IR 05000296/1995201
| ML18038B571 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/07/1995 |
| From: | Gallo R, Narbut P, Norkin D NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML18038B570 | List: |
| References | |
| 50-296-95-201, NUDOCS 9512140254 | |
| Download: ML18038B571 (44) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION NRC Inspection Report:
50-296/95-201 Docket No.:
50-296 Licensee:
Tennessee Valley Authority Facility Name:
Browns Ferry Nuclear Plant, Unit 3 License No.:
DPR-68 Inspection at:
Browns Ferry Nuclear Plant, Decatur, Alabama Inspection Conducted:
October
20, 1995
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0 3S Date Inspection Team:
P. Narbut, Team Leader, NRR H. Wang, Assistant Team Leader, NRR A. D'Angelo, Inspection Program Branch, NRR M. Banerjee, Senior Resident Inspector, Region I P. Byron, Resident Inspector, Region II R;
Frahm, Jr.,
gA and Maintenance Branch, NRR K. Ihnen, Resident Inspector, Region III E. Kleeh, Special Inspection Branch, NRR R. Pelton, Human Factors Assessment Branch, NRR P. squalls, Reactor Inspector, Region IV Vick,aerator Lice sing Branch, NRR Prepared by:
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Paul P. Narbut, Team Leader Special Inspection Branch Division of Inspection and Support Programs Office of Nuclear Reactor Regulation, Donald Norkin, Section Chief Special Inspection Branch Division of Inspection and Support Programs OfFice of Nuclear Reactor Regulation Date Approved by:
Robert Gallo, Branch Chief Special Inspection Branch Division of Inspection and Support Programs OfFice of Nuclear Reactor Regulation Date 95i2i40254 95i207 PDR ADQCK 05000296
PDR Enclosure
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C Hr. Oliver D. Kingsley, Jr.
Tennessee Valley Authority BROWNS FERRY NUCLEAR PLANT CC:
Hr. 0. J. Zeringue, Sr. Vice President Nuclear Operations Tennessee Valley Authority 3B Lookout Place 1101 Harket Street Chattanooga, TN 37402-2801 Dr. Mark O. Medford, Vice President Engineering 8 Technical Services Tennessee Valley Authority 3B Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Hr. D. E.
Nunn, Vice President New Plant. Completion Tennessee Valley Authority 3B Lookout Place 1101 Harket Street Chattanooga, TN 37402-2801 Hr.
R.
D. Hachon, Site Vice President Browns Ferry Nuclear Plant
.Tennessee Valley Authority P.O.
Box 2000 Decatur, AL 35602 General Counsel Tennessee Valley Authority ET 11H 400 West Summit Hill Drive Knoxville, TN 37902 Mr. P.
P; Carier, Manager Corporate-Licensing Tennessee Valley Authority 4G Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801 Hr. T. D. Shrive'r Nuclear Assurance and Licensing Browns Ferry Nuclear Plant Tennessee Valley Authority P.O.
Box 2000 Decatur, AL 35602 Hr. Pedro Salas Site Licensing Manager Browns Ferry Nuclear Plant Tennessee Valley Authority P.O.
Box 2000 Decatur, AL 35602 TVA Representative Tennessee Valley Authority 11921 Rockville Pike, Suite 402 Rockville, HD 20852 Regional Administrator U.S. Nuclear Regulatory Commission Region II 101 Marietta Street, NW., Suite 2900 Atlanta, GA 30323 Hr. Leonard D. Wert Senior Resident Inspector Browns Ferry Nuclear Plant U.S. Nuclear Regulatory Commission 10833 Shaw Road Athens, AL 35611 Chairman Limestone County Commission 310 West Washington Street Athens, AL,35611 State Health Officer Alabama Department of Public Health 434 Monroe Street Montgomery, AL 36130-1701
Distribution:
Docket Files 50-296 PSIB R/F WTRussell, NRR FJMiraglia, NRR ACThadani, NRR RZimmerman, NRR FGillespie NRR PPNarbut,NRR RMGallo, NRR DPNorkin, NRR CERossi, AEOD FJHebdon, NRR JAZwolinski, NRR SAVarga,,NRR JFWilliams, NRR EWMerschoff, RII JRJohnson, RII AFGibson, RII MLesser, RII LWert, SRI CHarwood Regional Administrators Regional Division Directors Inspection Team PUBLIC
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OGC (3)
1S Distribution
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1.0 EXECUTIVE SUHHARY
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TABLE OF CONTENTS 2.0 INSPECTION OBJECTIVES AND SCOPE
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3.0 FACILITY MANAGEMENT.
3.1 ORGANIZATION AND STAFFING
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3.2 SITE AND CORPORATE MANAGEMENT INTERACTION.
3.3 MANAGEMENT OVERSIGHT, INVOLVEMENT, COMMUNICATION, 3.4 OPERATIONAL READINESS SELF-ASSESSMENT
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3.5 TRANSITIONAL CONTROLS
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3.6 OPERATING EXPERIENCE FEEDBACK.
3.7 CONCLUSIONS
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AND GOALS
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4.0 5.0 6.0
"'.0 OPERATIONS 4.1 PERSONNEL QUALIFICATIONS AND STAFFING ADEQUACY 4.2 OPERATIONS PERSONNEL TRAINING.
4.3 PROCEDURE ADEQUACY 4.4 PROCEDURE ADHERENCE
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4.5 SYSTEM STATUS CONTROL AND LOGS 4.6 SHIFT ROUTINE AND TURNOVER,
'.7 RESPONSE TO ANNUNCIATORS AND OFF-NORMAL CONDITIONS 4.8 TECHNICAL Specifications LCO TRACKING AND CONTROL
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4.9 HOUSEKEEPING AND MATERIAL CONDITION
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4.10 CONTROL ROOM DECORUM AND PROFESSIONALISM 4.11 REPORTABILITY REQUIREMENTS AND IMPLEMENTATION.
4.12 OVERTIME CONTROLS
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4.13 POST-TRIP REVIEW PROCESS 4.14 CONCLUSIONS MAINTENANCE.
5.1 ORGANIZATION AND STAFFING
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5.2 SELF-ASSESSMENTS 5.3 REVIEW OF COMPLETED WORK PACKAGE RECORDS 5.4 OBSERVATION OF IN-PROCESS WORK 5.5 MATERIAL AVAILABILITYAND PARTS CONTROL
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5.6 WORK SCHEDULING AND PRIORITIZATION 5.7 MAINTENANCE BACKLOG
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5.8 FAILURE TRENDING AND PREDICTIVE MAINTENANCE 5. 9 TRAINING 5.10 CONCLUSIONS
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SURVEILLANCE TESTING 6.1 TEST PERSONNEL 6.2 PROCEDURE ADHERENCE, ADEQUACY, AND PERSONNEL PERFORMANCE 6.3 TEST SCHEDULING
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6.4 CONCLUSIONS
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SAFETY ASSESSMENT AND QUALITY VERIFICATION 7. 1 OVERSIGHT COMMITTEES 7.2 QUALITY ASSURANCE INVOLVEMENT.
7.3 CORRECTIVE ACTION PROGRAM
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7.4 ROOT CAUSE AND FAILURE ANALYSIS
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7.5 INDEPENDENT VERIFICATION POLICIES
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7.6 CONCLUSION
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8. 1 REQUIREMENTS 8.2 REVIBI OF FIRE PROTECTION PROCEDURES 8.3 PLANT TOUR 8.4 FIRE RESPONSE EQUIPMENT
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8.5 THERMO-LAG 330-1 FIRE BARRIERS 8.6 STAFFING 8. 7 TRAINING 8-8 QUALITY ASSURANCE AUDIT.
