedure was when the operators used caution tags to relay information on handling specific equipment problems.
On each unit, five caution tags associated with the same
)
i caution number existed that provided information to the operators for l
determining high pressure coolant injection (HPCI) operability based on valve position.
This was inconsistent with procedure AI-58, " Equipment Clearence
{
Procedure" which stated that " Caution tags / labels shall not be used to record 1
procedural information."
In February 1989 the CP&L Brunswick Project Manager issued a memorandum directing that established procedures be followed by site personnel.
The memorandum was in response to a violation resulting from the failure to follow procedure (NRC Inspection Report 88-40).
The team determired that operators l
were aware of the directive relating to procedure adherence and were generally supportive of that policy.
however, several operators expressed that the degree of adherence varied somewhat based on individual philosophy of shift supervision.
Some operators felt that procedures as written were too
" restrictive", resulting in an unnecessary burden to the operators.
An example given was the need to process a temporary change to permit loading an emergency diesel generator to a load of 3500 Kilowatts (KW) even though that loading was well within the component's design but exceeded the load range of 2700 to 3100 KW specified in the procedure.
Another example was the need to markup (delete) procedure steps, in system operating or test procedures, to permit performance of a simple task or single step such as stroking a valve following valve maintenance.
Several operators expressed their belief that strict adherence would result in nonthinking operator performance.
The attitude reflected by these statements is indicative of a failure of operations staff to understand i
the importance of procedures and their implementation which is an essential ingredient of a safety culture.
T 32
Procedures could be improved to reduce the existing administrative burden to operators.
Operatiens' management is aware that some procedures are cumbersome L
and require modification.
The Operations Quality Team (Q-Team) recommendations for procedure improvement had not been submitted for action (see Section 3.2.5.2).
Although management's recent directive on procedure adherence was communicated throughout all shift crews, there was still questions among the operators concerning strict adherence to procedures and the implementation of this concept.
3.2.3.1 Standing Instructions The Standing Instructions were not being used effectively to provide instruction to the operating staff and were an unnecessary burden to the j
operators.
An excessive number of miscellaneous instructions to the operators were in effect that were neither indexed nor administratively controlled.
At the time of the evaluation, 33 standing instructions had been issued for 1989 and there were current standing instructions dating back to January 30, 1987.
Because there wts no index, operators had to thumb through the Standing Instructions in order to find a specific instruction.
During a discussion concerning the RFP trip and reset circuit logic, one operator searched through the Standing Instructions without successfully finding the applicable instruction.
The administrative controls for Standing Instructions were not effective as evidenced by two currently active instructions which had already been incorporated into procedures.
These instructions should nave been deleted from the Standing Instructions.
The RFP trip and reset circuitry is discussed in more detail in Section 3.2.4.3.
3.2.3.2 Emergency Operating Procedures (EOPs)
Tha E0Ps were not consistent with the BWR Owners Group Emergency Procedure Guidelines (EPGs).
This finding had been previously identified during an NRC E0P inspection and is documented in Inspection Report !'-325/88-200 and 50-324/88-200.
The Brunswick E0Ps prioritized operator sctions according to a predetermined significance (i.e., reactor power control iad higher priority than water level control) rather than taking actions to simultaneously control reactor power, pressure and level as is specified in the BWR Owner's Group EPGs.
The licensee's format could potentially delay operator response and implementation of accident mitigation actions.
In addition, the licensee's E0Ps incorporated event specific response strategies such as post-scram recovery and station blackout actions which also had the potential to delay the operators' response and implementation of accident mitigation actions.
During execution of the E0Ps in simulator scenerios, these event specific strategies caused the operators to delay implementation of accident mitigation actions.
For example, the post-scram actions in the E0Ps resulted in a delay 'in maintaining normal range reactor water level.
This allowed the RFPs to refill the reactor pressure level resulting in high reactor water level and a trip of the RFPs.
This, in turn, unnecessarily burdened the operators with additional actions to reset and restart the RFPs.
Despite these procedural problems, the shift crew observed properly implemented the procedures.
The team also verified that the E0Ps we>9 being updated to reflect plant modifications.
3.2.4 Material Condition of the Plant The team concluded that there was an excessive number of plant deficiencies.
The majority of deficiencies were associated with balance of plant (BOP)
}
33
t systems (annunciators instruments and valves).
These deficiencies had been identified by the licensee and entered on work orders.
However, some deficiencies associated with both primary and BOP systems had existed since 1986/1987 and collectively presented an unnecessary operational burden to the operators.
The following sections discuss deficiencies involving control room instrumentation, plant equipment, the " Ten Most Troublesome WR/J0s Lists," and I
the impact of these deficiencies on the operations staff.
A discussion of various equipment deficiencies is also presented in Section 3.3, " Maintenance" I
and Section 3.6, " Engineering Support".
3.2.4.1 Control Room and Associated Instrumentation The team found that there were an excessive number of control room instrume i
and indications which required maintenance or engineering attention.
Instrumentation deficiencies adversly affected tne operators ability to monitor and control plant conditions and burdened the operators with additional, otherwise unnecessary, actions.
To reduce the clutter caused by excessive trouble tags in the control room, the licensee had recently initiated a program to place the trouble tags on the applicable plant equipment rather than on the affected control room indication.
For example, 21 control room annunciator problems on Unit 1 (13 disabled annunciators and 8 lighted annunciators), and 26 control room annunciator problems on Unit 2 (22 disabled annunciators and 4 lighted annunciators) were not identified with control room trouble tags.
This resulted in no indication on the main control boards to acknowledge the abnormal status of the lighted annunciators (disabled annunciators were identified in the control room with colored dots), and further burdened the operatort as discussed previously.
For example, the Unit 2 main control board annunciator "SPTMS DIV II WATER RTO OUT OF LIMITS" was continually lit due to a problem with the sensor.
There was nothing on the control boards to indicate the cause for the abnormal status of this annunciator, although a trouble ticket had been placed on the Suppression Pool Temperature Monitoring System (SPTMS) Division II Microprocessor Cabinet in the plant.
Discussions with several operators indicated that they knew the cause behind most of the lighted annunciators.
When an operator couldn't recall the reason for a lighted annunciator, he offered to contact an A0 to check the trouble ticket on the plant equipment responsible for the indication.
The operator's response was indicative of the difficulty in remaining knowledgeable of the excessive number of adverse plant conditions.
To increase the operators' sensitivity to undesirable plant conditions, the plant general manager initiated the " Ten Most Troublesome WR/J0s List," also known as the " Ten Nost Want?d List," in October 1988.
The control room operators provided a list each week of the ten main control board items for each unit which impacted their ability to monitor or control the plant.
An item was removed from the list when either the work was complete, scheduled for i
j an outage, or required an engineering work reouest (EWR) for resolution.
A review of the weekly lists from October 1988 through April 1989 indicated that l
less than 50 percent of the items identified by the operators had been fixed.
i The majority of the deferred items were scheduled for an outage, awaiting parts or required an EWR.
However, items that required an EWR for resolution lost the operators' prioritization and was reprioritized by the Technical Support unit.
Before March 1989, items that had been removed from the top ten list, but had not yet been fixed, were no longer tracked.
The team concluded that the " Ten Most Troublesome WR/J0s List" had the potential to correct the l
34 l
g 4
operators' willingness to work around or live with equipment problems and to convey management's support for a better working environment.
However, the program thus far had limited effectiveness in resolving control room equipment problems.
Operations management indicated that the " Ten Most Troublesome WR/J0s List" was also initiated to increase teamwork between Operations, Maintenance and Technical Support personnel as well as to provide the operators with a means to identify and obtain priority response to correct the most troublesome control room deficiencies.
However, discussions with a number of ope ators indicated that the goals and objectives of this initiative had not been adequately communicated.
The team concluded that the poor maintenance of control room instrumentation placed an unnecessary burden on the operators and detracted from their ability to operate the plant.
3.2.4.2 Plant Equipment and System Operability There was an excessive number of plant equipment deficiencies which required maintenance or engineering attention.
Plant equipment deficiencies unnecessarily burdened the operators with additional actions, such as frequent draining of the reactor building closed cooling water (RBCCW) tank due to through-valve leakage, the estimation of flow during rad wasts releases because of an inoperable flow transmitter and obtaining grab samples every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and monitoring recombiner temperatures because of inoperable hydrogen monitors.
These items are discussed further below and additional examples of plant equipment deficiencies are presented in Section 3.3.2.2.
The RBCCW surge tank fill valve (1 RCC-V313) has had through-valve seat leakage of approximately 700 gallons per day since March 1989.
The inleakage required that an A0 drain the surge tank to an acceptable operating level about every six hours.
The condition results in additional radiological waste processing, and had the potential to mask reactor coolant inleakage to the RBCCW systems.
Although the repair work would be relatively simple, there had been no effort made to repair the valve.
An excessive number of active LCOs existed against both units because of equipment problems.
At the time of the evaluation, 11 LCOs were active against Unit 2 and 8 LCOs were active against Unit 1.
These LCOs did not include those entered to perform Technical Specification surveillance or tracking LCOs.
(A j
tracking LCO is a condition, usually caused by an inoperable component, which would lead to an active LCO upon changing plant modes and is, therefore, monitored, or tracked.) Although most of the LCOs were entered in 1989, some LCOs dated back as far as 1987.
For example, the radwaste effluent flow I
monitor transmitter had been inoperable since August 29, 1987.
Although the instrument was obsolete and needed to be redesigned, work was not scheduled to be completed until the 1990/1991 time frame.
Radwaste operators had to use flow estimation methods during liquid radwaste releases because of this inoperable transmitter.
Another example involved inoperable hydrogen monitors for the Unit 2, A and B j
The hydrogen monitors had been inoperable since April 19, 1988 and necessitated collection of grab samples every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and monitoring of recombiner temperatures while the SJAEs were in operation.
~~
35
The team's overall conclusion was that the number of plant deficiencies was excessive and adversely affected personnel and plant performance.
The duration of some deficiencies indicated a lack of appropriate prioritization and disposition by management.
Although recent management attention was noted to i
improve personnel and equipment performance as indicated by the " Ten Most Troublesome WR/J0s List," continued management attention is needed to assure l
tnat existing deficiencies are appropriately prioritized and those posing i
operational problems are corrected in a timely manner (see Section 3.3.4).
I 3.2.4.3 Impact of Equipment Problems The team found that the operators had grown accustomed to operating the plant with an excessive amount of inoperable or poorly functioning equipment.
Equipment problems adversely affected the operator's ability to monitor and respond to plant conditions and presented additional burden to the operators such as the need for manual repetitive tasks.
Additionally the high number and duration of equipment problems had contributed to a complacent attitude among the operators.
Interviews and discussions with a number of operators indicated that they did not consider the number of outstanding work requests on plant equipment to be a problem.
The team found that the operators had a tendency to judge the plant's material condition on the basis of the plant's condition during the 1981 through 1983 time period.
A common response from many operators to the team's questions concerning current equipment problems was that the situation used to be worse a.nd that it had improved since the early 1980s. Although the operators cited this improvement in the plant material condition, they did not indicate a need for further improvement. These operators also indicated that they were not concerned with the number of items on the main control boards which were not functioning properly and expressed that they received adequate maintenance and engineering support.
Although operations managers had taken several recent actions to track and trend the number of trouble tags on the main control boards and the number of control room annunciator problems and had instituted the " Ten Most Troublesome WR/J0s List," the operators were still complacent about working around, or living with, equipment problems.
In several cases, the operators displayed a general lack of inquisitiveness; they appeared to accept problems and activities without adequate explanation.
For example, on April 21, 1989, the Unit I shift crew was to perform a HPCI injection test such that the HPCI system would inject into the reactor vessel at power. The shift crew had received simulator training on the evolution the prior day and was well versed in the expected plant response.
However, when e
the two control room operators were questioned on why they were conducting this unusual test, they were at a loss for an explanation.
Both the control room operator and the shift foreman indicated that the NRC required that the test be performed.
In fact, the licensee decided to conduct the test to verify the HPCI system's operability because of past HPCI system performance problems.
Another example involved a problem with the RFP trip and reset circuitry.
When questioned, four control room operators and one auxiliary operator did not know of anything abnormal concerning the RFP trip and reset circuitry.
Although a work request on the circuitry existed, there was no trouble tag or other indication in the control room or on the equipment to indicate an abnormal condition.
The only indication to the operators that a problem existed was an entry on the last page of the Daily Status Report instructing the operators not to conduct a periodic test which affected the circuitry.
This instruction had been in effect since June 2, 1988.
The team concluded that the operators t.
36
l I
attitude and complacency towards equipment problems in general had been caused by years of operating while living with undesirable equipment conditions.
3.2.5 Operations Unit Management Performance I
i 3.2.5.1 Management Involvement 1
Management demonstrated a high degree of personal involvement in ongoing I
routine and off-normal plant activities.
Managen,ent performed daily plant tours and control room observations, and was actively involved in response to plant problems and special plant evolutions.
Management attention and support of crew training was evident in providing crew simulator training for special system testing, involvement in crew real time training, and presence during crew simulator training.
Management was aware of long standing organizational cultural problems, such as poor communications throughout the site, and was actively involved in the removal of communicat. ion barriers to gain operator confidence in management and support of improvement initiatives.
Effort in this matter includes weekly operations manager " feed back" sessions and biweekly general manager's " working lunch" sessions during the crew's training week. The " Ten Most Wanted List" was established to provide operators a means to identify and obtain priority response to correcting the most troublesome deficiencies.
The objective of this process was to increase the operator's sensitivity to living with or working around problems and to convey management's support of a better working environment for the operators.
Managers' personal involvement set a positive l
example (role model) for line supervision and underscored the importance placed on operator performance.
Some improvement in communications was observed during the evaluation.
3.2.5.2 Improvement Initiatives Both established and recently implemented improvement initiatives were reviewed i
and examined.
Some initiatives which had been established by the previous Operations Unit management, e.g., the operations quality team, were not being aggressively pursued by the current management.
Initiatives which had been recently implemented by the current management, e.g.,
"self-identification,"
lacked clear definition of objectives and did not include specific personnel performance standards.
Although some improvements as a result of these initiatives were observed, most of the current initiatives had been recently implemented and their overall effectiveness could not be evaluated.
The operations' improvement initiatives at Brunswick were responses to previous NRC identified deficiencies, and thus, reactive in nature.
Improvement initiatives that were evaluated included the following:
1.
In December 1986, an operations Q-Team was formed to identify opportunities to improve operator professionalism.
The Q-Team, comprised of a team leader and ten members, focused on the reduction of operator Opportunities identified by the Q-Team and implemented include; errors.
the closure of the control room work window during shift turnover periods, and provisions for summary descriptions of procedural / plant changes in the standing instructions.
The two additional opportunities initially -
identified were to improve the useability of procedures and the 37
a installation of large identification tags for valves specified for use in E
local emergency procedures.
At the time of the site visit, neither of these opportunity goals had been completed.
2.
In February 1989, the operations manager issued a memorandum which strongly supported "self-identification" of conditions adverse to quality.
This memorandum was intended to remove the punitive atmosphere associated with.' reporting of events, and to enhance operations root cause i
determination and corrective programs.
The team viewed this as a positive step toward increasing the operators' awareness of management's interest in reducing operators' reluctance to report plant and personnel i
deficiencies, however, the memorandum'did not provide definition of reporting threshold or process.
Through interviews, the team determined that operations personnel were generally aware of the self-identification memorandum, viewed it as a change in management philosophy and with some reservation were supportive of the program.
Additionally, on April 25, 1989, Operating Instruction 01-56 (Operations Conditions' Adverse to Quality (CATQ) Process) was issued which defined individual responsibility for identification and process of adverse conditions.
The procedure described the processing of CATQ which was defined as "an adverse condition associated with the safety function of a structure, system, or component that is Q-list, FP-Q or required for compliance with 10CFR71 (Packaging and Transportation of Radioactive Material)." The team believed that the defined reporting threshold will not significantly improve root cause determination as key information associated with balance of plant incidents or incidents having impact on plant operations would not be captured in this program.
(See Section 3.5.2) 3.
In January 1989, the Operations Manager established a corrective action subunit to review and categorize 1988 events involving plant operators.
The subunit identified five major cause categories as follows:
o Communications problems Incorrect / improper use of procedures o
o Clearance / work control problems o
Inadequate document reviews o
Inattention by operators Each cause category was assigned to a specific SOS for evaluation of the events including adequacy of root cause identification and corrective actions.
The 505 assignment is included in the management action tracking system with a response due date of May 20, 1989.
The results of the effort were not available for the team's review during the evaluation but the initiative indicated positive management action to improve overall performance.
The team's overall conclusion concerning recent improvement initiatives was that present management involvement demonstrated an increased level of attention and support of plant activities. The improvement initiatives, although positive, in many cases lacked clear definition of responsibility and accountability and effective implementation.
The ongoing initiatives reflected favorably on management's commitment to improve operations performance.
38
Although some improvement in open communications and operator acceptance of initiatives was observed, there remains opportunity for considerable improvement.
3.7 5 Operator Training Operator training was provided by two separate groups at Brunswick. The Brunswick Training Unit provided training not only to plant operators, but to maintenance crafts and for general employee training.
This Training Unit was managed from CP&L corporate offices and was separate from Brunswick plant management. The second group that trained operators was the Real Time Training (RTT) group and was part of the plant Operations Unit.
- 3. 2. 6.1 Brunswick Training Unit Staff The Brunswick Training Unit consisted of 20 instructors and 5 supervisors.
Nine of the instructors and two of the supervisors were assigned to licensed operator training.
All instructors had been qualified through the CP&L instructor certification program. The instructor's presentations were monitored annually by local supervisors for technical qualit corporate personnel for educational effectiveness.y and twice a year by The instructors were permanently assigned to the training unit.
Most of the instructors had been reassigned from plant operations to the training unit.
3.2.6.2 Training Instructor Workload The operator license training instructor's work load was excessively high which causes a reduction in the preparation time for lectures.
Instructors were not allowed overtime to prepare for presentations and often had to prepare for lectures at home.
The training materials were kept up to date despite the instructor work loed.
The lesson plans were a general outline so that the material to be included in the lecture was left to the discretion of the instructor.
These lesson plans would rarely need updating.
Each instructor was assigned the responsibility for updating certain lesson plans and training materials and would then usually teach that material.
The 1988 optrator requalification records had not received a final review and sign off approval until well into 1989.
This lack of review was attributed to instructor workload and a lack of supervision.
3.2.6.3 Training Instructor Morale The morale of all instructors interviewed was found to be low.
This was attributed to workload ano a pay freeze that occurred when the nuclear pay supplement was deleted.
The first year after the nuclear pay supplement was deleted, the instructors received an effective pay cut.
However, after complaints to corporate,.this cut was adjusted to a pay freeze for the next four years.
3.2.6.4 Licensed Operator Training The quality and effectiveness of the operator training program were above average as noted by the high pass rate for NRC examinations.
Training of the operators was observed in both classroom and simulator conditions.
All presentations were given in a very professional, relaxed manner that was -
conducive to learning.
The presentations contained a good mixture of lecture.
39
y p
u questions, and positive individual reinforcement for correct answers. When the students gave incorrect information, corrections were made, but in a manner that did not. embarrass the students and still reenforced learning. The simulator presentations reenforced the information presented in the classroom.
Feedback questionnaires from the students were evaluated and program improvements based on student feedback were implemented.
Despite the low instructor morale, as indicated through interviews, the presentations did not reflect a poor attitude.
However, interviews with the operating staff indicated that the instructors do complain in the presence of operators about j
workload and pay issues.
i 3.2.6.5 Simulator The simulator performance was observed on three occasions (1) operator license training, (2) a special training session for a crew that was going to perform a HPCI injection test, and (3) a special session requested by the team to evaluate a shift crew that had been observed operating the unit during 'startup.
During two of the observations severe modeling deficiencies.of the simulator were observed.
The deficiencies involved primarily the core and the nuclear boiler models and their interface with the other simulator models.
Poor simulator modelin water scenarios, g included the reactor " making" water during loss of makeup a lack of decay heat for end of cycle conditions, power reductions on ATWS scenarios without control rod insertion, and incorrect electrical bus interlocks.
Also noted during repeated scenarios was an inconsistent response which was attributed to the core and nuclear boiler model interface problem. Outstanding simulator service requests were noted from early 1986 and 1987.
Training management at the site wes aware of the simulator proolems and had l
worked through corporate menacpment to issue contracts for problem correction.
i The improvement program has been concentrated in two phases. The first phase was to update the hardware of the simulator to match the actual plant.
The second phase was under way and targeted partial replacement and improvement of the simulator software by February 1991.
Although improvements were being made in simulator fidelity, the quality of the simulator responses are misleading to the operators being trained and could effect their response during transient or accident conditions on the units.
The simulator was not certifiable in its present configuration because of these modeling limitations.
J 3.2.6.6 Real Time Training Group The RTT group consisted of one supervisor and three instructors.
The instructors were rotated from operations on a 1 year basis and had been l
qualified through the CP&L instructor certification program.
The RTT group was part of the operations unit.
The goal of the RTT group was to improve the quality of plant operations through training in the areas of management i
concerns, operator concerns, industry concerns, and plant modifications.
Despite the high workload on the three instructors, the training provided was j
of excellent quality and was presented in a timely manner. Training was i.
{
provided to the operating staff during the training week rotation.
If the j
subject warranted, on shift training was provided.
The RTT group interfaced closely with the Brunswick Training Unit, displaying an attitude of cooperation j
and willingness to share information to improve plant operations.
l l
40 1
l
___m__m__._
_m.
m___
1 3.3 Maintenance The evaluation of maintenance at Brunswick included reviews of documents, personnel interviews, and' observation of work in progress to examine preventive and corrective maintenance activities, the motor-operated valve maintenance program, and root cause analysis.
To a lesser degree, the team rvaluated the work planning and scheduling process, and the Maintenance Unit organization and staff, including technician training.
The team limited the scope of the evaluation of the Maintenance Unit because a Maintenance Team Inspection (MTI) had been conducted at Brunswick in January 1989.
The findings of the 4
diagnostic team and the MTI were generally in agreement.
For example, both l
efforts found that overall plant housekeeping was good; that the Automated Maintenance Management System was an excellent system for controlling and maintaining records of maintenance activities; and that the maintenance backlog was somewhat large but was on a downward trend, with work delays often caused by parts unavailability or slow, ineffective engineering support.
Additional details can be obtained by referring to the MTI report (NRC inspection report numbers 50-324/89-01 and 50-325/89-01).
3.3.1 Maintenance Organization and Staff The organization structure and staffing of the Brunswick Maintenance Unit were adequate.
The organization structure consisted of subgroups arranged according to craft discipline and nuclear unit, alon planning subgroups, and a " Plant Services"g with administrative and job subgroup responsible for work such as painting and preservation.
The complement of 300 personnel, which included supervisory personnel, was considered adequate for the needs of a 2 unit BWR site.
Morale within the Maintenance Unit was good, and craft personnel were knowledgeable and performed their jobs in a competent fashion.
This was indicated by interviews and observation of work in progress, including preventive maintenance (PM) of a service air 6-inch check valve, and torque and limit switch checks on a service water motor-operated valve (see Section 3.3.5).
Standardized technical training known as " Craft and Technical Development" was given to craft personnel.
This training was developed at the CP&L corporate level, and was common to all three CP&L nuclear sites.
The team considered this an example of good leadership and direction from the corporate office.
The standardization of technician training and the use of i
qualification signoff cards to fonnalize and document the training represented i
strengths in the maintenance program.
Backthift and duty day maintenance technician coverage was established for the mechanics in September 1988 and for the I&C technicians and electricians in April 1989.
The duty day crew provided maintenance coverage from the end of the regular work day until the arrival of the backshift crew, which provided coverage until the start of regular working hours.
Weekend and holiday coverage was split between the two.
The implementation of duty crews enabled quicker response to emergent work items by eliminating the delay associated with calling in technicians outside of normal working hours.
In addition, regular plant work was scheduled for and carried out by duty crew personnel.
As an incentive to the technicians, the rotation was arranged to provide up to 3-1/2 consecutive days off at the beginning of the cycle and 5-1/2 consecutive days off at the end, and discussions with licensee personnel showed a generally 41
~
l favorable response to the duty crew concept.
The team viewed the institution j
of duty day and backshift maintenance coverage as a positive step toward more efficient utilization of the maintenance staff.
l 3.3.2 Maintenance Work Practices 3.3.2.1 Site Work Force Control Group The licensee implemented the Site Work Force Control Group (SWFCG) in early loBB to improve coordination between onsite groups for scheduling work.
The
{
1
- i. dam viewed the use of the SWFCG process as a good work planning practice.
SWFCG consisted of representatives from various site organizational units, 1
including Operations, Maintenance, Technical Support. Radiation Protection, and i
QA. The group met each working day to review the status of all corrective
{
maintenance, preventive maintenance, and testing in progress or planned for that day, and to prepare and review a schedule for the current and following j
week's work items.
A SWFCG meeting was observed by the team.
The meeting was l
conducted in a professional manner, and the participants had clearly reviewed the applicable work packages prior to the meeting.
Administrative control of SWFCG's activities was found to be loose and informal.
The functioning of SWFCG was described in " guidelines" containing very little detail, as opposed to a more detailed treatment that might be found in an administrative procedure.
This low level of formalized administrative control was considered a potential weakness.
I 3.3.2.2 Automated Maintenance Management System The team found that the Automated Maintenance Management System (AMMS) was an excellent system for controlling maintenance activities and maintaining records. The AMMS was a computerized work request generation, planning,
{
scheduling, and retrieval system.
The system also scheduled preventive maintenance as well as tracked corrective maintenance.
Although the system was l
most frequently used by Maintenance and Operations staff, selected personnel in i
all organizational units had access to the system and system terminals were readily available in a number of locations.
3.3.2.3 Maintenance Unit Procedures The team reviewed a number of Maintenance Unit procedures used for performing preventive and corrective maintenance for a variety of plant components.
The licensee is currently upgrading the maintenance procedures with a dedicated staff of experienced writers.
The team found that the maintenance procedures were consistently formatted and well organized for ease of use.
The procedures i
reviewed were technically accurate and provided a high level of detail.
The l
Maintenance Unit was also responsible for development of the majority of the surveillance test procedures and these procedures were also of high quality.
A complete discussion of the surveillance test procedures is in Section 3.4.
3.3.2.4 Maintenance Work Backlog i
l A review of licensee records revealed a backlog of about 4700 pending l
preventive and corrective maintenance work requests.
Of these, 1500 required an outage for performance and the remaining 3200 were categorized as nono0tage items.
Licensee management estimated that the nonautage backlog represented about 2 weeks of work at the time of the diagnostic eva~1uation. and they s.
42 l
1
considered this to be an acceptable level for the backlog.
However, historical rates of work accomplishment indicated that a much longer period would be necessary to. eliminate the backlog.
In 1988, an average of 1850 work requests were completed each month.
At this rate, the nonoutage backlog of 3200 items would require about 1.7 months, or 7 weeks, to complete.
In discussioc.s with licensee personnel, work delays were often attributed to difficulties in obtaining replacement parts or engineering support.
The team concluded that although the maintenance work backlog had been steadily trending downward since 8
early 1988, it was still too large, and continued effort was needed in this area.
3.3.3 Control Room Instrumentation Maintenance Weaknesses l
l The team found that, in general, maintenance of control room instrumentation A check during the evaluation showed 124 trouble tags existed on the was poor.
Unit 2 main control boards and 30 existed on the Unit 1 main boards. The large difference between the 2 units was attributed to the recent completion of a Unit 1 outage when many items were fixed.
Of the Unit 2 trouble tags, 56 were awaiting an outage for compledon.
In addition to the problems identified by trouble tags, there were 47 control room annunciators in need of repair that were not tagged (see Section 3.2.4.1).
Although the majority of items requiring repair involved BOP equipent, these items negatively impacted operation of the plant, as illustrated below.
Examples of control room
-instrumentation problems and their history are as follows.
1.
A work request was initiated on October is, 1986 for a problem with the narrow range reactor water level instrument on the Unit 1 main control boards.
This instrument provides a signal to the Main Turbine and the Reactor Feedwater Pump trip logic, which could result in a reactor scram.
There was no record of work until January 22, 1988 when the ticket was reprinted because the old copy could not be found. On that date, the work request was given to Technical Support to determine a direct replacement part due to parts unavailability.
On March 24, 1988 additional planning was added to the work request and work was performed. On April 15, 1988 work was completed but the operators requested a rework because the indicated level was more than 1.5 inches out of agreement with the other a
two level instruments.
The rework was initiated on April 18, 1988 and on March 13, 1989 the work code was changed to " outage" work.
2.
A work request was initiated on January 24, 1989 for a feedwater flow indicator on the Unit 1 main control boards because the indicator was out of calibration.
On January 26, 1989 the work request was planned and on February 2, 1989 it was assigned for work.
Over the next four days several components were inspected. On April 28, 1989 a recalibration was attempted but the calibration tanks required were found to be contaminated, and the one remaining set of tanks at the site was in use.
On May 1, 1989 the second set of tanks was available, but it was determined that they were inaccurate at a calibration tool, and the technicians began construction of a new set of calibration tanks.
The tanks were expected to take up to two days to build.
3.
A work request was initiated on March 31, 1989 to repair the chart paper take-up reel for the Unit 1 main control board reactor level /pressurP recorder.
Planning was completed and work was started on that date.
During withdrawal of the recorder a spike in reactor water level was 43 1
o induced.
The operators succeeded in recovering from the resulting transient, but the level spike had the potential to cause a reactor scram.
A special procedure was then requested from Technical Support, and the procedure was approved 26 days later on April 26, 1989.
When work was started e days later on May 4, 1989, the operators were again challenged by a reactor water level transient induced by the repair efforts.
.As the above examples illustrate, the large number of. control room instruments in need of repair placed an unnessary burden on plant operators because they did not have the full corplement of process parameter indications and controls available for their use in operating the plant.
In some cases the instrument problems had the potential to cause plant transient *, including scrams.
Furthermore, the large number of inoperable instruments and the excessive length of time often consumed in effecting individual repairs had encouraged the operators to adopt an attitude of accepting and living with equipment problems (see Section 3.2.4.3).
As discussed in the above examples and in Section 3.6.1.2, maintenance efforts were often hampered by slow and ineffective assistance from the Technical Support organization.
The team concluded that there was low concern in the Maintenance Unit for expediting repairs that made operation of the plant easier, and that additional management attention was needed to better coordinate communications and team work among organization units to achieve timely resolution of control room instrument deficiencies.
3.3.4 Plant Equipment and Systems Reliability The team reviewed licensee efforts to resolve material deficiencies in the plant as t raans of assessing the effectiveness of maintenance activities at I
Brunswick.
Numerous weaknesses in the reliability and availa.bility of plant equipment and systems were observed.
Examples of these included the following:
1.
Multiple failures of the various keepfill systems had been experienced.
For example, the stem on the keepfill system pressure control valve (PCV) for linit 1 Loop B Core Spray System (1E21-PCV-F026B) was identified as being bent as early as April 20, 1986.
This was not repaired until December 3,1988, after the NRC Resident Inspectors noted that four of the twelve keepfill systems had inoperable PCVs.
In resolving the NRC action item associated with this problem, the licensee discovered that their operating practice of using the keepfill bypass valves (BPVs) to fill the keepfill lines ftom the demineralized water supply had caused 4
overpressurization of the keepfill lines, which in turn caused the PCVs to slam shut and suffer stem damage.
Also, the BPVs were damaged by using them to throttle flow, a purpose for which they were poorly suited since thsy were gate valves.
The functioning of the keepfill systems was thereby further degraded because the leaking BPVs caused an ongoing overpressure condition on the keepfill lines.
In addition, the overpressurization of the keepfill lines was exacerbated by two demineralized water pumps having the wrong size impeller, which gave a 10 psi increase in system pressure.
Corrective actions for keepfill system problems devised by licensee personnel were to change the appropriate I
operating and periodic test procedures, repair the damaged PCVs, replace i
the BPVs with globe valves to facilitate throttling when necessary, and install demineralized water pump impellers of the proper size.
Alth~ough appropriate corrective actions had been developed and pattially implemented, the process consumed an excessive amount of time, and the 44 I
1
1 f
problems did not receive meaningful attention until the NRC became involved.
Additional discussion of keepfill system problems can be found in Section 3.6.3.1.4.
2.
On April 27, 1989, the 28 nuclear service water (SW) pump motor burned up, and on May 1,1989, the 2A conventional SW pump motor experienced overheating problems.
history of SW pump motor failures and overheating problems.The te For example, the 2B and 1A conventional SW pump motors failed in September 1987 and May 1986, respectively, and six othar motor failures occurred from 1983 through 1985.
The licensee consulted with General Electric Company engineers in August 1986 and September 1988 concerning these problems.
These consultations and inspections of the failed motors pointed to poor motor ventilation and overheating leading to winding insulation breakdown as the cause of the motor failures.
It was discovered that some stator air ports had been partially blocked with insulation varnish and some stator and rotor air ports were not properly aligned with each other, i
apparently as a result of the original manufacturing or subsequeat rebuilding processes.
There were also indications of air cool',ng port blockage due to accumulation of dirt and corrosion products from the rotor assembly.
The result was motor air inlet to outlet temperature differentials as high as 43 degrees C, versus the expected 20 to 25 C.
In addition, the team learned that the process computer motor stator high temperature alarm setpoints had been raised improperly from 260 F to 1
302 F, without an adequate analysis of the effect of operating motors at a higher temperature. The maximum continuous temperature rating of the class B winding insulation used in many of the SW motors was 260*F.
This discrepancy was identified by the responsible system engineer, who initiated action to have the alarm setpoints returned to 260 F in August 1988.
While the setpoint was set at the higher value, SW pumps operated at greater than 260'F and incurred accelerated insulation aging as a result.
No action was taken to evaluate the effect of operating the motors at elevated temperatures. When questioned by the team, the licensee was unable to determine how long the setpoint had been set at the higher value (see also Section 3.6.3.1.5).
The knowledge gained from the numercus rotor failures and associated discussions with the vendor had not resulted in effective licensee actions to preclude recurrence of these problems, despite their longstanding nature.
3.
Electrical conduits and a junction box located on the Unit I north core spray room wall were severely corroded. These electrical components contained controls for the Unit I north core spray room sump pump and the power supply feeder for valve ISW-V128 (SW vital header isolation valve).
The condition was readily apparent and had existed for a number of years.
WR/JO 86-ASIL1 initiated in April 1986 identified " heavy corrosion to conduit" due to leakage of ground water through the seal on pipe penetration 1-008.
WR/JO 86-ASIN2, initiated in May 1986, stated that the electrical conduit and various components were " badly corroded and need to be replaced." EWR 06113, dated July 1988, addressed these concerns by stating "although conduit is corroded it is still intact and capable of carrying out its function, therefore it is not a deficiency." Further work was expected under this EWR, but the resolution target date assigned was July 1990.
The defective pipe penetration seal and resulting 45
)
\\
conditions had the potential to disable the room sump pump and ISW-V128.
The continuous leakage raised questions concerning the integrity of secondary containment.
4.
The Unit 1 RBCCW surge tank demineralized water fill valve, IRCC-V313, had seat leakage that requireo frequent attention by operators to drain down the surge tank to maintain level within acceptable limits (see Section 3.2.4.2).
Although a priority 3 WR/JO had been written in early 1989 on the problem, and it did not represent a difficult repair, it remained unfixed at the time of the diagnostic evci "ition.
l 5.
A review of various work requests indicated multiple failures for each of at lem 10 different pressure gauges in the plant over the years.
Althcagh a task group was looking at these failures, they were approaching them stri.:tly on a system by system basis and not studying the problem on a plan wide basis.
)
(
From these exampies, the team concluded that licensee development of corrective actions for chronic equipment problems was often excessively slow, root cause analysis was poor and ineffective, and repairs that would reduce the burden on operators were not given sufficient priority.
Once resources were focused on a problem, the corrective actions were generally of high quality.
However, the licensee often failed to recognize problems as chronic and to prioritize them such that they received the attention necessary for resolution.
NRC involvement was sometimes necessary before chronic problems were fully recognized, analyzed, and driven to full resolution (see Section 3.1.4).
Increased management attention was needed to assure that existin were appropriately prioritized and corrected in a timely manner.g deficiencies 3.3.5 MOV Program The team reviewed documents and activities associated with Brunswick's f
motor-operated valve (MOV) maintenance program, including the licensee's MOV Project Plan and MOV Task Group Final Report, preventive and corrective maintenance procedures, completed work requests, and MOV work in progress.
Significant effort had been expended at Brunswick to address its long history of MOV problems.
This effort resulted in the development of an MOV maintenance program with many strong provisions, but the team found that programmatic strengths were offset by significant weaknesses in program implementation.
Overall guidance for MOV maintenance activities was given in the " Project Plan for Limitorque MOV Actuator Maintenance Program." The purpose of the program was to " insure Limitorque MOV actuators are maintained to the necessary quality to provide continued reliable service with a minimum of failures." Strong attributes of the Project Plan included the requirements for technicians to receive formal T V training prior to working on MOVs (or to be under the direct supervision of another technician who had been trained), and for all safety-related MOVs to receive periodic diagnostic testing with specialized diagnostic equipment known as the " Motor Actuator Characterized" (MAC).
In addition, the Project Plan called for electrical and mechanical PM to be performed at the vendor specified periods on both safety-related and BOP MOVs.
The licensee had developed in-house expertise at Brunswick on the use of the MAC testing equipment, and the equipment was used for both periodic testing and analysis of MOV failures.
While the team was onsite, Brunswick MAC testing 46 L - _- _-- -_
g perscanel and their equipment were sent to CP&L's Harris plant to provide
-technical assistance with an MOV problem. This was an example of' good inter-site communications and teamwork.
Limitorque operator mechanical ccrrective maintenance (CM) procedures were reviewed by the team and found to be of high quality.
The procedures were organized in a logical sequence and contained numerous illustrations to assist the mechanic.
The list of precautions and limitations as well as the procedure steps themselves indicated that the licensee was familiar. with and applied much of the accumulated industry experience on MOVs.
For exe le, the concerns discussed in' IE Information Notice 85-22, " Failure cf Limitorque MOVs Resulting from Incorrect Installation of Pinion Gear," were clearly addressed by procedure steps and illustrations, and the possibility'of invalidating an MOV's environmental qualification by the use of improper gearbox grease was removed by specifying the use of only Exxon Nebula EP-1.
The team noted that procedure OCM-M0500, which governed mechanical repairs to SMB-5 and 5T actuators, permitted the use of other gearbox greases, but responsible licensee personnel stated that the procedure would be revised to bring it into line with the procedures for smaller actuators.
The mechanical and electrical MOV PM procedures were, in general of high technical quality.
However, a weckness in the MOV PM program was that the electrical PM covered by procedure OPM-M0004 called for the checking of limit switch settings every 36 months switch settings were within pres,cribed limits.but did not require verification that torque Under the current program, such a verification would be made once every 6 years during periodic MAC testing (only for Q-list MOVs), or possibly when an MOV required corrective maintenance.
The team learned of several examples in which Q-list MOVs were found with improper torque switch settings, as discussed later in this section.
A review of licensee records revealed a poor completion history for the PMs.
Of 802 BOP and Q-list MOVs in the two units, 242, or 30 percent, had never received the mechanical PM, and 554, or 69 percent, had never received the electrical PM.
A review of just the Q-list MOVs, which totaled 316 between the two units, showed that 2 percent had never received the mechanical PM and 58 percent had never received the electrical PM.
In addition, the team discovered that a failure of the 2A nuclear service water pump to start occurred in August 1988.
The starting logic of the pump is electrically interlocked with the pump discharge isolation valve, 25W-V19, and the licensee's investigation determined that an out-of-adjustment limit switch on the valve actuator had prevented proper operation of the MOV, which in turn prevented starting of the pump.
The MOV electrical PM could have led to the discovery and correction of this problem, but 25W-V19 had never received the PM prior to this failure.
The licensee had attempted to establish administrative control over MOV torque and limit switch settings.
Procedure ENP-43, "Q-List MOV Settings," provided safety related MOV allowable torque and limit switch setting values and guidance to be followed when it was necessary to change these allowable values.
ENP-43.1, "Non-Q MOV Torque Values," provided sim*lar controls for B0P MOV torque switch settings.
However, thcre was a conflict between ENP-43 and modification procedure NED-IA-0Gs, which required the use of a modification package to change MOV switch settings (see Section 3.6.4).
In addition, discussions with licensee personnel revealed that the figures provided in Tables 1 and 2 of ENP-43 for torque and limit switch settings were in error in 47
many cases.
For example, several butterfly valves in the service water system had been changed by plant modification from Fisher to Jamesbury valves.
The new Jamesbury valves required different torque and limit switch settings than the Fisher valves they replaced.
Some of the Jamesbury valves had been installed a, early as February 1987, but the data in ENP-43 had still not been updated at the time of the diagnostic evaluation.
The bulk of the errors in the ENP-43 tables were identified by the MOV Task Group (see Section 3.1.4) and were documented in the final MOV Task Group Report of December 1988. as items requiring additional work at some future date.
No date was specifiad in the report for correction of the arrors, but responsible licensee r esr el indicated that a revision to ENP-43 correcting these deficiencies was expected to be approved by the end of May 1989.
The integrity of torque and limit switch settings in the plant was being maintained through the efforta of the
'imitorque Maintenance Engineer, who kept an " unofficial" version of the ENP-43 tables with the most current switch setting data.
The use of such an unofficial document was contrary to the provisions of ENP-43, paragraph 3.2.1, which stated, "All personnel shall follow this procedure to determine limit
)
switch settings or torque values on any of the valves listed in Tables 1 and 2 and all MOVs installed or replaced by a modification."
As a result of concerns raised by the team regarding leakage between the nuclear and conventional service water headers (see Section 3.6.3.1.2), the l
licensee performed checks of the torque and limit switch settings of several service water MOVs.
The team witnessed this work on ISW-V18, which served to isolate the IC conventional service water pump discharge from the nuclear service water header.
The technicians involved were knowledgeable, worked well together, and followed the procedure properly.
The Limitorque Maintenance Engineer was present and provided guidance as necessary.
However, these checks revealed improper torque and/or limit switch settings on each of the MOVs checked.
(MOVs checked during the diagnostic included ISP V14, 16, 18, 102, 118, and 25W-V14, 16, 18, and 111.
The licensee planned to check several other SW MOVs subsequent to the team's departere from the site.) The improper torque switch settings were determined to be due to relaxation of belleville spring pack washers, and in one case due to corrosion of the torque switch assembly.
The improper limit switch settings were in some cases due to the change from Fisher to Jamesbury brand valves, and in some case due to an error made when the limit switches were last set.
The team concluded that many of the elements necessary for a successful MOV program were in place at Brunswick, but that significant additional effort and management attention were needed to ensure the many strong provisions of the t
program were consistently implemented in the plant.
3.4 Surveillance and Testing The team reviewed the licensee's testing programs and their implementation, with emphasis on testing required by the technical specifications (TS).
The team evaluated the inservice testing required by TS 4.0.5 and performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code.
Test procedures and completed tests were reviewed for technical adequacy and followup corrective action.
The team witnessed the conduct of surveillance on the service water (SW), high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems.