8. 9 CONCLUSIONS
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9.0 ENGINEERING AND TECHNICAL SUPPORT
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9. 1 ORGANIZATIONAL STRUCTURE 9. 2 ENGINEERING PERFORMANCE
'9.3 TECHNICAL SUPPORT GROUP PERFORMANCE 9.4 CONCLUSIONS
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10.0 EXIT MEETING APPENDIX A DEFICIENCIES
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APPENDIX B OBSERVATIONS
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APPENDIX C ATTENDANCE LIST
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34 A-1 B-1 C-1
1.0 EXECUTIVE SUNDRY The Browns Ferry Units had been shutdown by the Tennessee Valley Authority (TVA) since March 1985.
The units remained shutdown until the restart of Unit 2 in May 1991.
The inspection described in this report was conducted to assess the readiness of the licensee to restart Unit 3 in conjunction with the already operating Unit The inspection was led by -the Special Inspection Branch of NRR.,
The team.consisted of -ten inspectors and a team leader.
The team assessed the functional areas of management, operations, maintenance, surveillance testing, safety assessment and quality verification, fire protection, and engineering.
The findings of the inspecti'on were as follows:
The team considered management at Browns Ferry to be a strength.
Management personnel were well qualified and brought experience from plants outside of the TVA system.
Management was aggressive in problem resolution and was closely involved with plant staff.
Management was well aware of its weaker performance areas and was working.to strengthen those areas.
It had arranged for outside experts to perform tough, critical assessments of readiness for operation, and also had performed well-structured and detailed self-assessments.
Good management systems were in place to monitor performance and trends.
The team considered performance in the area of operations to be adequate.
Operator staffing on each shift exceeded NRC minimum requirements.
Operators
. were knowledgeable, as evidenced by their high pass rates on licensing exams, and as demonstrated by their good performance in event response and simulator exercises.
Operator behavior was professional.
The team observed good turnovers, good annunciator response, and good knowledge of system and hardware status.
On the other hand, the team observed some individual performance errors.
For example, some operators failed to log actions,- such as pump starts, as is required by plant procedures.
The team also observed some errors in troubleshooting procedures which should have been caught before the procedures were performed.
The licensee's actions in response to these errors were timely and appropriate.
The team considered that the overall performance of routine shift activities to be adequate for operations and typical of performance at other operating plants.
In the areas of maintenance and surveillance testing, the team considered the overall performance levels to be adequate.
Staffing and craft skills were good.
The team observed good performance in the majority of observations and record reviews.
Craft used the correct materials and tools, and maintained good housekeeping and work controls.
Problems encountered by the craft were properly documented for resolution.
In some procedures and work practices, the team observed some examples of minor problems such as failure to adequately perform supervisory reviews of completed work records.
These observations did not affect the end product and the licensee took appropriate corrective action.
The quality of maintenance observed was in keeping with the quality of maintenance at other operating plant The team considered the areas of safety assessment and quality verification to be adequate.
Onsite and offsite safety committee activities met requirements.
The team observed active management and gA oversight.
The team noted that, just before 1995, the licensee revised and strengthened its program for reporting problems to encourage the open identification and resolution of problems.
This led to a sixfold increase in the number of problem reports written in '1995, as compared to 1994.
The team also observed that quality assurance audits and surveillances were performed in-depth and were performance-based.
The licensee's audits identified broad areas requiring attention (1) rigor in procedure compliance and (2) procedure accuracy and complexity.
Consultants who performed independent assessments for the licensee identified these same areas.
The team considered the fire protection program to be strong.
The licensee had a staff of full-time professional fire fighters, and a good fire fighting facility; both were well above NRC requirements.
The fire protection systems were in good condition, and the control of combustibles was good.
When the team identified an example of a procedure weakness concerning ventilation damper isolation, the licensee took prompt and adequate corrective action.
The team considered engineering to be a strong area overall.
The licensee had a large qualified engineering staff with considerable site-specific experience.
The team found good support for operations and maintenance.
The team found that drawing control was good and noted no significant drawing errors.
The team observed safe operation of Unit 3 during testing in conjunction with the concurrent safe operation of Unit 2 at power utilizing essentially the same programs, procedures, and people that would be used to operate Unit 3.
The overall level of performance observed was considered adequate for operations.
The team concluded that the licensee had programs, personnel, and procedures that were adequate for the restart of Unit 3 operations.
2.0-INSPECTION OBJECTIVES AND SCOPE The objective of the Operational Readiness Assessment Team (ORAT) inspection of Browns Ferry Unit 3 was to evaluate the licensee's readiness to restart Unit 3 operations.
All the Browns Ferry units voluntarily shut down in 1985.
Unit 2 had been operating since its 1991 restart while Unit 1 and 3 remained shutdown.
The.inspection conformed to the guidance in Inspection Procedure 93806,
"Operational Readiness Assessment Team Inspection,"
except that the team did not.evaluate primary water chemistry, security, emergency preparedness, confirmatory measurements, radiological environmental monitoring, radiological waste and effluents, chemistry, power ascension testing, fuel receipt and storage, or transportation.
These areas had been or would be examined by regional personnel.
The team examined management, operations, maintenance, surveillance testing, safety assessment and quality verification, and
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engineering.
Although not required by the inspection procedure, the team also examined'ire protection readines The inspection was led by the Special Inspection Branch of NRR.
The team consisted of ten inspectors and a team leader.
The team made performance-based observations of in-plant activities.
The team covered control room activities continuously (24-hour coverage)
for,a period of four days, observed operator crew performance in simulator exercises, and performed walkdowns of five systems.
Because plant personnel were rotated through the units, and used essentially the same programs and procedures, the team also sampled some Unit 2 activities.
The systems and components examined were selected utilizing probabilistic risk assessment data to ensure that important activities were sampled.
Some balance-of-plant activities were also sampled.
The team also evaluated personnel and system unit interdependencies.
This report categorizes inspection findings as deficiencies or observations.
Deficiencies, discussed in the report and listed in Appendix A, constitute either (1) the apparent failure of TVA to comply with regulatory requirements or (2) the apparent failure of TVA to satisfy non-legally binding requirements (such as written commitments, applicable codes, standards, guides, or acceptable industry practices).
Observations, discussed in the report and, listed in Appendix B, are items considered appropriate to call to the attention of station management but which have no direct regulatory basis.
Appendix C lists the licensee management and NRC.staff who att'ended the exit meeting.
3.0 3.1 FACILITY MANAGEMENT ORGANIZATION AND STAFFING The team compared the qualifications and commercial operating experience of key Browns Ferry managers to plant Technical Specifications and procedural requirements.
The Site Vice President and Plant Manager bring considerable nuclear operating experience to the Browns Ferry organization.
The Site Vice President has held positions ranging from BWR System Engineer to.Plant Manager for a similar BWR facility, to President of a consulting company.
The Plant Manager has held a
BWR Senior Reactor Operator license and has technical, managerial, and operational experience similar to that of the Site Vice President.
Each manager has more than 20 years of commercial BWR experience.
The Site Vice President and the Plant Manager qualifications exceed Technical Specifications and procedural requirements; The Plant Manager's department heads comprised the maintenance and modifications manager, operations manager,.radiological controls/chemistry manager, outage manager, technical support manager, and the training manager.