The team also reviewed the TS requirembats for the SW system and selected TS interpretations.
s.
48
r 3.4.1 Technical Specification Surveillance Testing As.a result of a previous failure to verify or demonstrate by surveillance tests that safety systems would, if called upon to function, operate in accordance with design specifications, Confirmatory Order EA-82-106 was issued on December 22, 1982, and ramains in effect. The Confirmatory Order directed the licensee to implement the Brunswick Improvement Program (BIP).
This program contained seven major objectives related to the adequacy and the accuracy of the TS surveillance program.
Three of these objectives were (1) to ensure full and timely compliance.to all surveillance requirements, (2) tc ensure that all procedures were clear and of high technical quality, and (3) to increase the frequency and scope of QC surveillance and corporate auditing program activities.
3.4.1.1 Surveillance Tracking and Scheduling System (STSS)
The licensee established the surveillance tracking and scheduling system (STSS) under the direction of the Regulator systematic program for identifying, y Compliance Unit as a centralized scoping, scheduling, tracking, and closing of all surveillance requirements and regulatory commitments and requirements.
The STSS was implemented as a BIP corrective action to ensure full and timely compliance to TS surveillance requirements.
This program was computerized and all T5 surveillance were scheduled and tracked by the regulatory compliance unit with the STSS.
The Operations, Maintenance and Technical Support Units were notified by the Regulatory Compliance Unit of the due dates of required surveillance and the various units were responsible for surveillance completion. The team concluded that this was an effective method to schedule and track the TS surveillance tests.
However, the STSS did not schedule and track surveillance other than those required by TS.
For example, the operations organizational unit had 11 non-TS and 132 fire protection surveillance that were not included in the STSS.
A weakness in implementation of the STSS was that the accuracy of the STSS data base was not periodically verified to ensure that all the TS surveillance requirements were tracked by the STSS.
The licensee confirmed that neither the site nor corporate Quality Assurance Units performed a periodic verification of the accuracy of the STSS data base.
The integrity of this data base was originally verified as a result of BIP Action Item II-3A.
However, subsequent to this effort, only new or revised TS surveillance procedures were reviewed.
(see Section 3.5) 3.4.1.2 Technical Specification Interpretations The team reviewed the following Technical specification Interpretations (TSIs) which were developed by the licensee in accordance with Regulatory Compliance Instruction, RCI-02.3, " Technical Specification Interpretation Request, Processing, and Maintenance," Revision 2, maintained by the Regulatory Compliance Unit and approved by the Plant Nuclear Safety Committee (PNSC).
49
1.
TS1 07-01, Minimum Offsite to Onsite Electrical Circuits 4
Technical Specification Interpretation 87-01, approved on March 10, 1987, incorrectly interpreted TS 3.8.1.1 concerning the number of paths from the 1
offsite to the onsite electrical system.
The T5I was based on the assumption that the General Design Criteria (GDC-17) requirement for two physically independent paths from the offsite (switchyard) to the onsite emergency loads was more than satisfied by the design of the offsite transmission network
)
(grid) to the switchyard through the use of four separate transmission lines.
The TSI failed to address the GDC-17 requirement for two physically independent paths from the switchyard to the emergency loads. The design of the Brunswick uses two physically independent circuits from the switchyard to the emergency
)
loads by the use of the station auxiliary transformer (SAT) as the " normal"
)
source and the unit auxiliary transformer (UAT) as the " alternate" source.
However, since the TSI was based upon the four transmission lines to the
{
switchyard, the licensee believed that there was no single " alternate" source i
and, thus, concluded that the surveillance and LCO requirements of the TS were i
not applicable.
As a result of this incorrect interpretation the required actions for the T5 3.8.1.1.1 Limiting Condition for Operation (LCO) for minimum AC electric power sources were not accomplished whenever the UAT or SAT were removed from service.
A review of the material history files indicated that the Unit 1 main and unit auxiliary transformers were removed from service in November and December of 1988.
These actions require demonstration of the operability of the remaining AC offsite source within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, demonstration of the operability of the diesel generators within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, and restoration of the inoperable offsite circuit within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
- However, actions required by these LCOs were not accomplished.
The GDC-17 requires that both of the physically independent circuits be designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite electric power circuit.
The use of the UAT as the " alternate" source of offsite power requires that the main generator disconnects be removed and associated protective circuitry be bypassed to allow backfeeding the main transformers to the UAT.
In order to meet the intent of GDC-17, this evolution must be able to be accomplished before the specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are exceeded.
Although Operating Procedure (0P) 50, " Plant Electric System Operating Procedure,"
Revision 26, provided instructions for the required evolutions, at the time of the evaluation, the licensee had not demonstrated that this design requirement could be accomplished in the required time.
Further, the licensee had not performed an analysis to determine the time allowable to utilize offsite power to supply site electrical loads utilizing the unit auxiliary transformer.
In fact, the procedure was only recently developed and it is unlikely that the design requirement was previously recognized.
2.
TSI 85-08, Testing of Alternate Electrical System The licensee incorrectly interpreted the TS surveillance requirements of TS 4.8.1.1.1 concerning the applicability of testing the alternate offsite I
~
l 50 l
s electrical path.
Technical Specification Interpretation, TSI 85-08, approved on March 5, 1985, concluded that the surveillance requirement to demonstrate the operability of the alternate circuit every 18 months was not applicable to Brunswick.
The licensee incorrectly assumed that the four feeders to the offsite distribution system satisfied the GDC-17 design requirement for two physically independent circuits between the offsite and onsite distribution systems. The TSI indicated that Brunswick did not have an " alternate" circuit and therefore surveillance testing was not required.
A test procedure to demonstrate the function of the automatic bus transfer from the UAT to the SAT has not been developed and the testing has not been periodically performed.
3.
TSI B4-06, Service Water System Limiting Condition for Operation (LCO)
In 1985, the licensee identified that the TS for the the Service Water System were not sufficient to ensure that the safety function of the system would be satisfied.
Technical Specification 3.7.1.1 required two independent residual heat removal service water (RHRSW) subsystem be operable with two pumps and an operable flow path in each subsystem.
This requirement was not sufficient to ensure that the safety function of the system would be fulfilled because it did not specify that both the nuclear and conventional service water headers be operable and did not address the divisional loading of the pumps (as discussed below).
TSI 84-06, Revision 4, approved January 21, 1988, required more service water pumps to be maintained operable than specified in TS 3.7.1.1 (Amendment 78).
A TS interpretation was developed to require additional SW system pumps to be maintained operable and to specify the divisional loading and the type (i.e., nuclear or conventional service water header).
Revision 4 to TSI 84-06 was written to ensure that sufficient pumping capacity would be available in the correct time frame during a postulated design accident scenario.
The conventional SW pumps are inhibited from starting for the first 10 minutes following a Engineered Safety Features (ESF) actuation.
Therefore, the nuclear SW must be available during the first 10 minutes.
In addition, the revision incorporated a site wide vice a unit operability requirement for the SW pumps because the availability of the nuclear SW pumps are directly related to the availability of the diesel generators.
At Brunswick all four diesel generators are required to be operable with either unit operating.
Finally, the revision attenpted to separate the SW system into divisions which were common to both Unit 1 and Unit 2.
The revised TSI required two nuclear service water pumps per unit, and an additional two pumps per unit (either conventional or nuclear), each powered from a different division.
As a result of the team's findings with respect to the design and operability of the service water system (Section 3.6),'the licensee recognized that the latest interpretation was not sufficient to ensure the safety function of the service water system would be fulfilled.
At the conclusion of the evaluation, a new revision was in c'evelopment to address the SW system pump capacity problems related to leakage between the nuclear and conventional SW system headers.
In addition, the new TSI would maintain site vice unit criteria and maintain divisional separation of the pumps.
The TSI (not yet approved by the PNSC) was provided to the operations unit for use by Technical Support Memorandum (TSM)89-295, dated April 27, 1989.
The engineering guidance,
required four nuclear service water pumps and two conventional service wat~er pumps (each powered from a different division) operable in all operational 90 des with either unit in operation.
51
{
' 4.
TSI 85-01, Primary Containment Isolation Valves The licensee used'this interpretation to redefine the piimary containment isolation valves and effectively deleted the stroke time testing of containment isolation valvas specifically ider.tified in TS Table 3.6.3-1, " Primary Contain-ment Isolation Valves, due to an incorrect Technical Specification Interpretation.
TS 3.6.3 required that the primary containment isolation valves specified in Table 3.6.3-1 be operable with specified isolation times.
TSI 85-01, apprcved on November 17, 1987, indicated that the correct primary containment isolation valves were identified in Tables 2.4.2 and 2.4.3 of System Description, 50-12, " Primary Containment Isolation System,"
Revision 013.
Based on this interpretation, the licensee determined that i-surveillance testing of eight valves, which are listed in the TS Table 3.6.3-1, were not required to be tested for isolation tinies.
These valves were:
Unit 1 E11-F040 RHR discharge isolation valve to radwaste E41-F041 HPCI torus suction isolation valve E11-F022 Reactor vessel head spray isolation valve (valve is deenergized)
E11-F023 Reactor vessel head spray isolation valve (valve is deenergized)
Unit 2 E11-F049 RHR discharge isolation valve to radwaste E41-F041 HPCI torus suction isolation valve E11-F022 Reactor vessel head spray isolation valve (valve is deenergized)
E11-F023 Reactor vessel head spray isolation valve (valve is deenergized)
The licensee indicated that the TSI was initiated as a result of the continued failure of these valves to meet action levels during stroke time testing.
The licensee reevaluated the purpose of the valves and concluded that they did not have a primary containment isolation function.
A TS change request was submitted in 1984 to remove these valves from the TS surveillance requirements.
However, periodic testing has not been performed in the interim.
In each of the examples noted above, a significant period of time had passed since the regulatory compliance unit had identified the deficiency requiring a interpretation and the time when a TS char.ge had been submitted.
i 3.4.1.3 Surveillance Test Procedures The licensee established a Procedures Administration Manual (PAM) governing the standardization and preparation of plant procedures and utilized a qualified l
consultant to modify or develop necessary plant operating procedures.
These c
corrective actions were in resporse to BIP action item II-1 to ensure that all
{
i procedures were clear and of a tigh technical quality.
Although the licensee 52 j
.c had completed these~ actions and had significantly improved the quality of the surveillance test proceoures, the PAM had not been effectively implemented.
The PAM provided comprehensive guidance for the development and revision of the Plant Operating Manual (i.e., all plant procedures); guidance for the preparation, revision, or change of. procedures; and preparation standards for all procedures.
The Operating Manual, Administrative Procedure (AP), Voluine I, Section 5, Paragraph 5.7.1, indicated that the format.and content of new procedures would be established by (1) the format and content of existing procedures, or (2) the PAM.
The Maintenance Unit had incorporated some of the PAM attributes, but the PAM had not been revised since January 5,1984, and had not been actively and comprehensively implemented.
The Operations Unit did not have a controlled copy of the PAM for general guidance of procedure revisions and indicated that the procedure war only general guidance.
There was not a clearly established hierarchy of procedures at drunswick, so the inconsistency between the PAM and the AP created more confusion than it would otherwise.
Surveillance tests intended to meet TS requirements were performed and developed by a wide variety of groups onsite.
However, because the majority of the TS surveillance requirements are devcioped by the Maintenance Unit, only these procedures were reviewed.
The team reviewed seversi procedures developed for instrumentation and control surveillance testing and concluded that the Maintenance Unit procedures were in accordance with the PAM, consistently formatted and provided a high level of technical detail for supoort of the Operations Unit and the performance of procedure changes, maintenance and post-modification testing.
Several positive and innovative methods have been uced in the development of maintenance unit surveillance test procedures.
For
- example, MP-52, " Standards for Preparing and Maintaining Maintenance o
Protedures," Revision 4, provided a standardized method for preparing the surveillance tests in accordance with the Procedures Administrative Manual.
The maintenance unit was finishing converting all periodic tests into maintenance surveillance tests (MSTs) in order to implement this guidance, Procedures MP-52A through MP-52R, (various +
o
< j, provided a 4
detailed description of the system tests useu to define and control the overlap between logic functional system tests and channel calibration tests.
The team concluded that this was an excellent method to ensure the entire instrument train is properly tested and to support future modifications and maintenance testing.
All MSTs had a separate test summary sheet which provided a o
description of the test; the required plant conditions; any alterations to the plant systems net.assary for the test; the expected annunciators and affected indications; and possible TS LCOs.
This summary was required to be supplied to the operations unit shift foreman prior to beginning the test procedure.
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The MSTs were developed with a high level of detail.
Although some o
technicians were concerned that the procedures were too " wordy", the Maintenance Unit supervisors believed that a high level of detail prevented misinterpretation and thereby procedure change requests and ensured an awareness of the significance of the technicians' actions.
Maintenance Unit technicians were comfortable with the procedures and o
confident-in their use.
The technicians were proud that in the last four years there were no instances of scrams due to personnel errors implementing the maintenance surveillance tests.
There was an inconsistency between the Operating Manual ano the Maintenance Unit procedure which implemented the requirements of the Operating Manual for temporary procedure revkions.
Maintenance Management Manual 0MMM-013,
" Maintenance Surveillance Test User's Guide," Revision 4, Section 5.2.6 (Page 16, Revision 2), required implementation of temporary revisions following approval by two knowledgeable plant management members and a safety evaluation.
However, Operating Manual Administrative Procedure Volume 1. Book 1, Section 5.7.4.2, did not require a safety evaluation for a temporary revision.
As discussed below, the team also identified that the Maintenance Unit incorrectly approved a temporary procedure changa due to the complexity (double negatives) of the forms used in the maintenance surveillance test procedure change process.
In addition, the Operations Unit exhibited a lack of attention to detail during the review of the temporary procedure change.
During the performance of 2MST-HPCI21R, "HPCI Steam Line Break High D/P Instrument Channel Calibration Test," the team identified that the maintenance procedure change traveler [i.e., Appendix A of Maintenance Policy Notice MPN 88-005, Revision 2]
was completed and signed by the Maintenance Unit but was incorrect.
The traveler was used to identify whether the proposed change could be processed as a temporary change in accordance with Operating Manual Administrative Procedure Volume 1, Book 1, Section 5.7.4.2 and Maintenance Management Manual 0MMM-013,
" Maintenance Surveillance Test User's Guide," Revision 4.
Maintenance Unit personnel incorrectly answered several of the questions as " disagree".
However, the reviewer did not recognize that the use of any " disagree" answer precluded approval of the proposed temporary change.
In addition, the 505 failed to recognize the discrepancy in the use of the form for this revision during his review and approval. As a result, both management representatives (including an individual with a senior reactor operator's license) failed in their responsibilities as identified in the Plant Operating Manual.
t Further review did not identify additional examples in which the form was misinterpreted.
Prior to the conclusion of the diagnostic, the licensee revised the form to clarify its use.
This instance did not result in the incorrect level of review and approval for the temporary revision.
- However, the failure to correctly use the form was indicative of a lack of attention to det. ail by maintenance and operations management.
54
c, 3.4.1.4 ASME Section XI Surveillance Testing The ASME Section XI Inservice Testing (IST) Program at Brunswick is defined in CPL-01, " Inservice Testing Program for Brunswick Steam Electric Plant, Units 1
, and 2," and submitted to NRC for_ approval.
Tne ISI group of the Technical Support Unit was responsible for the development and implementation of the ISI/IST program.
Engineering Procedure, ENP-16, " Procedure for Administrative Control of Inservice Inspection Activities", documented the administrative-controls and ENP-17, " Pump and Valve Inservice Testing," listed the detailed
- IST program requirements and identifies all the pumps and valves included in the program and the appropriate testing frequency.
Valves and test re-quirements as stated in 10 CFR 50, Appendix J are also_ included in the IST
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program. _ The Brunswick IST program (CPL-01) for the second (current) interval was submitted in 1986, but has not yet been approved by NRC.
The team reviewed these Engineering Procedures and discussed the development and implementation of the program with the responsible individuals.
There was no corporate policy or organizational guidance responsible for the ISI/IST
_ program. The project engineer for engineering support of ISI/IST indicated that there had been no counterpart meetings in the last five years except for a recent'one which he initiated.
Brunswick management supported the effort, but this was not a corporate initiative.
The next meeting was delayed due to the extended _ outage of Unit 1.
Periodic revisions and technical reviews of the IST program and data were performed by the Brunswick IST group without support from other groups within the CP&L organization.
A review of HPCI system valve IST requirements was recently completed by the IST group after NED postponed action on a request for assistance (due to budget concerns).
The team concluded that there was no corporate guidance provided for the development of the ISI/IST program land that lessons learned from other CP&L facilities were not ~
incorporated into each other's programs.
This is an example'where the absence of corporate direction or involvement was compounded by program weaknesses discussed below.
Evaluation of the pump IST program included' review of program records and completed pump tests and interviews with technical support unit IST group personnel. The review of records was restricted primarily to the SW and RHRSW systems.
Several weaknesses in the program were found and are discussed below.
The Technical Support Unit IST managers responsible for ASME Section XI pump testing showed a lack of enthusiasm for the current program and a hesitancy to change the program.
The IST group had purchased new vibration monitoring equipment, but did not expect to install this equipment before the end of 1989, and had made no commitments for installation.
An interest was expressed toward using pump vibration velocity (as opposed to displacement) measurement for fulfillment of Section XI testing requirements.
However, this cannot be implemented until the new vibration monitoring equipment is installed, training is performed and new reference values established.
Auxiliary operators (A0s), as opposed to IST group personnel, are used to obtain data for ASME Section XI inservice tests in accordance with IST and l~
vibration monitoring procedures.
The training of Operations Unit A0s in the use of current vibration monitoring equipment (vibrometers) is weak.
Classroom training in the use of vibrometers was last given during the first quarter of 1987 as part of operations unit RTT.
Since then, A0 training involves on the job training in that an unqualified A0 participate in a surveillance test with u
55 i
i
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a qualified A0.
At the time of the evaluation, there were A0s who had not received classroom training in vibrometer usage.
Classroom training in the use of vibrometers is scheduled for the third quarter of 1989.
A lack of communication and teamwork exists between the IST and maintenance engineering groups, both of which are in the Technical Support Unit.
Both groups perform vibration monitoring on pumps, with the maintenance engineering group performing more detailed testing for predictive maintenance.
Numerous pumps are included in both programs, including the SW and RHRSW pumps.
However, the IST group had made no effort to incorporate testing performed by the maintenance engineering group into the ASME Section XI IST program.
This is an example of poor teamwork.
The Operations Unit scheduled and performed individual performance tests based i
on output from the STSS, reviewed the data for equipment operability concerns, and then notified the IST group that the test had been completed.
The IST group then had 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> to review the data.
IST group personnel did not routinely observe the performance of inservice tests.
The team reviewed the 'Section XI testing of the 2B nuclear service water pump conducted on April 11-12, 1989, and discovered several problems.
Section XI of the ASME Code is intended to test the performance of individual components within a system; in this case the 2B nuclear SW pump.
Several factors in the f
design and maintenance of the SW system prevented proper evaluation of the pump's i
head-flow performance.
First, the flow element used to take pump flow data was located several hundred yards downsteam of the pump; second, there were a i
number of system valves in the discharge of the pump and in parallel with the flow element, some of which were suspected or known to leak; and third, the pump discharge pressure gauges used to take test data were unreliable.
- Thus, when flow was set at the value prescribed by the performance test procedure, it was unclear if the flow was only that due to the pump under test, or if it had been supplemented or diminished by leakage into or out of the nuclear header through the valves in parallel with the flow element.
Uncertainty in pump flow introduced uncertainty in the meaning of D/P results, and essentially invalidated the test. Questionable discharge pressure gauge performance further increased the uncertainty of test results.
The performance test procedure, PT-24.1-2, Revision 6, Step 4.0.5, acknowledged the effects of system leakage on indicated flow and called for minimization of D/P between the nuclear and conventional SW headers to " prevent possible cross-leakage." The procedure provided no guidance on how this was to be accomplished, nor what D/P between headers would be considered acceptable.
In the case of the April Il 2B nuclear SW pump test, D/P fell in the high required action range.
The testing conducted on the following day confirmed licensee suspicions that leakage past 25W-V14 and 16 (discharge isolation valves from the 2A and 2B conventional service water pumps to the nuclear header) was permitting the conventional SW pumps to supplement the flow provided by the 2B nuclear SW pump.
This resulted in a lower true 2B nuclear SW pump flow than that shown by the flow element, and consequently a higher D/P.
The licensee reduced the number of conventional SW pumps running and retook the data for the 2B nuclear SW puinp, with the result that D/P improved and permitted the pump to be declared operable.
The licensee considered this action proper because the problem had been demonstrated to be with valve -
leakage and not with actual pump performance.
Although WR/J0s had been written in November 1988 to repair the leaking SW isolation valves, the work had been 56
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iL___.__
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deferred until the next Unit 2 outage.
The team concluded that the licensee j
had accepted degraded equipment performance and other SW 1eakage as part of
" normal" operations, and that test controls were inadequate to provide-l standardized test conditions and permit proper evaluation of pump performance.
l (Also see Section 3.6.3.1).
The team reviewed the Brunswick valve IST program, focusing on the SW and RHRSW systems.
Program records and completed valve tests were included in this review, as well as interviews with technical support unit IST personnel.
ASME Section XI relief request VR-02 showed conservatism in the establishment of a reference value for each valve in the IST program.
This reference value was the average of several stroke times for the valve when in a known good condition. -Successive tests of this valve were compared to the reference value instead of the previous stroke time.
This practice placed absolute limits on the deviation of valve stroke times from an optimum value.
Additionally, since limits on stroke time deviation were fixed by the creation of a reference, the need for field calculation of stroke time deviations was eliminated. In addition, the IST group developed valve data sheets for ute when establishing reference values for valves.