Each of these managers has more than 10 years of operating nuclear experience and exceeds the Technical Specifications and procedural requirements.
For refueling and power ascension testing, management augmented the Browns Ferry 3 operations shift management with two positions; a Shift Mentor and a
Unit 3 Supervisor.
When Unit 3 begins commercial operation, the licensee plans to remove these two positions from the operating organization.
The positions are discussed in Section 4.0 of this repor C Browns Ferry used an organizational development consultant from outside TVA to determine staffing levels appropriate for dual-unit operation.
The consultant compared Browns Ferry staffing to staffing at other dual-unit nuclear facilities in the U.S.
In addition, Browns Ferry managers visited other multi-unit sites to learn about staffing levels there.
As a result of the assessments and visits, site management identified those positions that would not be needed for dual-unit operation.
Individuals in positions at risk were notified in June as to when they could expect their positions to be abolished.
To maintain a positive attitude on site, management stated that individuals so identified will be transferred to the TVA Service Organization with a guarantee of one year of employment.
The Service Organization provides support to all TVA nuclear facilities in a manner similar to the traveling outage organizations used by other utilities.
The team noted that key managers at Browns Ferry have been in position for at least two years.
Organizational changes during the past five years were directed at strengthening the organization and the organization's operational experience level outside of TVA.
The team determined that Browns Ferry staffing levels were appropriate for dual-unit operation, and that the qualifications and experience of key Browns Ferry managers exceeded Technical Specifications and procedural requirements.
3.2 SITE AND CORPORATE NANAGENENT INTERACTION During interviews, licensee representatives stated that the interaction with TVA Nuclear and the other TVA nuclear sites was a strength and contributed to the improvements at Browns Ferry.
The team observed examples of the good interaction.
One example was the daily telephone call between TVA operating sites.
Ouring these calls, information on technical and regulatory issues was exchanged.
A second example was the monthly site staff meetings with the Chief Nuclear Officer as the featured speaker.
The team concluded that the interaction between site and c'orporate personnel was'good and appropriate for restart.
3.3 NANAGENENT OVERSIGHT, INVOLVENENT, CONNUNICATION, AND GOALS The team examined the licensee's published policies, goals, and objectives and considered them conservative and oriented toward safety.
The corporate objective was to achieve operating results which would place Browns Ferry among the top nuclear plants in the world.
Corporate goals and objectives were incorporated into the site business plan, which, also contained methods for monitoring performance.
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'lh Other methods of communication employed at Browns Ferry were (I) the operational experience review process and the weekly meeting of the operational experience review panel during which operational information was exchanged between Browns Ferry, TVA corporate, and other TVA nuclear facilities; (2) periodic meetings between'he Sequoyah and Browns Ferry business and work performance groups to determine methods that can be used to
improve performance (Browns Ferry had the lead for'new methods of processing work orders and Sequoyah had the lead for the quality self-check process);
(3) monthly round-table meetings between the Site Vice President and 40 to 60 staff personnel, with other members of management specifically excluded, (plant management viewed the exclusion as a good method of gaining feedback from the staff); (4) annual business plan meetings with all staff followed by quarterly updates of the status of the business plan; (5) quarterly meetings-to trend ongoing and projected site activities.
The team interviewed management to assess management involvement in day-to-day facility operation.
Management was conducting observations both in the plant and in training.
Although, the management observation program was not specified by a procedure, management observations were being performed.
Only records of management observations of training were available.
The training observations were listed in the daily Plan of the Day (POD) meeting once a week.
Week-to-week differences in observations of training were discussed in the POD meetings.
All site supervisors were required to observe training activities and record the observations.
By reviewing completed training observations, the team verified that participation in the management observation program was good.
The Site Vice President monitored the performance of training observations.
Through interviews with Training Department management, the team learned that the department was getting good information. from the observations and acting upon it.
The licensee stated that they plan to develop a procedure for management observations which would stress the use of observation time to reinforce management expectations.
The team determined that management was actively involved in the planning and preparation of work.
Active management involvement was noted in daily POD meeting, the Operating Experience Review Panel meeting, and the Management Review Committee's daily problem evaluation report meeting.
- In addition, the team concluded that management oversight, involvement, and communication were appropriate for Unit 3 restart.
3.4 OPERATIONAL READINESS SELF-ASSESSMENT The team reviewed four internal operational readiness self-assessments of individual departments.
The internal self-assessments of Operations Department and the Maintenance Department'ere thorough, were conducted using accepted industry objectives and criteria, and were critical reviews of the programmatic readiness of the departments being assessed.
However, being conducted at the program level, these internal assessments were not intended
'o and did not actually assess departmental performance.
The assessments concluded that the departments were programmatically ready for dual-unit operations.
In addition to'he internal self-assessments, two external assessments of the operational readiness of Browns Ferry were conducted.
The first assessment
was conducted by an Operational Readiness Review Team (ORRT) which was made up of outside industry experts.
The licensee invited the ORRT to be critical and to look beyond restart to-dual-unit operation.
The second assessment was conducted by INPO.
Both assessments were tough critical assessments that identified performance issues and noted areas for improvement that needed to be addressed before the restart of Unit 3.
The findings and recommendations of the readiness assessments provided appropriate information for-improvement and corrective action.
In most cases, corrective actions were underway or in the planning stage at the conclusion of the assessment.
The team also noted, as discussed in Section 7 of this report, that management made effective use of its guality Assurance Department.
Management was well informed regarding their weaker areas and was taking appropriate actions for those areas, including ongoing performance monitoring.
The team concluded that management was taking timely and appropriate corrective actions for restart and long-range improvements.
3.5 TRANSITIONAL CONTROLS The licensee tracked departmental readiness for Unit 3 restart with a management tool, called
"windows," which had been developed by TVA Nuclear.
The tool used industry-developed objectives and criteria to qualitatively determine the relative strength or weakness of functional areas, departments, units and the site.
The tool used color-coded windows to indicate performance in an area.
The report a'nd the readiness of each department was discussed at monthly meetings attended by the Site Vice President, the Plant Manager, and the appropriate department heads.
The report provided a visual display for managers and staff regarding matters to be addressed before restart.
In addition, weekly meetings were held to discuss the schedule and status of Unit 3 recovery, obstructions to restart, and trends associated. with the recovery.
These meetings looked at items on an individual level rather than at a departmental level.
The team concluded that Browns Ferry was actively ensuring all items were accounted for and effectively addressed prior to Unit 3 restart.
3.6 OPERATING EXPERIENCE FEEDBACK The team observed that the licensee's Operating Experience Program includes the review and evaluation of worldwide operational nuclear information.
Weekly Operational Experience Review Panel meetings, conducted via conference calls, were chaired by TVA corporate staff in Chattanooga and included representatives from all the TVA operating and construction sites.
During the meetings, new operational experience items were discussed, actions to be taken for each new item were determined, responsibility for the actions was assigned, and the status of previous action items was discussed.
New items were discussed collegially and actions to be taken and responsibility to complete the actions were determined with consensus from all partie The team selected three of the licensee's operating experience actions items to determine the status of the actions to be taken and to determine if the actions taken were appropriate.
The team reviewed General Electric Technical Information Letter (TIL) 1165.3, INPO Operating Event Report 95-7289, and INPO Significant Operational Experience Report (SOER) 95-01.
In all cases, the operating experience items had been evaluated and initial actions completed.