These sheets contained several stroke times for i
1 the valve along with TS or Updated Final Safety Analysis Report (UFSAR) specified maximum valve stroke times.
IST group personnel then generated a reference value based on the average stroke time or the most limiting TS or UFSAR specified time.
Absolute stroke time deviations of 25 percent (increased frequer.cy) and 50 percent (required action) are then calculated and compared to the TS and UFSAR values to ensure compliance.
This practice permitted the inservice test program to satisfy applicable operability test criteria.
The team-found that three ASME Code boundary valves in the SW system were missing from the Brunswick IST program.
The specific valves were SW-V144 and SW-V148 (well water supply to RHRSW suction header) and the SW-V192 (well water supply to vital service water header) valve. These are check valves which are required to close upon a loss of pressure in the well water system in order to preserve Service Water system design pressure and flow rates.
Additionally, if the SW-V144 or SW-V148 valves failed open, cross leakage could occur between the independent Unit 1 and Unit 2 Nuclear Service Water Headers.
The licensee had begun an informal program to review the ASME Section XI testing requirements of all systems to verify that all the required valves are included in the program and to verify that the tests performed on these valves were adequate to satisfy ASME Section XI IST requirements.
During the review of the HPCI system, which was the only system reviewed to date, four valves j
were determined to be missing from the IST program.
These valves were the 1
inboard and outboard HPCI barometric condenser condensate pump drain line to
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radwaste isolation valves and the inboard and outboard HPCI steam line drain pot to radwaste isolation valves.
There was no formal commitment date for the completion of review of the remaining systems, and no procedures existed to control the performance of these reviews.
The ?icensee intended to use these reviews as the basis for a controlled technical support document.
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3.4.2 Conduct of Testing 4he team witnessed the following TS survei' lance tests:
2MST-HPCI13M, "HPCI Steam Leak Detector Channel Functional Test" 2MST-HPCI14M, "HPCI Steam Leak Detector Channel Functional Test" 1MST-RWCU22M, "RWCU Steam Leak Detection Channel Functional and Setpoint Adjustment" 2MST-HPCI21R, "HPCI Steam Line Break High D/P Instrument Channel C.libration Test" The operators and technicians performing the tests were knowledgeable and followed the procedures properiy.
There was good coordination between the personnel in the control room and the operators running the test at the equipment location.
The conduct was judged to be satisfactory.
However, some weaknesses were identified.
For example, the maintenance and operations units did not strictly adhere to the prerequisites for the performance of Maintenance Surveillance Tests HPCI13M, HPCI14M, and HPCI21R.
Each of these MSTs had prerequisites to preclude the performance of the test if any testing or maintenance is in progress which could initiate or isolate the high pressure coolant injection system.
After initially disapproving the simultaneous performance of both HPCI21R and HPCI13M, the operations unit shift foreman approved them based on discussior.s with the periodic test (PT) crew foreman and reference to the Section 5.3.6 of MMM-013, " Maintenance Surveillance Test User's Guide," Revision 4.
The PT foreman and the shift foreman concluded that this section allowed discretionary authority to interpret the prerequisites of 1
maintenance surveillance procedures "as appropriate" and allowed both tests to be performed if the PT crew coordinated the testing to prevent false isolation signal logic.
OMMM-13, Section 5.3.6, was incorrectly interpreted.
The phrase "as appropriate" referred to the requirement to obtain either one or both of the Units Shift Foreman's approvals, if required, and did not indicate that this is an acceptable method of performance.
Although a testing error did not occur as a result of the simultaneous performance of these procedures, the Maintenance Unit's interpretation of the test performance requirements and the f ailure to preclude the simultaneous performance of testing which initiates isolation sign 81s to the system under test has the potential to mask the failure of the channel under test.
In addition, the MSTs were not written to support independent performance of each of the MST sections.
j During the observation of testing activities, the team identified that the labeling of control room back panels was inconsistent and difficult to use.
Discussions with the responsible licensee personnel indicated that the method for upgrading plant labeling had significant weaknesses in scope and implementation. Operating Instruction 01-52, provided a method for the resolution of plant labeling deficiencies.
However, this procedure did not direct or require the ide. notification of plant labeling deficiencies.
The team also identified that the personnel responsible for the labeling program assumed l
that all station personnel were required to identify labeling deficiencies in accordance with 01-52.
However, the team observed that the maintenance unit technicians ignored labeling deficiencies during the performance of MST RWCU22M. The technicians, foreman and supervisors did not routinely identify labeling deficiencies and were unaware of a requirement, need or desire to identify these deficiencies.
1 58
l The licensee had developed programmatic requirements for (1) the evaluation of plant labeling during the technical evaluation of procedures changes, and (2) the prevention of valve tagging without accurate valve identification.
l However, the organization responsible for the labeling program was understaffed and a systematic and comprehensive program for the identification, evaluation, and prioritization of plant labeling deficiencies had not been developed.
The failure of the maintenance unit to routinely identify plant labeling deficiencies was indicative of a le'k of communication between organizational units and a willingness to live with problems.
The lack of a site requirement to identify labeling deficiaviv anu the lack of a systematic approach to the review of the adequacy of. plant labels' was indicative of a narrow and ineffective corrective action program.
3.4.3 Nontechnical Specification Testing 3.4.3.1 Preventative Maintenance Vibration Testing The team reviewed the licensee's rotating equipment Vibration Monitoring Program (VMP) and found that it included many strengths.
Even though the program was still under development, it was mere advanced than the TS required ASME Section XI vibration testing program.
The VMP was administered by the Maintenance Engineering group within the Technical Support Unit.
The program's purpose was to obtain long, trouble-free service from vital plant equipment and promote efficient plant operation by detecting deterioration of rotating equipment and effecting repairs prior to the occurrence of equipment failure.
To carry out ichis purpose, the VMP called for the taking of baseline data and periodic vibration checks, with trending and analysis of results.
Upon including a component in the program, the component's work history was reviewed, along with its operating characteristics that could affect vibration signature, such as bearirg types; coupling type; motor horsepower, voltage, and amperage; and impeller or fan type including the number of vanes or blades.
Vibration displacement and velocity were routinely measured under the program, and acceleration and spike energy measurements were taken on an as-needed basis.
All accessible bearings on each equipment in the program were required to be monitored in three axes at permanently marked data acquisition points.
Guidance was provided in the program for evaluating periodic vibration test results against the previously established baseline data, with criteria for when to perform additional vibration testing and analysis as an adverse vibration trend developed.
The program also required that supervisors be informed in writing when adverse trends were detected.
Technicians were given formal training in the use of the vibration monitoring equipment by the equipment manufacturer prior to being assigned to collect vibration data, and were supervised in tne field by the Predictive Maintenance Engineer during their first field use of the equipment. The team viewed the above provisions of the VMP as strengths.
Components were chosen for inclusion in the VMP primarily based on their importance to availability of the nuclear units for power generation, and many safety-related rotating equipments were excluded.
For example, the RHR, core spray, HPCI, and RCIC pumps were not included in the VMP.
These pumps received vibration monitoring under the ASME Section XI IST program (see Section 3.4.1.2.2), but Section XI requirements are minimal, specifying only that i
59 l
vibration measurements be taken at the pump bearing, and only in one axis.
In addition, the training given to technicians who took VMP data was better than
'that given to the A0s who took IST vibration data.
As a result, equipment in the VMP was receiving much more thorough periodic vibration monitoring than some important safety-related equipment covered only by the IST program.
The conventional and nuclear SW pumps, which had a long history of vibration problems, were included in both the VMP and the IST program.
Investigations by contractor and CP&L personnel beginning in 1984 showed that the physical configuration of the pump and motor inctall tion resulted in a resonant frequency very close to the pump running speed, citat the vibration readings taken on one SW pump were affected by the number and combination of other pumps running in the SW building due to the transmission of resonant and/or harmonic frequencies (crosstalk) through the building floor, and that pump vibration measurements were also affected by the level of the tide due to variable damping of pump shaft vibration. To resolve the resonance problem, a modification was prepared to install spring plates between the pumps and motors.
This modification was expected to be installed in the summer of 1989.
The VMP procedure governing SW pump vibration monitoring, OPDM-FMP502, Revision 0, was approved in March 1989 and required that vibration data be taken within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of low tide and that the combination of pumps running in the SW building during data gathering be recorded.
In this way variations due to tide level could be reduced and higher confidence be attained that the trend of successive vibration tests was valid.
Similarly, the influence of crosstalk between pumps on pump performance trends could be reduced by comparing tests in which the combination of running pumps was the same (note, however, that the procedure did not go so far as to call for changing pump lineups solely for testing purposes).
The team regarded the above actions to resolve known problems and to improve the repeatability and validity of vibration testing as strengths in the VMP.
However, no similar effort to reduce variations due to tide level and pump combination had been made in the IST program.
Although the VMP contained many strong provisions, there was poor coordination within the Technical Support Unit to transfer the good practices of the VMP into the IST program.
The requirements of Section XI were being met, but the licensee was neglecting an opportunity to obtain more meaningful predictive i
testing data on safety-related equipment by not better coordinating IST and VMP vibration monitoring.
Such coordination could raise the sophistication of IST vibration testing to the standard set by the VMP, and result in more efficient
)
use of manpower and testing equipment.
The team concluded that the failure to integrate VMP and IST vibration monitoring activities was indicative of poor coordination within the Technical Support Unit (see also Section 3.6.1.2).
3.4.3.2 Post-Maintenance Testing l
The team concluded that weaknesses existed in the maintenance work planning and I
l performance processes that failed to ensure adequate post-maintenance testing l
(PMT) on safety-related equipment.
The team reviewed PMT at Brunswick and identified several instances in which safety-related equipment received significant maintenance, but did not subsequently receive appropriate PMT as required by ASME Section XI.
NCRs 5-88-043 and S-89-038 gave four specific l
examples in which safety-related valves were disassembled and rebuilt, I
replaced, or had limited switches on the motor actuator adjusted without follow-on testing to verify satisfactory valve performance.
In one case, the governing WR/JO required no PMT, and in another, the PMT requirements were not I
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adequate.
In addition, resolution of the testing deficiencies identified in NCR S-88-04? was ex:essively slow.
This NCR was initiated in August 1988 because check valve 25W-V202 was replace under WR/JO 87-AYWC1 and had been
' returned to service without proper PMT.
The initial estimated date given for resolution of the NCR was November 15, 1988.- However, two extensions of the completion date were made with the second completion date delayed to July.1, 1989.
3.5 Quality Programs and Administrative Controls Affecting Quality The team reviewed the Quality Assurance (QA) organization and its effectiveness including staffing, scope of responsibilities, programs and their implementation to evaluate QA effectiveness with respect to specific activities associated with plant operations.
This review included the licensee's organization and programs for QA auditing and surveillance activities.
The team reviewed the licensee's administrative controls affecting quality, problem identification processes and the Nonconformance Report (NCR) pre ess, including root cause and corrective action determinations.
The team alst reviewed the activities of safety review committeas including the Plant Nuclear Safety Committee (PNSC), Onsite Nuclear Safety'(ONS), and Corporate Nuclear Safety (CNS).
.3.5.1 Quality Assurance Organization The team concluded that staffing of the Brunswick Quality Assurance / quality Control (QA/QC) organization was a strength.
A fair amount of stability existed within the three site QA/QC subunits with the three supervisors each having been in their current position a minimum of 6 years.
In general, personnel assigned to QA/QC had good background experience and technical skills.
Transfer of personnel between the QA Surveillance and Quality Control (QC) subunits was well established to provide cross-training within the QA/QC organization.
In addition, a position was established in June 1988 within the QA Surveillance subunit for a licensed reactor operator as a 12-18 month rotational assignment, providing the QA staff with an individual experienced in plant operations.
The position was subsequently filled by a Senior Reactor Operator.
The site QA/QC unit at Brunswick was headed by the Director, Brunswick QA/QC, who reported to the Manager, Operations QA/QC at the Corporate office.
Reporting to the Director, Brunswick QA/QC were the QA Surveillance Supervisor, the Principal QA Engineer, and the QC Supervisor.
The site QA/QC organization t
consisted of approximately 54 personnel.
The site QA Surveillance subunit consisted of two groups. One was a program group which evaluated the adequacy of site programs. The other was a field group, which directed a significant effort toward performance-based review techniqces while evaluating the adequacy of the implementation of site programs.
Joint Operations Surveillance were initiated in 1988, consisting of members from the QA surveillance staffs of the three CP&L nuclear sites who conducted operations surveillance at each of the three CP&L nuclear sites.
l These activities provided members of the QA staff from each site with the opportunity to evaluate the activities of other CP&L sites. Recent surveillance i
activities conducted at Brunswick were reviewed by the team and appeared to be i
appropriate, based on current issues from industry advisories and issues
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identified at other CP&L nuclear sites, o
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The QA Engineering subunit' conducted surveillance associated with safety-related design activities such as design changes, plant modifications and engineering evaluation reports. -QA Engineering was also involved in review activities of safety-related purchase requisitions and evaluations to resolve safety related procurement issues.
The assignment of cause codes for the purpose of trending NCRs was also the responsibility of QA Engineering.
While i
the performance of this subunit was not reviewed during the evaluation, the numerous findings involving Engineering Weaknesses discussed in Section 3.6 indicate that this is a potential area of weakness.
I The QC subunit provided around-the-clock QC inspection coverage for applicable 1
Brunswick maintenance, operation, and modification activities.
The QC staff consisted of approximately 30 personnel which were supplemented by the use of contractors during major plant outages.
The QC staff also performed receipt inspections for safety-related procurement items.
The Corporate Quality Assurance Department (CQAD) was_ headed by the Manager, Corporate Quality Assurance who reported to the Executive Vice President, Power Supply.
Reporting to'the Manager, CQAD were the Manager, Operations QA/QC; Manager, Quality Assurance Services; Manager, Materials Quality; and Manager, Quality Check and Administration.
The corporate QA staff conducted audits, while site QA/QC staff conducted surveillance.
Audits required by Brunswick TS were performed by the corporate QA Services Section.
This section also compiled the Brunswick audit deficiency reports and nonconformance reports into Quarterly Nonconformance Trend Reports.
Oversight of Brunswick QA Surveillance and QC activities was provided by the Manager, Operations QA/QC.
3.5.2 Corrective Action Program 3.5.2.1 Deficiency Identification and Processing The team evaluated the Corrective Action Program through individual interviews, document reviews, and a group discussion with managers and supervisors.
The
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Corrective Action Program was comprised of three parts.
The first involved
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deficiency identification and their processing to determine which were significant.
The second involved those deficiencies which are trended formally I'
and those that were determined not to be significant.
The third part involved determination of the root cause of the deficiency and implementation of corrective action to prevent recurrence.
This section discusses the first part of this program.
The second and third parts of the program are discussed in I
subsequent sections.
The team found that the deficiency identification process
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was not effective due, in part, to a high threshold for items to te considered as "significant" and the perception of some employees that identification of conditions adverse to quality would result in adverse personnel appraisals / actions.
t Historically, NCRs and field reports were used to identify significant and nonsignificant nonconformances.
Beginning in 1983, nonconformance reports could be used as an indicator of an individual's performance and reflected in their performance appraisal.
Interviews indicated that, in the past, reporting f.
problems or deficiencies within the Operations unit resulted in punitive action
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against individuals, a lack of trust for management among the operators, and a j
decrease in the number of NCR's being written.
Today senior plant managers encourage self-identification of problems.
However, the policy of using NCRs as a performance indicator in individual performance appraisals remained in j
62 t
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4 effect until February 1989.
To avoid perceived adverse impact, separate organizational unit problem identification programs were used as an alternative to NCRs by managers and supervisors to circumvent the NCR process (see Section 3.2.2.4).
The licensee identified several deficiencies regarding various aspects of unit corrective action programs documented in NCRs, 5-87-042, S-87-049, S-87-052, and S-87-057.
To address these corcerns, the licensee initiated an assessment in the latter part of 1987 of the Brunswick Corrective Action Program by reviewing the various organization unit problem identification proced.res.
Generic deficiencies identified by the CP&L assessment included (1) inadequacies in programmatic requirements for determining whether or not an off-normal condition is "significant," (2) lack of or ineffective trending programs, (3) no requirements for assessing the effectiveness of corrective actions to preclude recurrence subsequent to implementation, and (4) inconsistent or absent root cause determination methodologies. As a result of this assessment, a task force was established to resolve the deficiencies identified.
A plant procedure, Corrective Action Program, PLP-04, was developed and issued in November 1989 in response to the assessment.
This procedure provided overall guidance for the Brunswick Corrective Action Program and formalized the NCR process as a site wide corrective action process for significant conditions adverse to quality.
However, problem identification processes remained within the various unit procedures.
PLP-04 states that all Brunswick personnel are responsible for reporting adverse conditions to their supervisors.
However, management and supervisory personnel were responsible for determining which items were adverse conditions.
If an adverse condition was determined to be a "significant condition adverse to quality" (SCATQ), management personnel were responsible for initiating appropriate action, including root cause analysis.
The CP&L Corporate Quality Assurance Program defined the terms "significant conditions adverse to quality" and " conditions adverse to quality," and these terms met regulatory requirements addressing nonconforming conditions for purposes of trending and corrective action to prevent reoccurrence.
The practical result was that the threshold of SCATQ was high.
Implementation of organizational unit interpretations of PLP-04 and a high threshold for items to be defined as SCATQs resulted in little information being entered into the NCR process.
On i
the average, approximately 15 NCRs were generated each month at the Brunswick
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site.
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In addition, significant adverse conditions (other than those documented in l
NCRs) were documented and processed by different methods, such as Licensee l
Event Reports (LERs), Special Reports or Safeguards Event Reports, Corporate j
Quality Audit Deficiency Reports, responses to NRC Inspection Reports (IERs),
or other significant conditions not fitting the previous categories which are reported with a Plant Incident Report (IR). Significant adverse conditions i
documented and processed by these methods were not included in an integrated program for assessment or trending.
I The corrective action program also did not adequately identify and trend items which were determined not to be significant.
For example, items such as repeat i
failures or other precursor events which were potentially significant but determined not to be "significant conditions adverse to quality" were not -
identified or trended in the Corrective Action Program as discussed in PLP 04.
If an adverse condition was determined not to be "significant," the item would 63 i
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be processed in accordance with organizational unit procedures.
The process of resolving issues could involve multiple unit procedures, resulting in inconsistencies with regard to the priority of an issue, including ownership or responsibility for resolution.
3.5.2.2 Nonconformance Trending Program i
The team reviewed the Brunswick nonconformance trending program through I
individual interviews with personnel at the site and corporate offices, observation of activities at a PNSC meeting, and document reviews. The team found the nonconformance trending program to be ineffective due to limited data input into the program and a lack of meaningful analysis of the available information.
There was also a lack of corporate ownership and involvement to assist and guide CP&L nuclear sites in resolving concerns from the trend reports.
Trending of significant nonconformance conditions was the responsibility of the
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Performance Evaluation Unit (PEU) within QA Services Section of corporate QA.
l The data base used for trending consisted of corporate internal QA Audit Deficiency Reports (ADRs) plus NCRs identified at the site.
These deficiencies were documented in the Quality Assurance Records Tracking System.
This data was compiled each quarter by the PEU and broken-down into numbers of deficiencies by cause code, discrepancy code, and unit. The number of deficiencies assigned to a given site organizational unit was compared with the deficiencies assigned in the previous quarter.
Analysis of the data was not performed by PEU.
Each organizational unit reviewed changes noted in the quarterly report and informed corporate QA of any actions taken or planned.
This corporate QA-site relationship was indicative of the overall corporate QA I
attitude concerning site activities. During interviews concerning the responsibilities of corporate QA to guide or provide oversight to Brunswick in resolving issues raised in NCRs, several corporate QA managers indicated it was l
the responsibility of site line management to correct these issues. This also reflected the corporate attitude with respect to oversite of Brunswick activities and discussed in Section 3.1.3.
For items determined not to be SCATQs, trending, if conducted, was accomplished in accordance with individual organizational unit procedures. Trending of these items could be consolidated within a functional area, segregated by plant system or grouped in any other manner considered appropriate for that organizational unit's application.
The result was that adverse conditions were segregated, thereby preventing a. meaningful assessment or trending of these site adverse conditions "as a whole."
The team reviewed the Brunswick Quarterly Nonconformance Trend Reports covering January 1987 through December 1988.
Cause classifications were assigned from one of 11 categories and discrepancy codes were identified for approximately 57 categories which were not considered to be all inclusive, but rather a listing of the most likely nonconformance occurrences.
Graphs were prepared covering the number of ADRs and NCRs by cause category for the lart four quarters of data for the site as a whole.
The summary memorandum forwarded to the site by corporate QA generally limited its discussion to changes in numbers of ADRs and NCRs and from the previous quarter.
The amount of data considered each quarter I
was limited, cause categories were general in nature and a short time span was used for comparing data.
The result was that analysis were not meaningful, nor 64
3
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b were site responses.
NCRs attributed to personnel errors were, in general,
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treated as individual events and no trends were established.
Based on the review of the 1987 and 1988 Annual Reports and the First Quarter 1989 Report to i
L the PNSC covering the five most frequent discrepancies and their causes.
personnel errors were the major cause~for practically all discrepancies identified.
The team concluded that the nonconformance trending program was ineffective to identify and trend discrepancies.
3.5.2.3 Root Cause Analysis / Corrective Action l
With the exception of special teams or task forces formed to investigate specific problems, the formal Brunswick requirements to conduct root cause analyses and take corrective action to preclude recurrence were limited to issues involving SCATQs.
Due to the limited number of issues that are classified as significant, the opportunity to identify root causes of issues on a broader scope was lost.
Poor performance in areas such as high volume of rework, high number of revisions to Engineering Work Requests, and repetitive equipment failures was not identified and corrected.
The team reviewed root cause determinations and corrective actions as documented in NCRs and found the root cause analyses generally were not pursued to a sufficient level of detail to determine the root cause.
As a result, corrective actions taken were ineffective and similar events reoccurred. The personnel errors described in NCRs P-88-008, P-88-015, and P-88-017 are an
. example. Many personnel errors were treated as isolated incidents where the repetitive nature of these events showed that they were not isolated events and the causes for the personnel errors were not determined.
Additionally, corrective actions frequently focused on a justification for the "as fount" condition rather than determining why the nonconformances occurred.
Examples include NCR M-88-014 concerning clamp installations and NCR R-88-002 concerning references to incorrect instructions.
These types of events had generic implications and were indicative of a generally negligent site attitude toward addressing.the real issues causing events.
Training on root cause determination was conducted in March 1989 by the licensee for managers and supervisors.
The team viewed a video tape of one training session and found the training to be an introductory or cursory overview of root cause determination.
Discussion of the various root cause methodologies was presented, but this training by itself was not sufficient to initiate an effective program.
It lacked guidance as to how or when managers and supervisors should implement the various methodology tools and what kind of results should be expected to achieve meaningful root case determinations.
Significant deficiencies in quality program activities were discussed in the NRC confirmatory order issued in December 1982.
Specifically, weaknesses in the program for identifying and correcting problems', insufficient audits and inadequate attention to audit findings were identified as areas requiring improvement.
Since that time, the inability to perform effective root cause determinations has been identified as a continuing weakness at Brunswick as documented in several NRC inspection reports, the CMOT report, and previous SALP reports.
Recent initiatives by the licensee to provide additional guidance for root cause determinations include Brunswick Site Procedure-31,
" Root Cause Analysis Policy," and Regulatory Compliance Instruction (RCI)-6.6, 65
" Site Investigation Process," both issued in January 1989.
Additionally, the team findings discussed in Section 3.6 reflect significant weaknesses in the quality programs related to engineering support.
l As demonstrated by the response to the SW system pump motor failure during the evaluation, the team found that despite issuance of PLP-04, Brunswick managers continued to have divergent views on what constituted a "significant condition adverse to quality." Also, while Brunswick has had a history of a poor corrective action program, the licensee indicated that there were no plans to l
review items previously determined not to be significant, but which were f
currently being addressed by organizational units to evaluate whether or not l
these items should be considered as significant under the recently implemented guidance of PLP-04.
The team concluded that the Corrective Action Program was inadequate due to (1) weaknesses in the problem identification process as a result of an inconsistent and high threshold for determining significance, (2) weaknesses in the trending processes, (3) investigations which often lacked sufficient depth to identify the root causes and major contributing factors, (4) untimely implementation of corrective actions and (5) employee perceptions concerning adverse personnel actions resulting from identification of deficiencies.
Recent initiatives, as discussed above, to correct known program deficiencies have been inef'setive.
Significant management attention was necessary to change attitude, and implement an effective program to identify deficiencies, their root cause and implement effective corrective actions to obtain lasting improvements in equipment reliability and a reduction in personnel errors.
3.5.3 Corporate QA Audits The team reviewed activities associated with QA audiu by interviews with corporate personnel and document reviews of completed audit checklists and audit reports covering the period January 1987 through December 1988.
Audits were conducted by corporate personnel to meet the requirements specified by TS.
Audits of the corrective action and root cause determination activities were limited in scope and depth (i.e. only sampled within selected functional areas).
Any additional audits (special) were performed at the request of site management and covered topics similar or identical to a TS required audit.
Audits were primarily programmatic, focused on document reviews and administrative requirements.
Audit checklists contained some items that were not meaningful due to the manner in which they were conducted such as verification of physical design features (e.g., number of fuel assemblies and controls rods in the core) by i
reference to the Updated Final Safety Analysis Report, and reviewing old information when more recent data should have been reviewed.
Another weakness was the practice of verifying that certain conditions were met by noting that the administrative requirements were in place rather than verifying that actual conditions in fact were met.
The team concluded that the programmatic focus of audits performed by corporate QA were inadequate, focused on document reviews, and were not performance based.
3.5.4 Site QA Surveillcnces The team evaluated onsite QA Surveillance activities at Brunswick through interviews with site personnel and associated document reviews.
The onsite 1
66 l
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surveillance activities were performed by the QA Surveillance subunit.
Surveillance activities were focused on activities which provided meaningful i
information.
Examples include the reinspection of pipe supports as a result of QA Surveillance's reevaluation of Brunswick efforts to meet NRC Bulletin 79-14 (See Sactions 3.1.3 and 3.6.7.2), reassessment of the Brunswick Corrective Action Program in 1987, establishment of procedures / processes for fuse design control, and an ongoing reassessment pertaining to the adequacy of the 10CFR50.59 review process.
The team reviewed the QA surveillance reports covering January 1987 through December 1988.
An increased trend toward performance-based surveillance was evident.
For selected surveillance activities, QA Surveillance was using c J
statistical sampling technique to better allocate the available QA surveillance marpower resources while still achieving a 95 per cent level of confidence regarding the adequacy of conclusions reached.
The licensee based the statistical sampling technique upon a continuous production process as described in " Multi-Level Continuous Sampling Plans" by G. J. Lieberman and H. Soloman, The Annals of Statistics, Vol. 26, 1955, and Military Standard (MILSTD) 1235-B.
The method implemented by the licensee did not meet the requirements of this sampling method.
A number of items necessary to apply this method were not included in the licensee's application of the statistical sampling technique in reviewing completed TS surveillance tests.
Examples were surveillance tests did not have an equal chance of being selected (i.e., QA selected one month of records from a given quarter); the size of the
" production interval" for surveillance tests was not defined; the initial 100 percent sampling frequency under the statistical sampling plan was not performed; the number of surveillance tests reviewed (i.e., 6) did not achieve 95 percent confidence of an error rate less than 5 percent; and the criteria established to determine acceptance / defects, results in reviewing surveillance tests which were outside the sample lot.
The statistical sampling plan received inadequate review by management prior to its implementation.
The team reviewed the operating characteristics curve measuring the performance of the sampling plan with the licensee and the licensee acknowledged that the plan as implemented did not provide an acceptable discriminating ability for error rate.
Further, the statistical sampling plan was inadequately reviewed during corporate QA Audit 0021-88-04 since none of the deficiencies noted above were identified.
Additionally, item III-3 of the BIP specified that QA would perform a 100 percent review of TS surveillance requirements every three years.
This item, imposed by NRC Oroer had not been properly implemented. QA procedures QAP-302,
" Technical Specification Surveillance Program," QAP-303, " Regulation Surveillance," QAP-304, " Regulatory Commitment Surveillance Program," and QAP-305, " Inservice Inspection Surveillance," were developed to satisfy the BIP commitments.
QAP-302 originally verified 100 percent performance of surveillance and was revised to a batch methodology which sampled the performance of each TS surveillance over a 3 year period following an interpretation of the BIP commitment by corporate QA in January 1983.
- However, in a letter to Region II dated October 26, 1987, the licensee modified the scope of the TS surveillance, ASME Section XI in-service inspection 10 CFR 50, Appendix J, and commitment verification reviews.
This revised approach was based upon the statistical sampling technique described above which was not consistent with the NRC order to perform a 100 percent review of TS surveillance requirements every three years.
(Refer to Section 3.4.1.3) s.
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3.5.5 Safety Review Committees The team reviewed the activities of the Brunswick safety review committees by observation of the activities at a PNSC meeting, interviews with members of the PNSC, ONS, as well as associated document reviews.
The Brunswick safety review committees were performing required review functions, except that ONS was not reviewing industry advisories and efforts to reduce personnel errors.
- Also, reviews' by the PNSC of TS Interpretations regarding minimum offsite to onsite electrical circuits and primary containment isolation valves were inadequate.
The team observed the conduct of a monthly PNSC meeting.
All materials presented had been issued to PNSC members for review prior to the meeting.
Little discussion tcok place at the meeting on any issue or presentation. The team reviewed PNSC meeting minutes covering the period January 1987 through December 1988. The PNSC meeting minutes appeared to cover the required review issues. However, the meeting minutes were generally cryptic.
Items reviewed and approved were listed by subject area or specific item numbers with little or ne description atta,ched.
Copies of the meeting minutes were provided to the Vice President, Brunswick Nuclear Project; Manager, Corporate Nuclear Safety; and Director, Nuclear Safety Review. With minimal discussions taking place at the meetings and limited writeup of meeting minutes, the value of the documented PNSC activities was reduced, which was confirmed during interviews.
The team also attended a PNSC meeting which discussed Engineering Evaluation Request (EER) 89-0135.
During the onsite evaluation period, the team identified numerous SW system design and operational concerns (see Section 3.6.3) which were being addressed in the EER.
The main topic of the EER was to assess the questionable capacity for the SW pumps to meet the design basis flow requirements.
The PNSC meeting was orderly, but lacked a formal agenda and included extraneous input from both corporate and site staff.
Questions posed were specific in nature and required specific answers to resolve.
During the meeting, actions were assigned, including required completion dates, requirements for follow-up discussions, and fact gathering.
The ONS requirement to examine NRC issues and industry advisories is specified by TS 6.2.3.1.
However, primary review responsibilities for NRC/ industry advisories were divideo among three different units at Brunswick.
NRC Bulletins were the responsibility of Regulatory Compliance; INPO Significant Operating Experience Reports and NRC Notices and Circulars were the responsibility of ONS; and Nuclear Steam Supply System (NSSS)/ vendor service bulletins were the responsibility of the Technical Support unit.
Since each of these organizational units had a different reporting chain, overall integrated responsibility for NRC/ industry advisories was not maintained.
Corporate j
Nuclear Safety Procedure-1 and Corporate Nuclear Safety Instruction-1 each identified ONS as the responsible organization for implementation of the Operating Experience Program defined in Onsite Nuclear Safety Instruction-1 (ONSI-1).
ONSI-1 specifically stated that documents to be screened by ONS
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included NSSS/ vendor service bulletins.
The team confirmed through interviews that this function was not performed by ONS except when corrective action deviated from the vendor recommendations.
However, the TS unit performed the i
normal review function of NSSS/ vendor service bulletins as discussed in Plant j
Performance Procedure-02.
See Section 3.6.9 for additional details.
1 TS 6.2.3.2 required the ONS to maintain surveillance of facility activities to provide verification that human errors are reduced as much as practical. While
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the team determined that the DNS was involved in many beneficial activities such as PRA studies and safety system functional inspection type reviews, ONS was not performing functions to reduce personnel errors.
Personnel errors'hr.d i
been documented in the PNSC Quarterly and Annual Reports to be the most frequent cause code assigned to nearly all of the most frequently occurring deficiencies. While Brunswick had approximately 22 personnel with some level of Human Performance Evaluation System (HPES) training, the HPES Coordinator position had not been filled.
The licensee had not documented plans or actions on how the site would address personnel errors or utilize the personnel trained in i: PES.
However, PLP-04 stated personnel trained in HPES would normally participate in the investigation of events involving personnel errors that contribute to significant conditions.
HPES trained individuals would be used if a Site Incident Investigation Team was activated (none to date), as indicated by Regulatory Compliance Instruction 6.6, " Site Event Investigation Process," which was developed and approved on January 17, 1989.
3.6 Engineering Design and Technical Support Engineering design and technical support to Brunswick was examined from several different perspectives.
The basic design of the SW system was examined to determine consistency with the FSAR and other design basis documents.
Various modifications made to the SW and other systems were also reviewed to assess the adequacy of the modification process.
A review of Brunswick and corporate engineering was also conducted that included changes taking place within the CP&L engineering organizations and the ongoing development of a Central Design Organization.
3.6.1 Engineering Organizations:
Onsite There were three organizations (units) located onsite which provided engineering support to Brunswick, each reporting to a different manager:
Nuclear Engineering Department (NED), Technical Support (T/S), and Outage Management (0M).
The exact engineering responsibilities of onsite NED, T/S and OM were not yet fully developed by CP&L corporate offices, as evidenced by the lack of detciled documents, interface agreements and site administrative procedures relating to the recent reorganization of engineering functions at the site and corporate level.
The licensee indicated that detailed upper tier documents including numerous site administrative procedures would not be written until late 1989, after the various management and organizational studies were scheduled for completion. Meanwhile, the site engineering organizations were working off "old work" and were beginning to function in their new roles as communicated verbally by CP&L and documented (loosely) in a
" Transition Agreement Between Brunswick Nuclear Project and the Nuclear Engineering Department" memorandum dated March 3, 1989.
These organizations are briefly discussed below.
3.6.1.1 Staffing, Resources and Organization 3.6.1.1.1 Nuclear Engineering Department The onsite NED was recently formed as a step in implementing the central design organization (CDO) in the corporate offices.
The onsite NED unit reported to the manager, NED in the corporate offices.
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The team concluded that the educational background of onsite NED personnel was below the industry average and may have been a contributing cause of the poor
-quality of work produced by NED. The onsite NED organization had approximately-128 personnel of which 97 had a technical function according to personnel position _ descriptions. Of the 97, 31 were CP&L employees and 66 were contractors.
The team reviewed the educational backgrounds of those personnel who had a technical function and determined that only approximately 25 percent of CP&L employees and 40 percent of contracted employees had at least a four year technical degree, The CP&L transstion to a CD0 will significantly reduce the current staff of 128 j
to approximately 10 personnel according to NED corporate staff.
It was anticipated by the team, however, that this reduction in staff would not take place for some time since onsite NED has the responsibility for closing out NRC IE Bulletin 79-14 support questions, which was nct expected to be completed i
until 1992.
i 3.6.1.1.2 Technical Support Unit The T/S unit reported to the Plant General-Manager. The main responsibility of T/S was to act as the first point of contact for all operational, maintenance and surveillance test concerns. The unit had undergone numerous reorganizations within the last two years and its performance continues to suffer from i
instability and morale problems.
During this period, experienced personnel
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were leaving and inexperienced personnel being brought in.
Substantial changes had been made in the role and basic organizational structure of the group within the last few months and the licensee predicted additional changes in the j
near future. Morale problems were the result of such things as the failure of management to set priorities and solve problems at Brunswick and management's decision to phase out the nuclear pay supplement that the unit had enjoyed over
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the years.
l Technical Support consisted of approximately 140 technical personnel of which 22 were contractors.
Fifty percent of the CP&L technical staff had at least a 4 year technical degree, while 75 percent of the contractor staff had at least 4 year technical degrees.
The team considered that T/S staffing was adequate despite the loss of more experienced personnel.
There was some duplication of effort within T/S such as between Maintenance Engineering and the systems engineers and, in some instances, between other organizations, such as 3
Procurement Engineering within T/S and other materials groups outside of T/S.
I Further restructuring of the unit was being evaluated by the ongoing CP&L OA.
3.6.1.1.3 Outage Management The OM unit reported to the Manager, Brunswick Nuclear Project. The engineering responsibilities of the Modification Project section within the OM unit were not well defined.
The OM' unit was created as a result of the 1982 Brunswick Improvement Plan.
The largest section within the OM unit (Modification Projects) provided an engineering function for the site.
According to Brunswick personnel, the OM projects section will be responsible for accomplishing emergency modifications, temporary repairs, writing post modification tests and, in addition, will " field follow" modifications that are currently being worked. The actual responsibilities may vary markedly-from what has been communicated verbally, since the transition agreement between 70
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't Brunswick and corporate relating to the establishment of the CD0 did not delineate what group at the site would be responsible for what, it only mentioned generic responsibilities of the site as a whole.
The Projects Section of OM had approximately 50 personnel of which 44 had a technical function based on position descriptions. Approximately 50% of CP&L I-technical personnel had at least a four year technical degree whereas 31% of their contractors had at least four year degrees. The team concluded that the level of education was marginally adequate for the work being accomplished, I
although the staff size Sas r e than adequate to handle the expected workload.
3.6.1.2 Plant Support and Communications There was a general parception by operations and maintenance staff that an overall lack of support by T/S and NED had existed for sometime.
As a result, a special engineering group had been established within the maintenance department to provide support. As part of a recent T/S reorganization, the maintenance engineering section was relocated to T/S to consolidate engineering support.
However, in reality, it has continued to function as a separate group and was not yet fully integrated into the T/S organization.
Communications between and within the onsite engineering groups were adversely l
affected by the continual changes in personnel and their assignments.
The lack of communications in one instance caused an estimated delay of 14 to 32 days in completion of the Unit 1 reload outage No. 6.
This delay was necessary to complete plant modification (P/M)86-007. The scope of the modification was to l
modify the reactor vessel level instrumentation to satisfy Regulatory Guide (RG) 1.97 commitments. During the installation of a similar modification on Unit No. 2, numerous field revisions were required because of the many interferences encountered during the installation.
It was decided in mid 1988, to limit the scope of the Unit 1 modification to allow field design of the work in the drywell. This was acceptable because the Regulatory Guide 1.97 commitment called for completion during the subsequent reload outage No. 7 for Unit 1.
This information pertaining to reduced work scope had not been communicated to those personnel in engineering responsible for an Appendix R commitment which had taken credit for the new reactor pressure vessel (RPV) level indication, and had referenced it in newly developed operating procedures. The Appendix R commitment required the new RPV indication to be in l
service before Unit I returned to service from the No. 6 reload outage.
This l
discrepancy was discovered during the outage just a few days before the drywell was scheduled to be closed.
3.6.1.2.1 Proactive Engineering Efforts The Brunswick T/S unit had initiated several " betterment" (improvements)
L projects or studies which were reviewed by the team.
Some of the projects or studies were recently implemented while others were still in their infancy.
l Long term benefits from these and future proactive efforts will, in part, be determined by management commitment of both funds and personnel.
Some of the l.
more important "betterments" included the following:
l SW long-range improvement program (continuing through 1995) l o
I o
Feedwater control system replacement o
Improvements in fuse replacement control o
Reduction of contractor dependency within T/S 7'
1
NPRDS failure reporting automation o
o Repetitive failure detection Replacement of the obsolete Honeywell based rod worth minimizer o
Core physics studies for power uprate o
o Direct replacement program for obsolete valves Motor operated valve improvement project o
Pump testing improvement program o
Procurement Engineering organization / work priorities / commercial grade o
l tmgrades/ backlog procurement
'3.6.1.2.2 Engineering Work Requests The corrective action program for resolving engineering problems was controlled by Engineering Procedure ENP-20 entitled " Engineering Work Request" (EWR).
The EWR process is used to request engineering assistance from the T/S unit to evaluate a potential " deficiency" or "betterinent." Suh equent to an NRC quality assessment inspection in 1987, the licensee revised the EWR program and performed a review of the safety significance of the large backlog of l -
undispositioned EWRs (totaling 1879).
T/S established a task force to disposition the EWRs and committed to work off the initial backlog of EWRs (investigation phase complete) by February 12,.1989.
The licensee actually completed the dispositioning ahead of schedule in January 1989.
Once the. initial work of dispositioning the 1879 EWRs was accomplished, a new backlog was created: dispositioned EWRs awaiting corrective action.
Thus the undispositioned EWR " backlog problem" identified in 1987 had been shifted to a dispositioned, but unimplemented EWR backlog problem.
Additionally, many EWRs were closed out on paper by transferring them to another program, the Project Identification (PID) thus moving the backlog of problems awaiting corrective action.
The team reviewed the status of EWRs via weekly, monthly and semiannual EWR reports to determine progress.
Surveillance Report No.88-059 completed in November 1988 indicated that the large backlog of EWRs was being reduced, but that the number of EWRs or PIDs that will require action within f
the next three years had sharply risen.
The team review of the current backlog
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problem is included below.
i Scope of Outstanding Work As af May 1989 there were approximately 560 EWRs that had been dispositioned and were awaiting corrective action.
The large majority were not being worked j
because they were not budgeted and would not be budgeted until 1990.
An additional number of EWRs have been closed out and turned into PIDs and require that specific funding be approved for each project.
Each PID retains the number given to its parent EWR. The team reviewed several open and closed PIDs and noticed that the implementation or completion of actions to close an i
EWR/PID was extremely slow and not well monitored.
Fer example, the "EWR-Project Status in Long Range Plan" printout conflicted with information contained in individual PID packages regarding whether or not a PID was closed or open.
The PID status report also contained project completion dates for j
individual work items within a PID that had been specifically cancelled by the l
PID.
PID forms were also not updated to reflect project status.
Engineering support had not been adequate to resolve one of the maintenance unit's primary concerns; parts availability.
The licensee estimateJ that approximately 50 percent of the open EWRs (dispositioned) were due to material 72
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problems and obsolete parts, yet there was no program at Brunswick to resolve the obsolete parts issue with the exception of direct replacement of small obsolete valves.
Untimely / Inadequate Comoletion of EWRs and PIDs The team found numerous examples of untimely and/or inadequate corrective action associated with EWRs and PIDs and concluded that inadequate engineering support had been provided to the site.
For example:
The Unit 2-5A Feedwater (FW) heater shell pressure transmitter which o
was used to measure equipment performance was out of service for an extended period of ti:ae because of untimely and ittorrect response to an engineering work request.
The transmitter provides local indication and a computer input.
The information was used by system engineering to evaluate the operability of the FW heater.
I ri November 1986, the transmitter was found out of service, and maintenance personnel, unable to find replacement parts or transmitters, wrote EWR 08800 in November 1987.
After a long delay, the EWR was dispositioned by T/S in October 1988, indicatir.g that replacement transmitters were available in the warehouse, when, in fact, they were not available.
A new EWR (07062) was issued December 26, 1988 to again review the problem. The target date for resolving EWR 07062 was August 3, 1989, approximately 2 years.after the original EWR was issued.
o EWR 02019 deals with the condensate drain line valves for the low pressure stop valves on the 1A and 1B reactor feed pump turbines.