With the exception -of SOER 95-01, all required actions had been completed and the items had been closed out.
Completion of action items for SOER 95-01 required changes to accredited training programs.
These changes were on schedule for completion.
The team considered that the licensee had taken appropriate actions for these three operating experience items.
The licensee's primary method for communicating operational experience information to plant personnel was through the Training Department.
Training participated in the weekly Operational Experience Review Panel meetings.
Methods employed by Training, to disseminate operating'xperience lessons, included required reading, incorporation into the initial or continuing training program, one-time training conducted in the appropriate shops, and on-the-job training with task performance evaluation.
The team concluded that the Training Department was adequately informed of operational experience information and took appropriate actions to get the information to affected personnel.
The team determined that the time to complete the required actions was appropriate to the significance of the
. required action.
3.7 CONCLUSIONS The team considered management at Browns Ferry to be a strength.
The qualifications and experience of management personnel was in excess of Technical Specifications and procedural requirements.
Management had ensured that there were sufficient numbers of qualified and trained individuals to support dual-unit operation and provided additional resources for startup and power ascension.
The team observed good communications and corporate-site management interaction and noted management's active involvement in the operation of the facility.
The management-directed operational readiness assessments were properly thorough and critical reviews.
Management effectively used the guality Assurance Department, was well informed regarding the weaker performance areas, and was taking appropriate actions for those areas, such as ongoing performance monitoring.
The team concluded that management was taking timely and appropriate corrective actions for restart and long-range improvements.
4. 0 OPERATIONS The team assessed the conduct of operations during a 96-hour continuous evaluation of shift activities in the Unit 3 control room and throughout the plant.
The team evaluated operating procedures, shift turnover, shift operations, shift communications, main control room access, and personnel
conduct related to the conduct of nuclear plant single and dual-unit operations.
The team reviewed the Operations Department organization, staffing, and experience levels.
The team conducted observations in the control room, interviewed operators, and performed Unit 3 walkdowns of the core spray system (CSS), residual
.heat removal (RHR) system, high pressure coolant injection (HPCI) system, fire water supply/fire protection system, and the reactor protection system (RPS).
In addition, the team observed outage activities leading up to and actually loading fuel in the Unit 3 reactor vessel.
The team also examined normal, abnormal, and emergency operating instructions; reviewed systems status controls and control room logs; checked valve lineups and the control of system configurations; and observed licensed operator training and refueling activities.
Additionally, the team accompanied auxiliary operators on plant tours and system walkdowns, and observed surveillance testing.
4.1 PERSONNEL QUALIFICATIONS AND STAFFING ADEQUACY The team assessed the qualifications and operating experience of key Operations Department managers and shift licensed operators.
The team conducted interviews, reviewed resumes; and observed shift operating activities with unit operators (UOs), assistant unit operators (AUOs),
assistant shift operations supervisors (ASOSs), shift operations supervisors (SOSs), shift technical advi'sors (STAs),
and the Operations management st'aff.
Browns Ferry had six SOSs, 22 ASOSs, five Shift Support Supervisors (SSSs),
'nd 32 UOs with active licenses staffing six 8-hour shifts.
In addition, six other SOS-qualified personnel were assigned Unit 3 outage responsibilities on each of the six groups for shift coverage.
Also, additional personnel with inactive senior reactor operator (SRO)
and reactor operator (RO) licenses supported the shifts.
'Browns Ferry used degreed, primarily SRO-licensed, ASOSs with 'additional STA training to staff an STA position on each shift.
A total of 53 AUOs gave each shift crew a sufficient number of non-licensed operators capable of simultaneously supporting the fire brigade and safe shutdown of the plant.
Operations management had maintained a regular rotation of the operating crews through each unit.
Consequently, the crews had maintained operational proficiency.
In addition, each shift was assigned a shift mentor, possessing previous startup and dual-unit experience, to continuously monitor control room activities and give the crew and management independent comments and recommendations.
The staffing and qualifications of Operations exceeded Technical Specifications, requirements and the minimum licensed operator staffing requirements of 10 CFR 50.54(m).
There were sufficient personnel in both
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operational performance and management roles.
The extensive operating experience at Browns Ferry of key Operations supervisors (typically more than 10 years of licensed experience at Browns Ferry),
was considered a strengt.2 OPERATIONS PERSONNEL TRAINING The team assessed the training programs for operations personnel.
All of Browns Ferry Nuclear Plant's training programs were accredited and used a
systems approach to training.
The.team reviewed the training records for Operations Department management and licensed operators, and interviewed operators, training management, and instructors.
The team observed classroom training and simulator training for licensed operators and on-the-job training for non-licensed operators.
The simulator and classroom training were determined to be both comprehensive and challenging, and operator interaction in training demonstrated control room formality, system knowledge, and the ability to respond to abnormal plant conditions.
As evidenced by their high pass rates on licensing examinations an'd as demonstrated by their good performance in event response and simulator exercises, operators were very knowledgeable.
4.3 PROCEDURE ADEQUACY The team reviewed approximately 40 operati'ng procedures to assess whether they were accurate, provided sufficient operator information, were clearly written, and could be followed, and to assess their technical adequacy.
Generally, the operating instructions (OIs),
abnormal operating instructions (AOIs), emergency operating instructions (EOIs), surveillance instructions
. (Sis),
alarm response procedures (ARPs), technical instructions (TIs),
and site specific procedures (SSPs)
were considered to be satisfactory.
However, some procedure problems were identified.
For example, the team noted three cases in which inadequate procedures contributed to performance errors.
(1)
During troubleshooting activities on the reactor protection system, the team observed that operators temporarily lost RHR shutdown cooling.
The event was properly reported to the NRC, although the safety significance was low, since no nuclear fuel was in the reactor vessel at the time.
The problem was caused by Work Order 95-18774-00,
"RPS Troubleshooting Proposed Plan'f Action," which did not include instructions to install a jumper and prevent the closure of valve 3-FCV-74-67, RHR LPCI Inboard Isolation Valve.
The licensee initiated PER 951505 to determine the root cause and corrective action for the error in the troubleshooting plan.
The team noted that prompt operator action to manually trip the operating RHR pump prevented damage to the pump and motor from operating without any flow path (the minimum flow path was inhibited. at the time of the event).
Had there been no op'erator action, the affected RHR pump would have cavitated.
(2)
During testing of the high pressure coolant injection (HPCI)
system, the team observed that the HPCI,turbine did not manually trip when the operator depressed the manual trip push button
located on the control room panel console.
Operating Instruction 3-0I-73,
"High Pressure Coolant Injection System,"
Revision 0, Illustration I, "HPCI SYSTEM ISOLATION LOGIC LEAD LIFTS UNIT 3,"
did not contain sufficiently detailed instructions to properly perform wire lifts required for the test, contributing to a performance error.
Operations personnel lifted leads on the wrong side of the terminal block, de-energizing a group of functions rather than the one intended.
One function inadvertently defeated was the manual pushbutton trip for the HPCI system steam-'driven turbine.
The error also rendered some other HPCI system logic-related components inoperable.
The licensee initiated PER 951473 and took corrective action to revise the instruction.
A test instruction, Technical Instruction 3-TI-343,
"HPCI Injection Flush," Revision 0, Step 7. 13, stated,
"CLOSE HPCI PUNP CST TEST VALVE, 3-FCV-73-35."
The team observed that a licensed reactor operator did not perform the step as stated and left the valve partially open and continued with the next step.
The operator realized, during the performance of the test, that the instruction step should have been written to allow the affected valve to be throttled closed (as was done) to maintain the desired HPCI flow rate (flush) to the reactor pressure vessel and to preclude overfilling the reactor cavity.
After the test, the licensee properly initiated corrective action to revise the instruction discrepancy and wrote a test deficiency, Form SSP-98, for the lack of procedure compliance.
Although the procedure error did not have safety significance in this case, the error in the test instruction was not discovered before the test was performed.
The team considered that the three examples of procedure inadequacy discussed above constituted a deficiency.
(Deficiency 50-296/95-201-01)
4.4 PROCEDURE ADHERENCE 0,
The team assessed Operations shift personnel adherence to plant operating procedures.
The team observed how operators used procedures and interviewed several operators, licensed and non-licensed, to discuss the quality and use of the operating instructions and procedures.
The team observed that operators generally performed control room activities in accordance with approved, written procedures.
The team noted some examples of procedures and good practices not being followed.
One example is described in Section 4.5 of this report and involved logs not being kept in accordance
.
with procedures.
The team also observed isolated instances of poor operator practices.
For example, an operator performed the beginning-of-shift annunciator check so quickly that the operator missed two windows that did not illuminate.
Another operator was observed tapping on windows which had failed to illuminate, to see if they would light up.
This poor practice sometimes
results in the window lighting without having assured the functional reliability of the annunciator window.
Additionally, the team observed.
two instances in which AUOs did not follow good radiological control procedures.
In one case, an AUO did not report an alarming frisker to the Radiological Control Department until questioned by the NRC inspector.
In a second case, another AUO exiting the radiologically controlled area, removed his jacket prior to entering the personnel contamination monitor (PCH)
and did not" separately check the jacket for contamination before exiting.
The licensee initiated PER 951553 and took corrective action by counseling the individuals involved.
The examples of 'failure to follow good operator practices and good radiological control procedures was considered an observation.
(Observation 50-296/95-201-02)
4.5 SYSTEM STATUS CONTROL AND LOGS The team assessed the adequacy of control room log-keeping and system status control.
The team noted log-keeping practices during their round-the-clock control room observations.
In general, logs were correctly maintained and had an appropriate amount of detail.
All required routine readings were properly taken.
When readings were out of specification, the reasons were properly documented in the logs.
All required reviews were performed and documented by initials on the appropriate logs.
The team observed one area in which some operators were not logging occurrences as required by their procedure.
The licensee's Site Specific Procedure SSP-12. 1,
"Conduct of Operations,"
Revision 21, Section 3. 11.3, required specific information to be recorded.
'The team reviewed the entries in the licensee's official log, the Unit 3 Daily Journal.
.The team observed examples of operators not recording required information regarding (1) the instruction and section used to make operating status changes to safety-related and major plant equipment, (2) the initiation and completion of surveillance instructions and, 3) procedure numbers and problems encountered during testing activities.
The team observed four examples in which such events were not recorded in the Unit 3 Daily Journal.
The examples were:
On October 14, 1995, the Unit 3 emergency core cooling system (ECCS) Division I inverter deenergized because of=a blown fuse.
The event was not recorded in the log.
On October 13, 1995, Surveillance Instruction 3-SI-4. 1.A-ll(I),
"NSIV Closure-RPS Trip Functional Test,"
was initiated, but was not recorded in the log.
Additionally, an unexpected half-scram was received but was not recorded in the log.
On October: 13, 1995, 'operator action to manually secure a running RHR pump (to prevent damaging the pump since the minimum flow path was not available)
was not recorded in the log.
On October 7, 1995, an unexpected de-energizing of the 3AB 4KV shut down board was not recorded in the log.
The failure to log events in accordance with procedures is considered a
deficiency.
(Deficiency 50-296/95-201-03)
4.6 SHIFT ROUTINE AND TURNOVER The team observed shift turnovers during a 96-hour continuous control room observation as well as during several additional shift turnover meetings.
The shift turnovers were structured, comprehensive, and well controlled.
The SOSs and ASOSs arrived before the scheduled shift turnover meetings, giving themselves time to review all items on the turnover checklist.
The turnover sheets gave details about such items as surveillances due, applicable Technical Specifications limiting conditions for operations (LCOs),
system configuration status, and system maintenance in progress.
The turnover meetings were conducted 'in a formal manner, and all appropriate material was reviewed and discussed.
All LCOs and night orders were read aloud, and upcoming tests and activities were reviewed.
After the meeting, the formal watch relief, including panel walkdowns, took place.
The operators walked the control panels with their reliefs and briefed the oncoming watch of continuing activities and anticipated actions for the shift.
During routine shift observations, the team observed good communication and coordination among the shift operators.
Operators responded promptly to annunciators and off-normal conditions.
Operator knowledge of systems status was generally very good.
The operators demonstrated proper communications and conducted control room activities in a professional manner.
Communications with other departments were clear and professional.
4.7 RESPONSE TO ANNUNCIATORS AND OFF-NORNAL CONDITIONS The team assessed operator response to control room annunciators, alarms, recorders, and off-normal conditions.
The team observed that operators promptly acknowledged and called out alarming annunciators and subsequently received confirmation from their shift supervisors as required by their procedures.
For unexpected alarms, operators properly referred to annunciator response procedures and performed required steps.
The team observed good operator response to an off-normal condition.
An RHR LPCI injection valve unexpectedly closed, and a potentially pump-damaging no-flow condition occurred.
The operator quickly recognized the condition and took appropriate action to prevent damage to the pump.
The team noted that the licensee had a good method for tracking standing alarms.
The annunciators that remained in an alarmed condition and the reasons for alarm were kept on a computerized list.
An updated list was provided as part of shift turnover.
The team considered the licensee's tracking method to be a strength.
4.8 TECHNICAL Specifications LCO TRACKING AND CONTROL The team assessed Operations Department tracking and control of Unit 2 and
Technical Specifications limi.ting conditions for operations (LCOs).
The team reviewed the procedures that tracked the status of Technical Specifications LCOs.
The procedures required that LCOs be tracked by the STAs.
The STAs received information regarding the LCO status of safety systems from the SOS, ASOS, UO, and the Work Control group.
-The SOS was responsible for operability determinations and entry or exit from LCOs.
The team considered that the LCO tracking program was adequately implemented by the licensee.
Operators were knowledgeable of Technical Specification LCO tracking and control. process.
4.9 HOUSEKEEPING AND MATERIAL CONDITION The team assessed Unit 3 plant housekeeping and material condition during plant tours and during system walkdowns.
The team observed that Unit 3's housekeeping and material condition was
. generally very good except for minor areas in which work activities were in progress.
Labeling and tagging were good throughout the plant, and systems were properly aligned.
4. 10 CONTROL ROOM DECORUM AND PROFESSIONALISM The team assessed control room decorum and Operations personnel professionalism during the round-the-clock shift monitoring.
The team considered the control room decorum and professionalism to be good.
Access to the control room operating areas was strictly controlled by shift personnel'o exclude workers not directly involved in ongoing or planned activities.
All licensed and non-licensed shift operators conducted duties professionally and exhibited good morale.
The activity levels in the Unit 3 control room were considered to be fairly high preceding fuel loading, but
,decreased after fuel load began.
4.1'1 REPORTABILITY REQUIREMENTS AND IMPLEMENTATION The team evaluated the licensee's implementation of reporting requirements by observing the licensee's response to reportable events that occurred during the inspection.