The control switches on the balance of plant (B0P) benchboard in the control room were not wired in accordance with plant drawings and were not labeled to reflect as-built conditions in the plant.
EWR 02019 was originated on January 20, 1984, had an engineering review on November 26, 1984 and was closed on April 18, 1986 without resolution because a duplicate EWR (02308) was issued on February 13, 1985.
This new EWR was dispositioned on February 19, 1985 with instructions to " trouble shoot the problem." However, it appeared that no action was taken and, after continued requests from the Operations unit and reidentification of the problem during an INPO audit, the EWR was finally re evaluated in February 1988.
The EWR was closed out on March 21, 1988, when the required work scope was t
identified and made part of P/M 87-187.
The implementation of P/M B7-187 was not scheduled to be worked until October 1991 during the Unit 1, refuel outage No. 8.
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o EWR 01741 was initiated in October 1984 to document that "the fire detection panel in the chlorination building is rusted out and is beyond repair.
This panel is inop and needs to be replaced." The EWR was closed out and transferred to a PID in June 1986 and was scheduled to be worked in 1994.
EWR 6963 was initiated in late 1988 to request that a basic document o
be prepared to justify current valve testing required by the A9'E Section XI inservice testing program.
The study was to incleza 1 review of safety-related systems to document which valves (inckJing check valves) were important to safety, their positions (normal and
)
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_____.___m-2-_
1 safety), their limiting stroke times and leakage values.
This EWR was closed out, turned into a PID and recently canceled due to budget
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constraints.
See also Section 3.4.1.2.
3.6.2 Engineering Organizations:
Corporate 3.6.2.1 Corporate Staffing, Resouren and Organization The team interviewed both supervisory w nonsupervisory corporate NED i
personnel, to determine how the current. engineering orcini.rion accomplished work and the extent of any proposed reorganization to fully adopt the C00 concept.
3.6.2.1.1 Huclear Engineering Department NED personnel were technically competent, with an adequate amount of nuclear and professional experience.. Corporate Management determined in 1986 that NED could become more effi,cient and effective by restructuring and eliminating duplication of effort at each site and within itself to develop.NED as a CD0 for all.CP&L nuclear sites.
NED had recently reorganized some sections and indicated that an additional reorganization would take place late in 1989 to implement recommendations made by.the various ongoing management studies.
'As the CD0 concept becomes a working reality, addit.ional staffing and organizational changes will be required to meet individual site (e.g. Harris, Robinson, Brunswick) needs.
This will have both positive (perceived increased efficiency) and negative (perceived continued organizational instability) effects.
The NED (corporate office) staffing level had remained fairly constant within the last year at approximately 310, despite a recent reorganization which eliminated some sections, realigned others, and eliminated some technical assistant / administrative personnel.
The turnover rate for corporate NED was higher than expected for 1988, at about 10 percent.
Of the approximate 18C CP&L personnel having technical functions, over 60 percent had at least a 4 year technical degree and 47 were registered professional engineers.
Corporate.NED was somewhat dependent upon full time contractor personnel with almost one-third of the staff being contractors.
Engineering organizations located at Brunswick and at corportate offices were attempting to minimize the use of long term contractors to become more cost effective, wlile at the same time, trying to retain the knowledge and experience within CP&L.
The team viewed this action as a benefit to both corporate and site engineering organizations.
3.6.2.2 Plant Support and Communications NED maintained a staff of approximately 130 personnel at the Brunswick site who worked mainly on special projects, such as the ongoing IE Bulletin 79-14 closeout.
The licensee intends the onsite NED plant support staff to be drastically reduced in size (to approximately 10) and function as a liaison for NED personnel located in the corporate office.
Given the plans to reduce tne NED plant support staff to 10, a significant change in corporate / site communications will be needed.
The team was favorably impressed, however, with the onsite presence of the corporate Brunswick NED project manager, who spent three to four days a week at the site, attending scheduled plant meetings and interfacing with plant 74
l l
4 personnel to learn first hand of plant operating problems or equipment problems I
l which may require NED input or action to resolve and expedite their resolution.
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This ection indicated a strong determination by corporate NED to better communicate with site organizations.
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3.6.2.2.1 Central Design Organization Development The team concluded that the engineering transition (to a CD0) was poorly planned and implemented with regard to the Brunswick plant. The orocess had been time consuming, was still being refined and was expected to 7ne' Je to change as various management studies and assessments were finalized.
The transition back to a CD0 including transfer of design authority was formalized in 1986 and was essentially complete by March 1989. A transition agreement between Brunswick and corporate NED was not formally written until March 1989 and failed to include any milestones for impi oentation.
CP&L determined that the existing contingent of on-site engineering / design personnel would not be needed past the end of the 1988 Unit 1 refueling outage and that NED would function as a CD0 for Harris, Robinson and the Brunswick nuclear plants.
The downsizing and restructuring of the Brunswick design engineering function began during the early part of 1988.
The Brunswick Engineering Support Unit in the Engineering and Construction Unit, which had performed the majority 9f plant modifications began turnover of their responsibilities to the NED ars was eventually phased out.
As of March 1989, the final transfer of the Brunswick I
design function to NED was complete.
Other organizations located at the Brunswick which had provided some form of engineering support to the plant had also been reorganized.
Maintenance Support Engineers, previously within the maintenance organization, had been transferred to T/S; the Engineering and Construction group had been " demobilized" with its personnel and/or functions transferred to Outage Management, T/5, and the NED.
Under the CD0 concept, engineering support would continue to be divided amongst various groups, however, individual functions were expected to be more discrete.
Very little documentation was available which described how the CD0 concept would be implemented, including the extent of corporate communication with each nuclear site.
Consequently, the team asked the licensee to provide a briefing to explain the CDO.
The following is a partial quote from a presentation given the team members on April 21, 1989 concerning the CD0 concept and CP&L commitments.
"NED is a discipline oriented "A/E" type organization responsible to the nuclear project managers for design proposals, plans and modification packages.
As the central design organization (CDO), NED is an organization that performs a full range of design work... NED is n"t a replacement for plant [T/S]... NED does not routinely do maintenance engineering, operations engineering, system engineering, reactor engineering or performance engineering.
The cesign engineers of NED are l
not replacements for nor are they duplicates of the system engineers in plant [T/5].
In fact, it is intended that the NED design engineers and
[T/5] system engineers work closely to assure that the design and subsequent operation of modifications to a system are optimal...
The nuclear engineering projects section supports the design sections and provides a critical management interface to ensure early coordination and I
problem resolution between the site and NED...
A site focus needs to be on operations, maintenance and safety, not design activities."
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The licensee recognized that there were both benefits and potential drawbacks to the CD0 concept.
Despite the potential drawbacks of the reorganization, the team concluded that once fully and adequately implemented, the resultant engineering product should be an improvement over the fragmented and weak engineering support previously provided the Brunswick site.
3.6.3 Design Evaluation of the Nuclear Service Water System A limited design review was conducted of the SW system to assess its operational readiness.
The service water system provides cooling water to safety-related and non safety-related heat loads in the Turbine, Reactor, and Diesel Generator Buildings.
The system is divided into a nuclear header and a conventional header.
The two headers are normally operated independently.
Five vertical draft pumps supply the s.vstet and all are powered from vital electrical buses.
Two pumps are aligi.ed to the nuclear header and the
{
remaining three pumps normally supply the conventional header but may also be i
aligned to the nuclear header. The nuclaar header provides cooling water to the emergency diesels, the SW pump lubricating water subsystem, RHR SW pumps, vital equipment (vital loop) including RHR and core spray pump room coolers, and nonsafety-related reactor building component cooling water heat exchangers.
The conventional header provides cooling to the turbine building closed cooling we.ter heat exchangers, bearing lubrication to the circulating water intake pumps, and the chlorination system.
Cross-connect valves allow the conventional header to supply the safety-related equipment in the nuclear header.
3.6.3.1 Service Water Operational Concerns To assess the adequacy of the service water system flow capacity and distribution, the team requested that creies of preoperational/startup testing documentation be provided for review.
ine licensee indicated that such documentation could not be located, and was uncertain whether tae testing was ever accomplished.
The licensee also indicated that subsequent similar flow verification testing (e.g., post-modification testing following SW pump and pipe replacement / modification) had not been performed even though substantial modifications to the SW system had taken place since startup.
The team identified a number of design and operational weaknesses that collectively challenged the operational readiness of the nuclear SW system, many of which were similar to the deficiencies in the HPCI system identified during CP&L's 1987 self-assessment.
These deficiencies, in combination with deficiencies involving design basis information (see Sections 3.6.5.1 and 3.6.5.4), raise questions about the reliability and operability of safety and nonsafety equipment under credible off-normal conditions.
Weaknesses associated with the nuclear SW system are discussed in subsequent sections and include:
1.
The vulnerability of the nuclear header to a single failure preventing the isolation of the nonsafety-related reactor t,uilding closed cooling water (RBCCW) heat exchangers, 2.
The lack of periodic testing to assess nuclear header leakage through normally closed isolation valves to a depressurized conventional header, 76
3.
Modification of SW restricting orifices and isolation valve actuators to the RHR room coolers thus causing a flow deficiency following a loss of offsite power, 4.
Modification of the vital loop's keep fill system thereby providing an uncontrolled flow path between the nuclear and conventional headers, 5.
Raising the SW pump motor stator temperature alarms and operating the SW pumps at the higher stator temperature without assessing the consequences of higher temperatures on accelerated aging of motor insulation, and 6.
Potential water hammer of the RHR SW loop keep fill system.
Durir.g the evaluation and in response to the first four concerns identified above, the licensee performed special tests, developed a system hydraulic model, and performed a failure mode and effect analysis and heat transfer calculations.
Thp' investigations concluded that the emergency core cooling system heat exchangers and cooling loads could not be supplied with required design flows, under the worst case accident scenario which included a LOCA, a Loss of Offsite Power (LOOP), the demand for cooling of four diesel generators from one unit's nuclear header, and a fcilure of an emergency bus. In addition to the assumed accident scenario, the licensee's investigation included a best estimate for nuclear to conventional SW header cross-leakage of 1900 gpm.
Based upon the team's findings, the licensee implemented interim compensatory actions (justification for continued operation) for all modes of cperation, designed to ensure that the service water system could perform its intended safety-related function as described in the FSAR.
Short and long-term actions included (1) Limiting the RBCCW SW flow to 4500 gpm, (2) Developing a final report on SW System capabilities for providing design bases flows, (3) Revising the current TS Interpretation, TSI 86-04, for TS 3/4.7.2, (4) Assessing the failure mechanism of 28 nuclear SW pump motor, (5) Testing the Unit 1 SW system to evaluate its cross-tie leakage, (6) Providing FSAR changes in concert with final report on service water system capability, (7) Consider decreasing diesel generator jacket water flow to increase available flow to RHR heat exchanger, (8) Limiting the operation of plant to SW water inlet temperature to 78 F, (9) Reviewing the containment accident analysis and related torus issues to determine RHR heat exchange heat removal cargin, and (10) Performing a design review of canal level versus tidal elevations and flow demand to assess the impact on NPSH requirements.
Lased on coordination between the team and USNRC Region II and NRR (licensing),
Region II and NRR closely followed the above items and will assess corrective action as it is completed.
The following is a brief description of each concern identified above.
3.6.3.1.1 Single Failure Vulnerability Although the FSAR states that the service water system was designed to withstand the effects of a single active or passive failure, the system was not protected from a single failure involving the power supply to service water isolation valve SW-V106. This valve is a normally open boundary valve between the safety-related portion of the nuclear service water header and the nonsafety-related RBCCW heat exchangers.
The failure of tnis valve to close 77
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under some. accident scenarios causes SW flow d'stribution problems to j
safety-related heat loads and' creates _ runout conditions for the operable NSW pump.
For example, the failure of the E3 bus following a LOCA concurrent witn
- t. LOOP causes nuclear SW pump 2A not to operate and valve 25W-V106 not to automatically close to isolate the nonsafety-related RBCCW heat exchangers (i.e. motor control center (MCC) 2XA that powers the motor-operated vane is powered from unit substation E7).
If nuclear SW pump 2A was selected as one of
. two operating nuclear SW pumps (only_ two required per TS), then one nuclear SW pump would attempt to supply all safety-related cooling loads including four emergency diesels and the RBCCW heat exchangers.
3.6.3.1.2 SW Leakage Across Safety-Related Boundaries Periodic testing such as surveillance testing had not been performed to confirm acceptable leakage between the nuclear and conventional headers. The failure to account for leakage from the. safety-related system to nonsafety-related portions of the system can result in additional undetected flow demands upon l
the nuclear SW system during accident conditions.
During the evaluation, the licensee performed preliminary leakage rate testing on Unit 2 and identified a potential leakage rate of approximately 1900 gpm under worst case conditions between the nuclear SW and conventional headers.
-This flow rate was significant and represented approximately 20 percent of the nuclear service water pump flow capacity.
Crossconnects were installed and allowed the conventional header to provide service water flow to nuclear (safety-related) heat loads.
Normally these boundary valves are shut.
However, leakage across the normally closed boundary valves from the nuclear header to a depressurized conventional header is a potential source for losing " limited" nuclear service water flow (i.e.,
inadequate nuclear service water pump capacity).
1 The following are examples of other potential leak paths.
1.
Conventional SW pumps can be crossconnected to the nuclear header through normally closed 20 inch butterfly valves SW-V14, SW-V16, and SW-V18.
Butterfly valves are normally not the type of valve used to assure leak tightness and CP&L has previously had experience with excessive leakage past these valves.
Work request WR/JO 88-BDRM 1 dated November 15, 1988, identified leakage past Unit 2 discharge valve SW-V14.
This valve was originally replaced in November 1985 under WR/JO 85-ADSR1.
Likewise, work request WR/JO 88-BDRN1 dated November 15, 1988, identified leakage past Unit 2 discharge valve SW-V16.
2.
ihe supply header for lubricating water pumps receives water from either the nuclear or conventional SW headers through normally open manual valves and check valves. The check valves are provided to prevent flow from being diverted from one header to another as the header pressures vary.
{
During an accident, the system relies upon check valve SW-V200 to shut and act as a boundary between the pressurized nuclear header and a potentially depressurized conventional header.
Leakage or failure of this valve can divert flow from safety-related heat loads.
The check valves in the 4-inch supply lines were not reverse flow tested to verify leak tightness although the SW-200 valve was disassembled to confirm that a disk was installed and that it moved freely.
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3.
Nutlear SW flow was also used to provide cooling water to the RBCCW heat exchangers through normally open butterfly valve SW-V106.
Following a LOCA and a LOOP the valve receives a signal to shut.
Leakage across this boundary valve when closed, is another potential source of leakage.
The SW-V106 was not leak tested as part of the ASME Section XI program and may also fail open under certain accident conditions explained in Section i
3.6.3.1.1.
3.6.3.1.3 Increased RHR Pump Room Cooler Flow Demand i
Mechanical flow calculations were not performed during development of RHR room f
cooler modifications P/M 82-219W and P/M 82-219Y even though flow demand was J
altered by changes to the failure position of the cooler discharge valve.
These modifications replaced the cooling water ceils in the RHR pump coolers 1A and 1B, respectively.
Two changes incorporated by the modifications placed additional burdens on the flow capability of one nuclear SW pump:
(1) replacement of the actuator on the discharge valve such that the valve fails open on loss of actuator motive power (air), and (2) resized and replaced pressure reducing orifice to correct for an original design capacity error (i.e. increase flow from 150 gpm/ cooler to 300 gpm/ cooler).
Following a LOCA concomitant with a LOOP, the original design assumed only one RHR cooler was required (i.e., each cooler has 100% capacity and they are sequenced such that one is loaded at 125*F and the other at 145 F).
Consequently, the licensee assumed the flow demand to be 300 gpm in FSAR Table 9.2.11.
Because the failure mode was changed both RHR cooler discharge valves will open on loss of r
instrument air creating an actual flow demand of 600 gpm.
3.6.3.1.4 Modification of Vital Header Keep Fill System Under certain plant conditions, nuclear SW flow is diverted from the vital service water header back through a normally open bypass valve.
Check valves were not installed to prohibit this flow and the licensee failed to calculate the water diverted from safety-related heat loads when the modification to the keep fill system was performed.
The vital cooling water loads (RHR pump room coolers, RHR pump seal coolers, core spray pump room coolers) are supplied through SW-V117 and SW-V118 from the nuclear SW pumps.
SW-V118 is a normally open crossconnect between vital loop A and B, while SW-V117 is normally closed.
Following a LOCA, SW-V117 opens.
The vital loads can also be supplied from the conventional header through normally closed isolation valve SW-Vill.
Both SW-V117 and SW-Vill have normally open 3/4 inch bypass valves such that the vital loops can be kept filled.
Following
)
a LOCA and concomitant loss of offsite power, some nuclear SW flow will be diverted to the depressurized conventional header through the normally open bypass valve around SW-V111.
The team was informed that these lines were installed by an old plant modification and that no analysis existed to demonstrate how much flow would be diverted from safety-related heat loads (see also Section 3.3.4).
3.6.3.1.5 Service Water Pump Motor Stator Temperature Alarms All SW motor stator temperature alarms were raised (erroneously) almost 40'F to eliminate the alarms caused by high operating temperatures.
Some of the mbtors had been rewound with a higher rated insulation and were capable of withstanding the higher running temperatures, while others were not.
This s.
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alarm setpoint change was accomplished without a modification package (i.e., no formal design review and no safety evaluation).
Subsequently, the licensee
' determined that the alarm setpoint change should not have been made and lowered the setpoint to its original design value.
This action was also performed without a modification package and there was no assessment of motor degradation caused during the periods of time when the motors were operated at elevated temperatures.
By the end of the ev41uatio7 period, the licensee established a group to study the cause of the high motor temperatures and was considering various modifications to resolve the issN (see also Section 3.3.4).
3.6.3.1.6 Potential Water Hammer The RHR service water loop A was normally supplied from the conventional header through supply isolation valve SW-V101 and loop B was normally supplied from the nuclear header through supply isolation valve SW-V105.
The two headers were isolated from each other by normally closed crossconnect valve SW-V102.
The RHR service water loops A and B were kept filled by normally open well water supply valve SW V143 through branch lines connected on opposite sides of valve SW-V102.
A check valve in each branch line served as the safety-related boundary. The well water supply valve (SW-V143) was interlocked with valves SW-V101 and SW-V105 such that if either of these valves were shut, SW-V143 will also shut.
During torus cooling mode of RHR, one of the RHR service water loops is used to remove heat from an RHR heat exchanger. In that mode of operation, either SW-V101 or SW-V105 are open.
Because of a valve interlock, well water supply valve SW-V143 will shut automatically and the valve is checked shut per the operating procedure for service water.
With the well water supply shut, the keep fill system for the idle RHR SW loop has no source of supply water (i.e.,
SW-143 is common valve supplying keep fill water to redundant RHR SW loops).
While valve SW-V143 is shut the loop may drain to a level consistent with the elevation of the discharge flow control valve.
If a LOCA were to occur after being in torus cooling for a period of time, the idle loop could be subjected to waterhammer unless the operator vents and fills the loop before opening either SW-V101 or SW-V105.
3.6.3.2 Incomplete and Inadequate Engineering Analysis of Service Water Flow During the review of the operational readiness of the service water system, a number of modifications, engineering analyses and safety evaluations were examined. Modifications to improve the corrosion and biofouling resistance of the SW system were found to be a strength.
However, operational concerns associated with inadequate flow distribution were considered a significant weakness.
Once the nuclear SW flow distribution issue '.13s identified by the team (see Section 3.6.3.1), the licensee drew upon technical resources from the site and from the corporate NED office to organize a project team.
This project team understood the issue and was able to formulate an analysis plan and then implemented it in a relatively short a period of time.
The ability to address this technical issue once identified by the evaluation team seems to be a dichotomy when compared to Brunswick's failure to recognize the flow distribution weakness over a long period of time.
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The licensee had numerous. opportunities to identify existing nuclear SW flow distribution and capacity inadequacies _yet they remained undetected.
For example:
1.
A May 1988 engine ning analysis of the SW flow distribution was incomplete.
and based, in part, upon design analysis that did not reflect the I
as-installed system configuration.
The results of this analysis was used as the basis for eliminating adm'11strative controls which restricted SW
. unrestricted operation.
CP&L Project Proposal, " Service Water Flow Distribution Verification,"
Project Control Number 06329A, Rev.~1, May 13, 1988 studied an accident scenario that appeared to create a condition that was bayond the des.gn capacity of the SW system, when TS Interpretation (TSI) 84-06 [Rev. 4 January. 21,1988) was applied.
The accident scenario included a single failure.that prevented the closing of RBCCW heat exchanger isolation valve SW-V106 upon demand.
The analysis performed for this CP&L Project Proposal contained the 1
following weaknesses:
The analyzed scenario was not the most limiting.
The licensee o
assumed a simultaneous LOOP and a LOCA followed by a. single failure of the E3 bus (see Section 15.6.4.1 of the updated FSAR).
In the analyzed scenario the loss of the E3 bus causes NSW pump 2A not.to start and_ valve 25W-V106 not to automatically close to isolate the non-safety-related RCBBW heat exchangers.
In the analyzed scenario, only three emergency diesel generators were assumed to require flow (non conservative) instead of four.
In addition, the analyzed scenario assumed zero leakage across closed boundary valves and through open bypass valves, however, periodic testing was not performed to confirm this leakage assumption.
The analysis assumed that the design flow rates listed in FSAR Table o
-9.2.1-1 (SW Flow Distribution) were actual demand flows.