On two separate occasions during'the inspection; the licensee made reports to the NRC.
" In one case a four-hour report was made per
CFR 50.72(b)(2)(ii)
due to an inadvertent. loss of RHR shutdown cooling on Unit 3.
Also a one-hour
report was made per
CFR 50.72(b)(l)(ii)(B) on a fire protection issue.
The licensee reports were timely and conservative.
4. 12 OVERTINE CONTROLS The team evaluated the control of overtime in the Operations Department and reviewed operator overtime records.
The team noted that operators worked a large amount of overtime.
However, the licensee controlled the overtime properly in accordance with plant procedures and authorized excess overtime requests properly.'he large amount of overtime was caused by the high level of activity associated with the efforts
on Unit 3.
No operator performance issues related to excessive overtime were identified.
4.13 POST-TRIP REVIEW PROCESS The team evaluated examples of Unit 2 trip events'and the associated post-trip review process.
The team examined Unit 2 trip events by reviewing licensee event reports and post-trip logs.
Management involvement in each restart was in accordance with applicable procedures with proper authorizations implemented.
The team did not assess Unit 3 examples since the reactor was not operating.
4. 14 CONCLUSIONS The team concluded that Operations staffing and qualifications were adequate for two-unit operation.
The team considered that licensed operators were professional, knowledgeable, and well trained.
Plant procedures were adequate, although some deficiencies were observed.
Procedure adherence was generally adequate, although an example of failure to follow the procedure for logs was observed and some examples of poor practices were observed.
Routine shift activities and shift turnover briefings were well conducted.
Operators were responsive to control room annunciators, alarms, and off-normal conditions, and were knowledgeable of applicable Technical Specifications LCOs.
The housekeeping and material condition of turned-over systems and areas were good.
5. 0 MAINTENANCE 5.1 ORGANIZATION AND STAFFING The team examined the organization and staffing of the Maintenance Department to assess its readiness for operation of two units.
Maintenance staffing of 252 craft was adequate, as compared to the size of maintenance organizations at other two-unit sites, and as evidenced by the licensee's success in reducing maintenance backlogs.
Maintenance personnel worked both the operating and shutdown units and had, therefore, maintained familiarity with work on an operating unit.
5.2 SELF-ASSESSMENTS The team reviewed approximately 25 assessments of maintenance.
The review included self-assessments and assessments performed by outside organizations.
The assessments were consistent and identified the need to improve procedure adherence and procedure quality-.
The assessments also identified that imprecisely written procedures and work orders sometimes contributed to the lack of procedural adherence.
In addition, the assessments identified that corrective actions had not been fully effective.
The team likewise identified widespread but minor procedure and work order problems during the observation of in-process work and the review of completed work packages.
The team observed cases of work orders not being carefully written and containing requirements that were not applicable (such as radiological controls for nonradiological jobs),
cases of vendor manuals not being referenced, cases of whole complex procedures being listed rather than the limited sections of the procedure that applied to the job at hand, and cases of procedure steps not being properly sequenced.
The team noted that licensee management was well aware of the problem. 'he licensee report, PER 940298, issued on June 30, 1994, addressed general procedural adherence problems.
The PER was considered a significant issue and had been escalated to the site vice presidential level.
A equality Improvement Team ((IT) had been implemented as one of the PER's corrective actions.
Licensee management continued to take actions to improve procedure adherence and quality.
The licensee concluded that procedure adherence and quality were adequate for restart, but not at the level desired to meet their performance goals.
The team concluded from its discussions
'with maintenance personnel, document reviews, and observations that the licensee had properly assessed the problems with procedure adherence and quality and was taking appropriate actions.
5.3 REVIEN OF COMPLETED CWORK PACKAGE RECORDS The team reviewed 36 completed work packages to'ssess whether there had been appropriate planning and approvals before implementation, whether required materials were utilized, whether all measuring and test equipment (M8TE) was calibrated and listed, whether a'll work and post-maintenance testing (PMT) was performed in accordance with procedures, whether the proper procedures had been specified, and whether proper reviews had been performed for closing work packages.
Overall, the majority of work packages reviewed were satisfactory, acknowledging the fact that there were the widespread minor work order and procedure problems previously discussed in Section 5.2 of this report.
The team identi.fied some discrepancies in the work package review.
The team observed three examples of failure to perform proper final reviews of work orders (WOs)
as required by procedure SSP-6.2,
"Maintenance Management System,"
Revision 16, Section 3.24.B, which required that general foremen review a final work record and verify that all required data were completed and present in the record package.
The examples were in WOs 95-01490-00 (a
i work step was not initialed), 95-06712-(
2-00 (work documentation was missing),
recorded as 30 seconds 95-16746
{a timing relay's range was erroneously recor e
as s
.
Althou h the examples were not significant errors, su ervisory reviews should have been the team considered that the craft and supervisory revie h.
The licensee agreed that the reviews were no d 951507 t ensure that appropriate corrective issued PERs 951499, 951901, an
action would be taken.
During the work package record review, the team observed one example of a failure to follow the maintenance procedure.
Licensee proce ure, I-0-085-PHPOOI
"Control Rod Drive Hydraulic Pump-bl II Morthin ton
MT 810, Disassembly, Inspection, Rework, and Reassem y,
Revision
was invoked in MO 93-00980-01 and sperified an acceptance h t 0.025 inch gap between the balancing disc and the disc head of the control rod drive hydraulic pump.
The craft r g
ecorded a
ap of 0.010 inch, which was not within the acceptance criteria.
The entry was made with a note which stated
"per factory rep and (name)
(System Engineer)
set at 0.010 inch clearance."
The team noted that the gap acceptance criterion had been effectively revised without processing a procedure change.
d SSP-2.
"Site Procedures Program," Revision 12, required personnel to follow procedures as written or to obtain a proced g
ure chan e before conti nul ng.
The new acceptance criteria were technically satisfac y
tor and the maintenance rocedure and the vendor manual were subsequently changed to reflect the new acceptance criteria in April 1995, approximately one month after the work was completed and the work package accepted, and well before the team's observation.
However, the craft should have stopped work and obtained a
d h
t the time the work was being performed.
Consequently, subsequent to the team's observation, the licensee issued PER 9514 97 to document the noncompliance with SSP-2. 1.
The team also identified an example of a, weak procedure.
Licensee maintenance-57859-01 re uired,the d
HCI-O-OOO-PCKOOI, "Generic Naintenance Instructions for Valve Packing," Revision 3, Step 7.7. 1, invoked in MO 92-
-
,
q
'raft to record the maximum and minimum torque values that were applie to e
packing gland in a core spray check valve.
However, the team noted that no torque value was recorded but rather an "N/A" was recorded at this step.
A h d b dd d stating
"snug tight,per (engineer's name).'"
Although a
place was provided to record the torque applied, the maintenanc p
t
'f th amount of torque.
The engineer had verbally specified
"snug t't" as the proper value.
The team considered that the craft should have lg as stopped work and obtained a procedure change, in accordance w'th their requirements, prior to tightening the packing.
AFter discussions with the team, the licensee drafted a revision to procedure HCI-0-000-PCKOOl which specified
"snug tight"as the proper value.
After reviewing completed work orders, the team concluded that all work reviewed was technically acceptable.
Examples were identified of craft and u ervisory personnel not complying rigorously with administrative requirements for procedure changes and record reviews.
yp These t es of problems were well known to licensee management and were being adequately
addressed, as was discussed in Section 5.2 of this report.