These flows were summed to obtain a service water pump flow without apparent consideration of different flow resistances in parallel branch lines (i.e., higher flows to low resistance paths and low flow to high resistance paths),
The analysis assumed that RHR rw m cooler required flow was 150 o
gpm/ cooler instead of the 300 gpm/ cooler listed in the FSAR tr. ie.
The basis for this assumption was information contained in Hvi/
system description SD-37.1 instead of the service water system description SD-43.
During modification P/M 82-219W and P/M 82-219Y the pressure reducing orifice downstream of the coolers were resized to pass 300 gpm per unit.
Thus the analysis assumption underestimated the RHR room cooler flow by at least 300 gpm.
The analysis compares the summed required flow of 10,070 gpm (short o
at least 300 gpm because of errors associated with RHP. pump room coolers) to the pump characteristic curve for the irstalled SW pDmps and concluded that the pump would develop a total.synamic head of 60 feet.
However, the CP&L analysis failed to note that 10,070 gpm Ws 81
g off the pump curve and did not address the effect of incre'ased flow demand on NPSH required.
At 9000 gpm the SW pump requires a NPSH of 40 feet.
NPSH available was less than 40 feet and the NPSH required at 10,000 gpm would be considerably higher.
.The analysis referred to a United Engineers and Constructors (UE&C) o calculation 9527-8-SW-11-F, Nuclear SW Header - HD.
Loss, Rev. O, March 6, 1972i The CP&L analysis referred to a plot of system resistance curve versus the pump head curve contained in the UE&C andycis as a basis for concluding that the operating point will b less than the design value (i.e., that margin existed to-support a increase in demanded flow).
However, the nuclear SW pump bowls we'e replaced in 1985, and the pump curve changed.
The CP&L qualitative argument did not address the effects of this modification.
Based upon this weak qualitative technical argument, the licensee concluded that during the postulated accident, design flow rates would not exceed the capability of the available nuclear SW pump. As a result, the licensee removed the self-imposed limitation of 5,000 gpm service water flow to the RBCCW heat exchangers invoked by SI-88-014 and rejected other alternatives.such as a modification to provide double isolation valves between the SW and RBCCW systems.
The analysis should have detected the weaknesses in the SW system design; however, it did not.
Since_it was a recent analysis (i.e., May 16,1988),
it suggested a weekness in engineering capabilities, and raised a concern over the organization's inability to recognize and understand operational problems.
This observation was further supported by repeated failed opportunities to recognize the SW system weaknesses. The following are additional examples.
2.
Modification P/M 81-207 and P/M 81-208 replaced the Peerless pump bowls of the nuclear and conventional SW pumps with Johnston bowls.
Review of the modification package inF eated that design analyses performed for these two modifications conten uated on the structural and seismic adequacy of the replacement bowls (i.e., pumps including impellers) since the modification was to seismically upgrade Re pumps.
Documentation of fluid calculations was not included in the modification package nor were such calculations on file.
It appeared that normal concerns associated with pump replacement were not conside;ed such as total discharge head and NPSH calculations. These modification packages were approved on January 24, 1982 and installed during the summer of 1985 and declared operable 11 August of 1985 for Unit 2 and Septe'nber of 1985 for Unit 1.
3.
Modification P/M 82-219W and P/M d2-219Y replaced R!"1 pump room cooler coils and changed th_e flow orifice sizes; however, no fluid hydraulic calculations associated with this modification were performed or referenced.
4 In December 1987, a QA audit report reviewed P/M 82-219Y.
Although the audit did not cite the lack of fluid hydraulic calculations, it did identify the iack of references to sources of design input.
The response to the audit finding should have triggered a search for necessary fluid hydraulic calculations as references, and the lack of such calculations should have alerted the licensee.
The February 8,1988 response to the L
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3 audit finding stated, in part, "The results of the calculation in
... P/M 82-219Y have been reviewed and found to be correct." The audit finding was closed without further action.
5.
In a December 1988, NRC Inspection Report 50-325/88-40 and 50-324/88-40 identified wealnesses with the testing performed to confirm adequacy of modification P/M-82-219W.
The inspection report identified problems with the actual flow compared to the acceptance criterion for EHR room cooler SW flow.
The inspectior, report questioned the reason fc: the inconsistencies and 'he deviation from the approved procedures.
In a letter dated January 20, 1989, licensee responded to the inspection report and stated that "... where flow was recorded above the high li' nit of the criteria the engineers knew that the actual intent was to ensure a minimum flow of 300 gpm and they therefore considered the flow of 455 gpm to be acceptable.
Again, the licensee had an opportunity to recognize that too high a flow may jeopardize flow to other safety-related loads and result in too'little flow to those loads.
3.6.3.3 Design Basis Information Inadequacies During the design review the team noted examples of missing fluid hydraulic calculations or the use of. FSAR and/or system description tables as design input.
In some instances, the licensee appeared to lack an understanding of l
the design basis of the SW system, and the necessity for traceability of design l
input to design output.
This weakness was attributed, in part, by to a ceneral lack of fluid hydraulic design calculations for the SW system.
The lack of these calculations fostered the use of engineering judgement instead of maintaining SW system design flow calculations as "living" documents (i.e.,
updated and maintained as modifications are made').
Based upon the extent of missing calculations in the SW system, it is expected that design flow calculations may not be available to engineers and designers making modifications to other fluid systems.
The following are examples of design basis information inadequacies.
The section number in brackets identifies the section where more detailed information can be obtained.
1.
The consequences of increased RHR pump room cooler flow were not assessed by either reference to an existing flow di.itribution calculation or a new calculation performed (3.6.3.1.3).
2.
A modification to upgrade SW pumps did not include total discharge head (TDH) or NPSH calculations even though the upgraded pumps had different pump characteristics.
The procurement specification d'd not have a vendor requirement to supply a NPSH required curve.
3.
Calculations to resize the RHR pump room cooler service water orifices did not identify the basis for sizing the orifice to pass 300 gpm (3.6.5.2).
Subsequent engineering analysis for verification of service water flow distribution used an incorrect flow rate of 150 gpm from an HVAC system description (3.6.3.2).
4.
Although the design basis low water level (-7.5 feet mean sea level) was stated in FSAR section 2.4.11, no design analyses existed to demonstrate that the SW system would operate at that low water condition.
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interviews the team determined a lack of awareness of this design requirement.
PID G-0050A was generated ta determine the worst case minimum water level in th nump bay to ensure adequate pump NPSH to support the saf(ty function of the NSW system. This analysis was not completed by the close of the evaluation.
5.
A CP&L engineering analysis used design input from the FSAR as a basis for assessing the consequences of a single failure of SW valve SW-V106 to close upon demand (3.6.3.2).
3.6.4 Design Change Process The team reviewed the design change process and found a program that was rcill inadequate, due in part to the transition of CP&L to the CD0 concept.
M.ny modifications were being worked to the Brunswick modification procedure, while others were being werked to the new corporate modification procedure.
Both procedures had significant shor*
omings due mainly to the infancy of the corporate procedur0 and the ongoing changes being made to the responsibilities of onsite and offsite engineering groups.
For example, the Brunswick Plant modification procedure ENP-03, Rev. 39 refers action to groups which no longer exist or whose functions have changed.
Until the CD0 is fully implemented and all pertinent procedures are coordinated, confusion will continue to exist.
Until January 1989, the design change process at Brunswick was controlled by Engineering Procedure ENP-03, " Plant Modification Procedure." After January 1989, all new modifications were to be accomplished by the corporate NED procedure NED-IA-003, " Nuclear Plant Modification Program." The purpose of the new procedure was to establish a uniform modification program for use at H.B.
Robinson, Shearon Harris and Brunswick Nuclear Power plants. The Team reviewed both modification procedures and determined the following:
1.
The new corporate modification procedure was considerably less detailed (a significant departure from the Brunswick modification procedure) and did not include references to any local interfacing procedures or documents.
2.
Conflicts existed between direction given by the "new" corporate modification procedure and the local Brunswick procedure.
Procedure NED-IA-003, Rev. 1 requires that all setpoint changes be accomplished per the modification procedures, while ENP-03, Revision 39 exempts changes to torque or limit switch settings for MOVs.
Changes to torque or limit switch settings constitutes a design change and must be controlled as such.
Brunswick uses procedure ENP-43 to control MOV settings).
See Section 3.3.5 for a discussion of the inadequacies of procedure ENP-43.
3.6.5 Engineering Modifications The evaluation team examined the overall process for accomplishing plant modifications from initiation to closecut and found it to be inadequate.
Particular emphasis was placed on the design adequacy, including the availability of design basis information, use of design basis information, engineering evaluations, post-modification testing, and actual installation.
The results of the review are discussed below.
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3.6.5.1 Availability of Design Records Design basis information was not readily available or could not be located.
The team concluded that insufficient and fragmented design records existed, that modifications to the plant would not get an adequate review and that engineering decisions would be based on engineering judgement rather than by use of updated design documents.
For example:
1.
Design records were maintained in several organizations.
The design records for the nuclear reactor and :sso :ated components were maintained by the General Electric Company.
Design records for the remainder of the plant were originally retained by the architect engineer, UE&C.
- However, since.1987, a program had been underway to transfer an indexed set of design records for each of the plant systems from UE&C to CP&L.
This transfer was approximately 25 percent complete and the target date for completion was 1992 or later.
A program plan for GE to provide design basis _information for specific systems requested by CP&L was being defined.
In many instances, the team found that the design records were not retrievable because a complete index was not available, and that some design records did not exist at all.
For example, a complete set of design calculations for the nuclear SW system flows was not available, and there were no calculations to justify the TS operational limits for the amount of fuel oil required in storage to support emergency diesel generator operation.
Also, dimensional drawings of the emergency diesel saddle storage tanks were not available to even allow calculations to be made.
2.
The license had recently initiated a program to obtain system design criteria documentation from the original design organization.
The team was informed that these documents were being prepared for use by the design engineering staff in the corporate office.
The original design organization was preparing a System Design Criteria Document (SDCD) which consisted of process criteria, interfacing system data and requirements, a listing of modifications performed by the original design agent, a listing and copy of original design calculations, and a listing of reference documents such as procurement specifications.
Upon receipt of the SDCD, the document enters a reconciliation process where the document is reconciled to the as-installed configuration of the system (i.e.,
modification and changes initiated by others is reflected in the document).
The current SDCD for the service water system did not agree with the service water system description.
However, the team was informed 8
that reconciliation had not taken place and that the SDCD was not being used at that time.
3.
The system descriptions were documents which described the design intent of installed plant systems and were found to be a strength even though some minor errors and inconsistencies were noted.
The system descriptions provided an outline of the purpose, characteristics and equipment of each plant system as w,'1 as setpoints for instrumentation and control.
The SW system description was found to be a good source of information about the design and operation of the system.
The document was updated as modifications were made to the system and was a controlled document.
The system descriptions were not described as design basis documents but -
rather documents used to aid in the understanding of the system.
The 5
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w syst$mdescrkptionswereretainedinthePlantOperationsManualandthe system engineers within T/S are responsible for maintaining the system-V descriptions.
I
'3.6.5.2 Design Calculations and Revisions In general, fluid hydraulic calculations were not referenced in modification packages. The modification process required that calculations performed in support.of a modification be referenced as part of the design basis section of a modification package. During review of modification pckages, several calculations were reviewed.
For mechanical service water system modifications, the *sion be. sis section identified structural and mechanical stress calcu atms; however, no fluid hydraulic calculations were identified in any of the p:
.ses reviewed. As stated previously, the lack of fluid hydraulic calculations had fostered the use of engineering judgement instead of maintaining such calculations as "living" documents (i.e., updated and maintained as modifications were made).
The following calculations were reviewed which contained weaknesses and inconsistences:
1.
Orifice sizing calculation (ID No. 82-218W-02, Restriction Orifice Calculation Items 1 and 2-5W-F0-1189 and F0-1194, November 19,1985)
Service water temperature was assumed to be 85 F even though the o
service water design temperature range is 33 to 90 F.
The source <for the temperature was not identified.
Basis for assuming that the orifice needed to be resized for 300 gpm o
was not identified.
The analysis did not refer to HVAC design analyses which used cooler heat removal capability associated with a service water flow'of 300 gpm or some other source.
Source and/or justification for assuming that the friction loss o
across the new orifice was 27.9 feet was not provided.
The team was informed that this value was used to size the original orifice; therefore,'it was used in the new sizing calculation.
The lack of a flow distribution calculation contributed to this weakness.
o The calculation assumed a value for the ratio of bore diameter to inside pipe diameter. The inside diameter assumed (again source not identified) for the six inch pipe appears to correspond to a pipe with a concrete wall thickness of 0.125 inches; however, the orifice was not installed in concrete pipe.
Once the bore diameter was calculated a check should have been made to confirm the validity of that assumption.
If invalid, an iteration would have been required.
Although the assumption appeared to be valid, the lack of a confirmation d eonstrates weak computation practice.
o In December 1987, a QA audit report reviewed P/M 82-219W and calculation No. 82-218W-02 and identified the lack of references to sources of design input.
The response to the audit finding should have triggered a search for missing and necessary fluid hydraulic calculations as references.
The response to the audit finding
[ Reference CP&L Memorandum, Quality Assurance Audit of BSEP 86
L Operations Units 1 and 2 (QAA/0021-87-09), Serial No. BSEP/88-0100, dated February 8, 1988] stated, in part, that the results of the calculation have been reviewed and found to be correct. However, the calculation was not revised to add the missing references and the errors and inconsistencies identified above were not detected.
During the inspection the licensee performed a calculation to check the flow orifice bore sizing.
In addition, the licensee indicated that the calculation would be filed in accordance with procedure ENP-13 requirements and added to the documentation nackagas for the affected plant modifications.
2.
Project Proposal, Service Water Flow Distribution Verification, Rev.1, Project Control Number: 06329A, May 17, 1988 The results (erroneous) of the CP&L engineering analysis of the SW flow distribution were used as the basis for eliminating administrative controls which restricted SW flow to the RBCCW heat exchangers thus returning the SW system to unrestricted operation (see Section 3.6.3.2 for additional details).
3.6.5.3 Engineering Safety Evaluations Completed SW system modifications P/M 82-219W and P/M 82-219Y contained weak safety evaluations.
The team did not assess the acceptability of current engineering safety evaluation process or results.
The licensee did recognize, however, that current generic concerns involving weak safety evaluations continue to exist.
P/M 82-219W and 82-219Y replaced the cooling water coils in the RHR pump coolers 1A and IB, respectively.
The cooling coils were replaced with coils of a different material to reduce susceptibility to failures (leaks) at interfaces between the H-bend fittings and tubes.
In addition, the modifications also accomplished the following changes:
1.
Replacement of cooler air-operated SW discharge and manual-operated supply valves with valves of a different material, 2.
Replacement of the actuator on the discharge valve such that the valve fails open on loss of actuator motive power and removal of the existing air receiver and trip valve, 3.
Resize and replacement of pressure reducing orifice to correct for an original design capacity error, and 4.
Removal of SW radiation monitor and associated piping and equipment.
Nuclear Safety Evaluation Checklist dated May 12, 1986 in modification package P/M 82-219W and one dated August 21, 1986 in modification package P/M 82-219Y indicated that a revision to the FSAR was not required dua to thue modifications.
However, Table 9.2.1-1, " Service Water Flow Distribution - One Reactor Plant," should have been revised following these modifications, because of the changes to the failure position of the cooler discharge valve (i.e.,
upon loss of instrument air the valve goes full open initiating cooling water flow even though the original design assumed cooling flow would not be required until a high temperature was sensed in the RHR pump rooms).
For example, following a loss of coolant accident concomitant with a loss of offsite power 3
the original design assumed only one RHR cooler was required (i.e., each cooler has 100 percent capacity and they are sequenced such that one is loaded at i
87 1
i i
125 F and the other at 145'F).
Consequently, the flow demand was assumed to be 300 gpm in FSAR Table 9.2.2-1.
However, the failure mode was changed, resultirg in both RHR cooler discharge valves opening on loss of instrument air, creating a flow demand of 600 gpm.
In addition, the Nuclear Safety Evaluation Checklists for these two modifications did not address the consequences of changing the operating characteristics of the c'coler discharge valve actuators.
The safety evaluation did not address the consequences of increased service water flow demand on nuclear service water pump net positive suction head (i.e., pump runout conditions) or the consequences to other safety-related flow demands such as diesel. jacket water heat exchangers and RHR service water pumps. The. failure to perform a thorough safety evaluation contributed to the failure to detect the weaknesses in the operational readiness of the service water system identified in Section 3.6.3.
The above findings are consistent with NCRs88-055 and 88-056 written November 1988, which identified that there was a programmatic deficiency in the l
areas of safety reviews and qualifications regarding 10CFR50.59 evaluations and identification.
Accord'ing to the licensee, examples of poor 10CFR50.59 evaluations came from " plant groups, Construction groups and Corporate (NED) groups." The licensee indicated that a programmatic deficiency existed in the performance of safety evaluations at Brunswick in the following areas:
1.
Not properly identifying changes to the facility and procedures as described in the FSAR and tests and experiments not described in the FSAR.
2.
Lack of proper justification that a change, test or experiment did not constitute an unreviewed safety question.
3.
Lack of research or the documentation of research that Technical Specifications or the FSAR had been researched in order to make the determinations of the safety evaluation.
4.
Lack of understanding existed for ensuring that items that involved changes to the facility or to procedures, whether temporary or permanent, must be reported to the NRC.
The team concluded that the corrective action associated with the 10CFR50.59 safety evaluation deficiencies was lacking in scope in that it addressed only training and additional administrative controls and failed to address the concern or effect of poor, past evaluations and the existence of potential unreviewed safety questions.
l 3.6.5.4 Design and Configuration Cont nl In addition to the numerous SW design and configuration control weaknesses presented in section 3.6.3, the team identified other design areas that were also in need of improvement.
For example:
1.
The calculations that determined the non-NSSS setpoints or limits in the i '
TSs were not available.
For example, the design calculations for the minimum diesel fuel oil storage requirements in TS Section 3.8.1.1 were not available.
The design calculation for the degraded grid voltages in the T5 section was available only because they were part of a plant 88 I
I i
modification P/M-77-327.
The team was told that in general this type of calculation did not exist.
The determination of whether or not a calculation existed was a long and tedious process which produced uncertain results.
The licensee indicated that this situation would be improved when the turnover of indexed design documents was completed.
2.
There was no centralized, controlled document for listing all instrument setpoints. Therefore, setpoint changes may be made without the proper documentation being updated.
Plant Operating Manual (POM) Volume 11 entitled, " System Descriptions," stated that the system descriptions
- provided an outline of the purpose, characteristics and equipment of each plant system as well as the setpoints for instrumentation.
Section 2.4,
" Instrument and Control Setpoints" of each system description notes that setpoints for devices not listed in the instrument and control setpoint table may be specified in other design or procurement documents, such as:
instrument schedules; system piping and instrumentation drawings (P& ids);
associated driwings; instrument data sheets, procurement specifications; and vendor manuals.
3.
The team identified an example of poor engineering work in a modification package.
When the main condenser circulating water system was modified to install, debris filters in about 1980, the wiring to valves 1/2CW-V11 and
-V13 was changed to provide an interlock feature between the valves and the debris filters. The design of the modification placed control room and MCC valve position indications on different contacts such that the valve sometimes indicated intermediate position at the MCC while the control room indication showed the valve to be fully open.
Discussion with the licensee revealed that the modification was properly installed, but its design was improper and that another modification would be required to resolve the deficiency.
4.
During the evaluation, the team requested the licensee to demonstrate the validity of the setpoint for' minimum fuel oil storage in the emergency diesel generator day tank.
The minimum level setpoint was specified as 134.5 inches in the system description No. 5D-38 " Fuel Oil System".
The licensee performed calculation No. M89-009, which justified the existing setpoint.
However, the team found a technical error in the calculation, which the licensee acknowledged and agreed to correct. The revised calculation showed that the calculated amount of fuel oil had been reduced, but it remained above the minimum TS requirement.
The team was ccicerned that the technical error in the initial calculation, although cit.cked and verified, was indicative of a lack of attention to detail by the engineering support organization.
The team also found corrective action being taken to improve the configuration control of fuses used throughout the plant.
In mid 1988, an operational self assessment team identified numerous problems with fuse control.
The team found that in 3 out of 5 cases, fuse data was either not listed in plant drawings or was incorrectly listed. A further investigation verified the lack of fuse design control and a nonconformance report No. A-88024 was issued on July 8, 1988.
Interim design control was established with and existing Maintenance Policy (MP)88-001, dated June 28, 1988.
In addition, a two phase program was initiated to provide permanent control of fuse selection and use.
Phase one provides for selection of fuses on a case by case basis in accordance with MP 88-001.
Phase two will provide fuse selection criteria via a centralized 89
design document.
A fuse size / type index for five applications will be updated as additional information is available and plant modifications are implemented.
3.6.6 Plant Modification Review The team examined a cross section of plant modifications issued during the period of 1982 to 1988 to determine if the overall plant modification process as described in Sections 3.6.4 and 3.6.5 was effective in assuring that the plant modification packages produced by engineering were of high quality.
For modifications directly affecting the SW system, see Section 3.6.3.
Although the plant modification packages contained significant detail, the team concluded that the plant modifications contained an excesive number of field revisions and that this was indicative of a lack of attention to detail by the original design engineers and the design checkers / verifiers. All changes to plant modification packages, after their initial issue, are made by field revisions. A survey of 16 plant modification packages found an average of 23 field revisions per plant modification package, which the team considered an excessive amount. The largest number of field revisions was 51.
It was found that about 25 percent of the field changes were design revisions and the others were categorized as changes to drawings, installation and testing requirements, and typographical errors.
The results of the review of the selected plant modification packages are discussed below.
3.6.6.1 P/M-88-019 This emergency modification made changes to several HPCI motor operated valves to correct design deficiencies which limited the amount of torque which the valve actuator de motors could provide.
For valve 1-E41-F001, the HPCI injection valve, the size of the dc power cable was increased, actuator gearing was changed, and the starting resistor was bypassed.
For valves 2-E41-F006 and 1-E41-F006, the starting resistors were bypassed.
Installation instructions did not specify the connecting hardware (nuts, bolts, etc.) to be used to connect the jumpers to the resister terminals.
The associated design basis document (DBD) 88-08, which was added as Field Revisi0n No. 2, contained several anomalies that were not addressed.
For example:
1.
For valve 1-E41-F001, the required motor torque was calculated as 48.5 ft-lb, whereas the calculated motor torque available was 48.4 ft-lbs.
For valves 1-E41-F006 and 2-E41-006, the required motor torque was calculated as 83.5 ft-lb, whereas the calculated motor torque available was 60.1 ft-lb.
Although DBD 88-08 concluded that the proposed modification would increase the available torque at each motor, it failed to address the known fact that the new available motor torques were less than required.
Also, thes? anomalies were not addressed in the safety evaluation.
The team was informed that the anomalies were later addressed in FER NO.
88-0340, "HPCI/RCIC MOV Justification for continued operation." However, there was no reference in PM 88-019 to indicate this.
l 2.
DBD 88-08 referenced (for valves 1-E41-F006 and 2-E41-F006) a maximum expected differential pressure of 1260 psid (open) and 136.8 psid (closed),
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whereas engineering procedure FNP43, Rev. 4, "Q List for Motor Operated Valve Settings," lists the maximum expected differential pressure as 1230 i
psid (open) and 1300 psid (closed).
3.6.6.2 P/M-83-143 This plant modification added two new flow channels to the nuclear service water system to measure " cooling water flow to ESF components" to mt.et Regulatory Guide 1.97 requirements.
The licensee did not have a standard design guide for calculating instrument loop accuracies to ensure that all variables will be included in calculations.
The team was told that the methodology for performing the instrument loop accuracy calculations found in the modification package was at the discretion of the design engineer.
Engineering Procedure ENP 12.3, which the team was originally given as a reference, only specified the format for the calculations.
The team was told that a design guide for instrument setpoint calculations and instrument loop accuracy calculations would be developed and was scheduled for completion by September 30, 1989.
3.6.7 Modification Backlog The evaluation team reviewed the modification backlog for the last several months and concluded that inconsistencies existed betseen existing and future modification closecut rates as documented in the Brunswick Five Year Business Plan.
The Business Plan forcasted a significant drop in the number of modifications performed on a yearly basis.
For example, the 1989-1993 business plan addressed the number of modifications to be accomplished during outages and non-outage periods.
The planned total output varied from a low of 55 to a high of 85 modifications per year.
According to statistics generated by the Long Range Planning Group, there were 897 open modifications at Brunswick, which included approximately 330 classified as still within the design phase (i.e., plant modifications identified with a real number; no action taken; plant modifications released, but not approved; and plant modifications approved, but not fully installed).
Modification statistics also indicated that the number of modifications that are not yet " operable" has remained fairly constant at approximately 330, which would also indicate that the backlog of modifications was not being reduced at a rate consistent with the Business Plan.
Schedules involving long range planning also did not address the eventual modifications (or the period of accomplishment) associated with piping or safe end replacements due to extensive cracking c used by intergrannular stress corrosion cracking (IGSCC).
See also Section 3.1.5 for additional discussions regarding Business Plan.
3.6.7.1 Work Prioritization The team concluded that once a project was identified, the prcper work prioritization process initially took place using a computer program. Actual scheduling of various work, however, appeared to be more dependent upon subsequent budget concerns rather than initial plant needs.
See Sections 3.6.1.2.2 and 3.1.4 for additional information.
l r>lant modifications, including all other plant projects, were prioritized Osing Desktop Instruction DI-LRP-4, Rev. 8, " Preparation, Control, and Maintenance of the Schedule Index, Benefit Index, and Project Pricrity." The instruction was u
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used by the Site Planning and control Section, Integrated Planning, Budgeting and Scheduling /Long-Range Planning Unit.
The two main factors used to calculate project priorities were the " Total Project Cost" (TPC) and the
" Benefit Index" (BI).
The TPC was converted into a number which varied inversely to the project cost (i.e. cost up, project desirability down).
The BI was the summation of seven factors which were weighted in order of importance.
The BI factors were weighted as follows (1) Plant Nuclear Safety
(.28), (2) ALARA (.15), (3) Personnel Safety; nonradiological (.15), (4) Plant Availability / Reliability (.14), (5) Maintenance Requirements (.10), (6) Ease of Plant Operations (.10), and (7) Surveillance Requirements (.08).
3.6.7.2 Resolution of Intergrannular Stress Corrosion Cracking l
One of the perceptions by engineering personnel was that Brunswick was,always L
one of the last BWR nuclear plants in the industry to make needed upgrades in L
hardware or programs.
Examples include the ongoing IE Bulletin 79-14 structural walkdowns.
Site personnel at Brunswick were attempting to closeout l
this item fc the third time.
It was not scheduled for completion until 1992, and the resolution of chronic intergrannular stress corrosion cracking issues associated with the ' circulation system.
Complex modifications to accomplish the recirculation system piping replacement were essentially complete for Unit 1 and were in a preparatory phase for Unit 2.
The licensee first noticed IGSCC in 1976, in the recirculation system. The practice of using weld overlays began in 1983, and has greatly expanded since that time. A complete recirculation piping system, exclusive of valves and pumps was purchased in 1984, which was later determined to be less resistant to IGSCC than newer technology materials, so a second set of riser piping was purchased, however, actual piping replacement has never occurred.
In addition to extensive use of the weld overlay process, Brunswick has used Induction Heat Stress Improvement (IHSI), Mechanical Stress Irrprovement (MSIP), and Hydrogen l
Water Chemistry (HWC) in attempts to eliminate the need for extensive pipe l:
replacement.
The last few years of temporary solutions to the IGSCC problem has resulted in significant increases in Man-Rem exposure.
Between 30 and 40 percent of the total exposure received over the last four years at Brunswick was related to repairs and inspections of piping affected by IGSCC.
Recent correspondence between the NRC and CP&L (March 22,1989) stated that "Because of uncertainties in CP&L's stress analysis, i.he weld overlay repair performed on the safe ends is acceptable only for ont full cycle at this time.
l-In view of the extensive cracking of recirculation user piping and safe-ends at Brunswick Unit 1 and the recent inspection results from another BWR which question the effectiveness of hydrogen water chemistry in mitigating crack growth, the staff strongly recommends CP&L consider replacing the recirculation riser piping and safe ends during the next refueling outage."
At the close of the onsite evaluation period, no firm program existed to l
replace piping or safe ends as evidenced by the lack of any such reference in i
the recently published 1989-1993 Business Plan.
The licensee did indicate to the team, however, that plans were being made for recirculation system piping replacement for the next Unit I refueling outage, and a contingency program was being develo k d for pipe replacement for either the 1989 or 1991 Unit 2 refueling outage.
In the meantime, temporary repairs, IHSI, MSIP and HWC would I
continue to be utilized.
L 92 L
3.6.8 Evaluation of Selected Events The team reviewed a few recent events which involved significant engineering input to resolve.
Based on the events reviewed, the team concluded that the overall quality and timeliness of corporate or onsite engineering support depended greatly upon event visibility and was generally reactive in nature.
Followup root cause analysis also tended to be weak in that generic implications of events were not aggressively pursued.
The following examples include instances of adequate and inadequate engineering support.
3.6.8.1 Bolt Failures in Class IE Motor Control Centers An aggressive root cause determination was not pursued when numerous component failures were discovered in safety related equipment.
In 1987, numerous 5/16 inch silicon bronze carriage head bolts were found to have failed in
)
electrical bus bar connections inside the safety-related motor control centers.
These failures were similar to others discovered previously in November 1986.
A failure analysis was not undertaken until more bolt failures were discovered in January 1988.
In April 1988 the results of this failure analysis identified integranular stress corrosion cracking to be the common mode failure mechanism for the silicon bronze carriage head bolts.
These failures had the potential of rendering associated safety equipment inoperable during a seismic event.
A notice of violation EA-88 149 and a proposed civil penalty were issued by the NRC on December 30, 1988, with regard to this issue.
In its January 27, 1989 response to the notice of violation, the licensee indicated that certain corrective actions had been taken to assure that the cause of conditions is determined and corrective action is taken to preclude repetition.
o Plant procedure PLP-04, " Corrective Action Program," was issued to provide overall direction for corrective actions at BSEP.
o Regulatory Compliance Instruction RCI-6.6, " Site Investigation Process," was established to provide additional guidance on root cause identification.
o Special training on root cause identification was given to selected personnel by INPO.
o Brunswick Site Procedure BSP-31, " Root Cause Analysis Policy", was issued.
It established goals for achieving permanent corrections for problems discovered at BSEP.
For additional discussion of the above see section 3.5.2 3.6.8.2 Non-Seismic Pressure Switches on Nuclear Service Water System On June 17, 1988, a discrepancy was noted between the actual installation and the respective design drawings for the mounting of instrument 2-SW-PS-1996 which might negate the seismic qualification of the switch mounting.
This concern was also applicable to switches 2-SW-PS-1995, -1988, and -1999.
These switches, one for each diesel generator, effect transfer of the diesel generator normal SW suppl.; from the other unit upon a low pressure condit15n in the normal supply header.
93
l A preliminary engineering assessment performed that same day using original design drawings and field as-built drawings relative to the switch mourting concluded that the pressure switch mountings met Short-Term Structural Integrity (STSI) requirements.
A follow-up evaluation, completed 11 days later
{
determined that the mourting for the pressure switches was not seismically qualified.
On June 30, 2988, plant modification P/M 87-226 was implemented to seismically upgrade the switch mountings.
The team evaluated the engineering effort to assess the seismic qualification of the swittn mounting and concluded that the licensee's initial assessment, developed wiihn a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time limit to satisfy the requirements of Operating Instruction 01-04, " Limiting Condition for Operation Evaluation and Follow-up",
was inadequate.
In addition, it took an inordinately long time,11 days, to perform a follow-up evaluation to determine that the mounting was not seismically qualified.
The plant modification to upgrade the switch mounting j
]
was done expeditiously, however, once the correct assessment was made.
3.6.8.3.
DC Motor Operated Valve Torque Output Studies The design guide for the electrical evaluaticn of DC power motor operated valves did not address the effect of thermal overload heater resistance in determining available (reduced) actuator motor torque.
Design guide BSEP-MOVTG-E-01, Rev. 3, " Electrical Evaluation of DC Powered Motor Operated Valves," describes the criteria and methodology used to evaluate the capability of safety-related motor operated valves to perform their design functions under both normal and postulated design basis events and normal operating conditions.
The design criteria were then evaluated in a separate analysis for each valve.
The primary goals of the electrical work scope as stated in BSEP-MOVTG-E-01 were to establish the minimum available valve actuator motor output torque and to verify that the supporting electrical equipment was adequately sized and applied.
Design Guide Section 4.3.1, " Motor Output Torque," described the design criteria that must be evaluated in determining the motor output torque for DC valve actuator motors.
Criteria such as inrush current, motor rt.sistance, cable resistance, and bus voltage were discussed.
However, there was no discussion about the effect of the overiced heater resistance on available motor torque.
The team was told that "during the preparation of the DC MOV electrical design guide, the resistance effects of the heater were discussed as e potential item requiring evaluation.
Insufficient engineering data were available to quantify and document these effects in a design calculation.
Field measured values were taken on a small sample of overload heaters.
It was judged that the additional resistance would have an overall nominal effect on the final output torque value and would be bounded by other design conservatism." The team was also told that resistance measurements were taken on three individual C25-0B heaters i
from stock and the measured values were 0.09, 0.14, and 0.3 ohms at normal room ambient temperature.
The team concluded that this information was inaccurate j
because of the wide variance in measured resistance for the same model heater.
Subsequently, the licensee remeasured the resistance of the C25-0B heaters in stock and determined that the original measurements were in error because of an i
improper measurirg technique.
The new measurements from a sample of nine C25-0B heaters showed a maximum value of 0.070 ohms.
The licensee did not know 94
what the design resistance values should be and agreed to obtain the design resistance values from General Electric for the C25-0B heater and all other heaters used at the site.
To evaluate the effect of the overload heater resistance on motor torque, the team reviewed the " Unit 1 Electrical Analysis and Calculation for 1-E41-F006 HPCI Injection Valve." The overload heater model C25-0B was used in the circuitry for this valve.
The calculation analyzed several different cases, representing different operating conditions, valve location, and valve ac'uator motors.
Case 2 ef the calculation, which represented the configuration as installed by P/M 88-026 in mid-1988, was selected for review.
In this configuration, the valve remained in the main steam isolation valve (MSIV) valve pit and the 100 ft-lb motor was replaced by a motor having a torque output of 150 ft-lb.
The largest resistance (0.070 ohms) obtained from the second set of measurements was used in the evaluation.
The calculations showed that the circuit resistance increased from 1.4339 ohms (motor and cable resi tance only) to 1.5039 ohms when the heater resistance was included.
The s
net effect was to decrease the calculated available motor torque from 103.2 ft-lb to 102.1 ft-lb.
This was below the required motor torque of 103.4 ft-lb.
Therefore, the evaluation showed that the valve actuator motor installed by P/M 88-026 had insufficient torque to open the valve under certain accident conditions.
The original deficiency in the amount of calculated available DC motor torque was addressed in EER No. 88-0340, "HPCI/RCIC MOV, Justification for Continuous Operation." The licensee has agreed to review EER No. 88-0340, using the new design guide, with particular emphasis on the Unit 2 E41-F006 valve, which is still located in the MSIV valve pit.
Valve 1-E41-F006 and its actuator were relocated during the Unit 1 refuel outage in late 1988 to reduce the environmental effects on the motor and cable resistance in calculating available DC motor torque.
Case 4 of the calculation addressed the new environmental conditiens.
Using the original maximum heater resistance of 0.3 ohms, the calculated available motor torque decreased from 123.9 ft-lb to 102.84 ft-lb, which is slightly below the required actuator motor torque of 103.4 ft-lb.
However, with the latest measured maximum heater resistance of (0.07) ohms, the available motor torque decreased from 123.9 ft-lb to 121.5 ft-lb, which is above the required actuator motor torque of 103.4 ft-lb.
The licensee had agreed to revise the design guide BSEP-MOVTG-E-01 to require evaluation of the motor overload heaters in calculating available motor torque.
In addition, calculations for all DC motor actuated valves will be reviewed / redone to assure that the valves will operate as required.
3.6.8.4 Valve Body Erosion The team evaluated the eng<neering effort to study the RHR valve erosion issue (documented in LER 325-88-033) and determined that the licensee's response was both timely and adequate, once the problem was observed during the performance of maintenance.
During scheduled maintenance of valve 1-E11-F0178, significant localized erosion was discovered adjacent to the valve seat on November 29, 1988.
F017B had experienced chronic packing leakage due to a galled valve stem since 1982.
The erosion problem would have been discovered much earlier had timely corrective action been taken by the site.
The licensee proceeded to examine 95
I other valves which were used for throttling and concluded that valves F017A/B l
I and F024A/8 in both units had sustained extensive erosion.
The greatest amount of erosion was on the "B" train which was used more than the "A" train.
4 l
Commitments were made which involved additional testing of the unit 1 valves to l
determine the limits which they can be operated without cavitation erosion.
The Unit 2 valves were scheduled to be repaired during the September 1989 refueling outage.
The licensee also planned to establish a long-term erosion monitoring program by June 1989.
Subsequent to the discovery of the erosion problem, General Electric distributed a " Rapid Information Communication Services Information Letter" (UTCSIL) No. 034 recommending that licensees review plant-specific operating conditions of globe valves used for throttling to detr.rmine which valves may be vulnerable to cavitation erosion, conduct a walk-down of the valves while they are being throttled to listen for cavitation sounds, inspect valves suspected to be vulnerable to such erosion, and take corrective action as required.
The licensee examined approximately 30 valves (not including the RHR F017 and F24 valves) in the RHR, core spray, RCIC, and HPCI systems were evaluated including the disassembly of eight valves.
One additional valve was found that had experienced erosion; HPCI F008.
3.6.9 Closeout of Vendor Recommendations Processing of vendor recommendations (VR) was accomplished by Plant Performance Procedure PPP-02, Rev. 8, " Vendor Recommendation Processing." Technical Support had the responsibility for the program.
The team reviewed action taken to resolve issues identified primarily by General Electric through " Services Information Letters" (SILs) and " Technical Information Letters" (TILs).
SIls and TILs generally specify a recommended action which may vary from performing a document review, to performance of detailed modifications.
Once reviewed, the licensee has the option to implement the vendor recommendation in part or not at all provided that a VR deviation is documented and approved.
The team's review of the VR program and its implementation resulted in the following weaknesses:
3.6.9.1 Untimely Identification and Closeout of Vendor Recommendations According to the VR tracking system, numerous VRs dating back into the 1970s were still listed as open and existed as EWRs.
Some VRs took as long as nine years before they were entered in the VR system.
For example, GE SIL 210, written in January 1977, regarding noise problems associated with neutron monitors, was put into the VR recommendations system in 1984, was transferred to an EWR as a modification and is scheduled to be worked in 1991.
GE SIL 289, written in May 1980, regarding cracking in core spray sparger arms, was put into the VR recommendation system in March 1989, transferred to an EWR and had not been dispositioned by the close of the evaluation.
3.6.9.2 Inadequate Procedures to Control Vendor Recommendations Procedure PPP-02 (last revised in June 1987) requi: as action from groups which no longer exist, whose function had either changed or had been moved to l
corporate, Consequently, work practices were not in agreement with the governin'g procedure.
Titles of groups had also changed because of the number of reorganizations to onsite and offsite engineering organizations.
Procedures 96 j
were required to be rewritten by August 1989, however the action item had not yet commenced by the close of the evaluation.
See Section 3.5.5 for additionsi details of site reivew of VRs.
1 1
4 97
., D 4.0 EXIT MEETING l On June 16, 1989, the EDO, DEDO, AEOD Director, Region II Administrator, NRR Director, Brunswick DET Manager, DE Leader, and other NRC personnel met at the NRC offices in the White Flint Building with senior CP&L management officials to provide a briefing on the results of the diagnostic evaluation.
The list ~
of attendees is provided at the end of this section.
The briefing notes which 1
provided the team's preliminary findings and conclusions, are attached as I
Appendix A.
As.a general note, senior CP&L managers discussed their belief that the diagnostic evaluation process is a valuable assessment mechanism and provides another perspective of the effectiveness of activities and identification of root'causes.
e
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ATTENDEES Brunswick Diagnostic Evaluation Meeting - June 16, 1989 Name Organization V. Stello Executive Director for Operations (E00), NRC J. M. Taylor Deputy EDO for Nuclear Reactor Regulation, Regional Operations & Research, NRC E. L. Jordan Director, Office for Analysis and Evaluation of Operational Data (AEOD), NRC l
S. D. Ebneter Regional Administrator, Region II, NRC l
T. E. Murley Director, Office for Nuclear Reactor Regulation (NRR), NRC S. Varga Director, Division of Reactor Projects I/II, NRR/NRC R. Lee Spessard Team Manager, Brunswick Diagnostic Evaluation Team, AEOD/NRC J. W. Craig Team Leader, Brunswick Diagnostic Evaluation Team, NRR/NRC E. Merschoff Deputy Director, Division of Reactor Safety, RII/NRC G. Lainas Assistant Director for Region II Reactors, NRR/NRC l
W. Ruland Senior Resident Inspector, Brunswick, NRC E. Tourighy Project Manager, Brunswick, NRR/NRC T. Le Project Manager, Brunswick, NRR/NRC R. W. Borchardt Regional Coordinator, OED0/NRC L. Eury Executive Vice President, Power Supply R. Watson Senior Vice President, Nuclear Generation group R. Starkey Manager, Brunswick Project J. Harness General Manager, Brunswick Plant A. Cutter Vice President, Nuclear Services Department A. Lucus Manager, Nuclear Engineering Department R. Paulk, Jr.
Supervisor, Regulatory Compliance Subunit J. Sally North Carolina Power Agency W. Batt North Carolina Power Agency e
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,V.
APPENDIX B
./
UNITED STATES k
NUCLEAR REGULATORY COMMISSION
.l wAsHawoTow, p. c.rosss
%..../
JAN.0 8 1989 MEMORANDUM FOR:
Edward L. Jordan, Director Office for Analysis and Evaluation of Operational Data FROM:
Victor Stello, Jr.
Executive D.jrector for Operations
SUBJECT:
DIAGNOSTIC EVALUATIONS By this memorandum you are directed to conduct diagnostic evaluations of the Brunswick Steam Electric Plant and Perry Nuclear Plant. You should plan to conduct these diagnostic evaluations so that you can report your findings at the next Senior Management Meeting on May 17, 1989. Support for the diagnostic evaluation teams will be provided, as necessary, by NRR and the regional offices.
As you know, these plants were discussed during the last NRC Senior Management i
Meeting. From these discussions, which addressed the regulatory and operational performance history at both nuclear stations, it became apparent that additional information would be needed to make an adequately informed decision regarding their overall performance.
I have determined that diagnostic evaluations of these plants are the most effective means of obtaining this information. These evaluations should be broadly structured to assess overall plant operations and the adequacy of both licensees' major programs for supporting safe plant operation.
Please forward your specific plans regarding schedule, team composition, and i
evaluation methodology when they are formulated.
]
i g;g'g>
ictor Ste.llo, Jr. '
Executive Direct i
for Operations cc:
M. L. Ernst, RII T. E. Murley, NRR J. M. Taylor, DEDRO A. B. Davis, RIII l
t.
115 4