However, the failure to follow maintenance procedures, was considered a deficiency.
(Deficiency 50-296/95-201-'04)
5.4 OBSERVATION OF IN-PROCESS WORK The team observed six in-process maintenance activities.
The-quality of work performed was good.
Craft briefings were generally thorough.
Craft personnel were qualified and demonstrated an adequate technical knowledge of the equipment and the maintenance activities.
Craft utilized and documented proper material and measuring and test equipment; Craft were observed to be conscientious about cleanliness, housekeeping, material handling, and safety considerations.
In general, supervision performed adequate pre-job briefings and was involved in ongoing work activities.
Communications between maintenance and other organizations was effective.
Foremen and craft properly documented problems on Problem Evaluation Reports or guality Control Inspection Reports.
The team observed some poorly written procedures and work orders.
The errors were minor and did not cause unsatisfactory work.
The types of errors observed were common in both the work and records reviewed by the team and were the types of errors the licensee was working=to correct, as was previously discussed in Section 5.2 of this report.
Although the errors were minor, they demonstrated a lack of rigor in procedure and work order preparation.
Examples included:
.(I)
During the assembly of a mechanical seal for a Unit 3 recirculation pump per WO 95-02248-00, the craft torqued a tube connector nut to 64 inch-pounds rather than 40 to 43,inch-pounds as specified by the procedure.
The problem occurred because the sequence of steps in the procedure
'was not'ompatible with the sequence dictated by the hardware.
The tube connector nut is physically before the capscrew.
The craft tor qued the tube connector nut to the capscrew value because the capscrew torquing instructions came first in the procedure.
The craft recognized the error, and a guality Control Inspection Report was written to document the overtorquing.
Subsequently, an engineering evaluation was performed which concluded the. as-left value acceptable.
(2)
The same procedure contained other minor weaknesses and errors.
Examples included a step which referenced the wrong attachment number, a
step which required a dimension to be measured but did not give enough information to determine what was to,be measured, steps which did not provide acceptance criteria, and steps which did not provide spaces for required data entries and signatures.
Subsequent to discussions, the licensee issued PER 951566 to ensure that proper corrective action was taken.
(3)
Likewise, the work order had minor weaknesses.
The WO did not specify the applicable steps in the pump overhaul procedure for the seal assembly.
The pump procedure had a much broader scope and included many diverse tasks.
Selection of the applicable procedure steps was left for the craft to determine rather than'eing determined by planning and
craft supervision.
This observation was common for the majority of work orders reviewed.
Additionally, the team observed examples of personnel not adhering to procedures or work orders.
The errors observed were minor and did not result in unsatisfactory work.
The types of errors observed were common in both the work and records reviewed by the team and were the types of errors the licensee was working to correct as was previously discussed in Section 5.2 of this report.
Although the errors were minor, they demonstrated a lack of rigor in procedure adherence.
Examples included:
(1)
A troubleshooting job in which the craft did not follow the WO requirements and the work package lacked required information.
The job involved troubleshooting efforts on a Unit 3 reactor protection system regulating transformer performed per MO 95-16492-00.
The MO only permitted adjustment of connections and replacement of printed circuit boards.
While troubleshooting, the craft replaced a solid-state device which was not authorized by the MO but was the source of the transformer problem.
An unsuccessful retest of the transformer revealed that the replaced device had been installed improperly.
Additionally, the team noted that the vendor manual for the transformer was not included in the work package, as was required by the licensee's procedures.
The vendor manual gave specific instructions for replacing of the solid-state device which, if followed, would have prevented the improper installation.
(2)
A pre-job briefing for a high-risk job involving the potential for a scram which was not detailed as required by licensee procedures for high-risk jobs.
Procedure SSP-6.2,
"Maintenance Nanagement System,"
Revision 16, Step 3. 17.N.2, required that a detailed pre-job briefing be held for high-risk activities and that the briefing"include expected plant responses and special preca'utions or limitations on activities.
Licensee personnel stated that the briefing was not detailed because the job was a duplicate of work done on a similar component the preceding day with the majority of the same crew.
Nonetheless, the second briefing did not contain'he attributes required by procedure.
The licensee concur red that the briefing was not conducted as required.
PER 951558 was written t'o document the problem and ensure that any required corrective action would be taken.
The team concluded that maintenance work was being properly performed although some poorly written procedures and work orders were observed.
5.5 MATERIAL AVAILABILITYAND PARTS CONTROL The team examined the availability of, and controls for, materials.
To assess availability, the team examined open work orders to determine how many were constrained by a lack of material.
The licensee had 1324 open MOs for Units
and 3 on October 13, 1995; only about 10 per cent had material restraints.
However, discussions with maintenance personnel indicated that a material availability problem existed and had an impact'on the Haintenance Department's ability to provide parts for emergent work orders in a timely manner.
The
availability problem stemmed from a licensee initiative to ensure that all material used had the proper pedigree and supporting documentation.
Engineering had reassessed and reassigned higher quality levels for a large.
number of components and assemblies.
The change in quality level did not apply to all the subcomponents within the assemblies.
Consequently, all subcomponents had to be evaluated and assigned the proper quality classification before use.
Three PERs (940336,'940451, and 951165)
were written to document parts upgrade problems.
One of the corrective actions for PER 951165 was to place a hold on a large number of the components in the warehouse pending a review by the Performance Engineering Group.
The team considered the licensee's initiative to be in the interest of safety.
The
.
resultant material availability difficulties were compensated for by a good deal of material expediting activities.
The licensee's component unavailability trending data demonstrated that component availability was adequate.
The licensee also identified an additional problem affecting material availability.
Bills of materials for components were not available for much of the older equipment.
The problem applies to several TVA sites and is not unique to Browns Ferry.
The licensee initiated a three year program to correct this deficiency..
The first phase incorporated the most critical items and was scheduled to be completed by the end of February 1996.
The bill of material problem also required additional material expediti'ng.
The team concluded that parts control and material availability were adequate although a good deal of material expediting was required to provide material
.in a timely manner.
5.6 WORK SCHEDULING AND PRIORITIZATION The team reviewed the licensee's 12-week rolling maintenance schedule for Unit 2 and unit-common work activities.
The schedule had been in use for only a short time, and was in the second 12-week cycle.
The schedule was structured to perform the required surveillance tests, and corrective and preventative maintenances, for one safety division of a system in a specified but repetitive week.
The schedule alternated units weekly and divisions biweekly.
The 12-week rolling schedule method was a common licensee tool for planning work.
Unit 3 work and.testing were being folded into the schedule as the Unit 3 systems were completed and turned over to operations.
The licensee pl'armed to have the Unit 3 work and testing fully integrated into the schedule by the
'ime commercial operations began.
Additionally, the licensee had developed, and was using, a risk assessment matrix for on-line maintenance.
The matrix had been developed for the conditions of Unit 2 in operation and Units 1 and 3 in outage.
The licensee had prepared a draft matrix for Units 2 and 3 operating and Unit I in outage.
The draft was scheduled to become final before startup.
The matrices were developed using probabilistic safety assessment evaluation techniques and were utilized in the development of the 12-week schedule.
The team reviewed the licensee's procedure for the prioritization of work, Appendix B of SSP 7. 1,
"Work Control," Revision 14.
The procedure was written
~
for the condition of Units 1 and 3 in outage and Unit 2 in operation.
The licensee planned to incorporate the condition of Unit 3 in operation before restart of Unit 3.
The team reviewed planned and ongoing work activities and did not observe any examples of improper prioritization.
5.7 NAINTENANCE BACKLOG The team examined the licensee's control of maintenance backlogs.
On September 17, 1995, Unit 0 (common)
and Unit'
had an open MO/work request (MR) backlog of 1965 items.
Unit 3 had a backlog of 687 items on turned-over systems.
The team observed that the backlogs for Units 0 and 2 had steadily decreased while the backlog for Unit 3 had increased.
However, the Unit 3 increase was expected as systems were turned over.
The licensee planned to have a Unit 3 backlog at restart of approximately 600 WOs, which the team considered reasonable.
The team reviewed the work which the licensee intended to defer until after restart of Unit 3.
The team noted no items which they considered necessary to be completed prior to restart.
The team also reviewed the issue status of maintenance procedures and determined that there were no overdue procedures.
The team concluded that the maintenance backlogs were manageable, were properly prioritized, and that the licensee backlog for restart was reasonable.
'.8 FAILURE TRENDING AND PREDICTIVE MAINTENANCE Procedure SSP 6.4,
"Equipment History and Failure Trending," Revision 7, described the failure trending program.
The licensee methodology used closed-out WOs as the source of trending data.
Honthly, the licensee issued a
repetitive failures report which listed all components which had received corrective maintenance, for any cause, twice in a two-year period.
Semiannually, the licensee issued another report which identified the components which had two or more common-cause failures in a two-year period.
The licensee compared their failure rate data to the rest of the industry's failure'ates using Nuclear Plant Reliability Data System (NPRDS) data and wrote PERs when appropriate.
The licensee's process required the maintenance foreman to assign 'the proper failure cause code during the MO closure process.
The team noted cases in which the cause codes listed were not consistent.
The licensee agreed and stated that maintenance foremen would be given additional training in cause determination.
5.9 TRAINING The team was unable to observe any maintenance training; none was scheduled because of the activity level associated with the scheduled fuel load.
However, the team did examine the training facility and considered it
. adequate.
Licensee procedures indicated that the craft were qualified for
specific job tasks by hands-on performance testing.
The team's field observations of maintenance work indicated that training was effective.
The licensee's procedures required, and the training staff confirmed, that continuing training for the craft consisted of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of classroom training per year plus any required special training.
The team observed a special training session that focused on unit differences.
The training was detailed and considered to be a good licensee initiative to prepare personnel for two-unit operation.
5. 10 CONCLUSIONS The tea'm concluded-that the conduct of maintenance at Browns Ferry was adequate for the restart of Unit 3.
Organization and staffing were adequate.
Licensee assessments of maintenance were thorough and identified areas needing improvement but concluded that Maintenance was ready for dual-unit operation.
Licensee actions to correct areas needing improvement were appropriate.
The team reviews of completed and ongoing work concluded that craft were skilled and knowledgeable.
The team's review also confirmed the licensee's findings of widespread but minor problems with procedure and work order accuracy and rigor in procedure compliance.
The team concluded that material parts control and availability were adequate, although a good deal of material expediting was required due to problems the li'censee had identified and was resolving.
The team considered that work scheduling controls and backlogs were adequate.
6.0 SURVEILLANCE TESTING
'6.1 TEST PERSONNEL The team reviewed the training records of several people on the maintenance staff who had performed surveillances which the team had observed.
~
The licensee's maintenance training program included training for performing surveillances.
The team reviewed the TVA Maintenance training procedures for electrical, mechanical, and instrumentation and controls staff.
The team considered that the training was satisfactory.
The craft received classroom training and were evaluated in hands-on training situations.
In field observations, the team observed maintenance staff perform surveillances correctly.
The team reviewed the qualification records of several operators and auxiliary operators and verified that they were qualified to operate the equipment specified in the surveillances observed.
6.2-"-
PROCEDURE ADHERENCE, ADEQUACY, AND PERSONNEL'PERFORMANCE The team observed the performance of ten surveillances and reviewed the records of 24 completed surveillance instruction (SI) tests.
The tests observed were performed properly and the test results were technically accurate.
However, minor discrepancies were noted which demonstrated that rigor in procedure adherence and attention to detail in procedure preparation could be improved.
The team observed the performance of ten tests, eight performed by Instrumentation and Controls (ILC) and two by Operations.
In some cases, the procedure was being performed for the first time and procedure accuracy was being validated.
The validation process verifies that the procedure can be performed as written.
The process allows on-the-spot corrections and the corrections are incorporated in a subsequent change to the procedure.
The'eam noted that the test crews identified an unusually large number of minor discrepancies during the validation which suggested that attention to detail in procedure preparation could be improved.
The team also noted, in several instances, that previously validated test procedures still contained minor typograph'ical errors suggesting that validation could be more rigorous.
The observed deficiencies were not significant and included the absence of verification blocks where required, and conversely, the presence of verification blocks when not required.
The team reviewed the records of 24 completed surveillance tests for proper test results, proper acceptance criteria, and proper test intervals as specified in the Technical Specifications.
The review results were satisfactory.
Only a few surveillances required schedule extensions and all tests were performed within the allowed grace periods.
6.3 TEST SCHEDULING The team reviewed procedure SSP-8.2
"Surveillance Test Program," the controlling document for the surveillance test schedule.
The procedure adequately implemented the Technical Specifications requirements for surveillance test frequency.
Additionally, the surveillance tests had been
"incorporated into the 12-week rolling.schedule discussed in more detail in Section 4.4 of this report.
6. 4 CONCLUSIONS The team concluded that surveillance testing was properly scheduled and performed.
Test personnel were properly qualified.
Procedures were adequate, although they contained minor typographical errors that were not corrected when the procedure was validated.
7.0 SAFETY ASSESSMENT AND EQUALITY VERIFICATION 7. 1 OVERSIGHT CONNITTEES The team examined the onsite and offsite safety review committees that provided the safety oversight of plant operations.
The Technical Specifications delineated the 'function, composition, responsibilities, authority, meeting frequency, and quorum requirements for the on-site Plant Operational Review Committee (PORC).and the offsite Nuclear Safety Review Board (NSRB).
The team reviewed the minutes of the first quarter 1995 PORC meetings, and observed a
PORC meeting on October 12, 1995.
The team observed good
interaction between the presenter and the PORC members at the meeting.
The team verified that the quorum requirements in the Technical Specifications were met.
The team reviewed the minutes of the previous three NSRB meetings (meetings 269, 270 and 271).
The minutes demonstrated that the NSRB was recommending improvements in areas of plant safety.
The reactor safety engineering and review (RSER) group provided the independent safety engineering group (ISEG) function at Browns Ferry.
The team reviewed six reports prepared by the RSER group during the third quarter of 1995, and interviewed the RSER supervisor.
The review indicated that the RSER was involved in a broad spectrum of activities that included weaknesses such as procedure adherence problems, potential safety issues such as the effects of a loss of shutdown cooling and industry initiatives.
The RSER also reviewed the schedule of plant activities for risk considerations and impacts on plant safety.
Other RSER activities included developing a review plan for Unit 3 power ascension testing and introducing the use of a computerized risk evaluation program for outage risk assessment.
The team reviewed an RSER evaluation of several operational events at Browns Ferry.
The evaluation assessed the adequacy of the corrective actions proposed by line management.
The review recommended additional corrective actions beyond those originally approved by line management.
The team considered the evaluation to be appropriately critical.
7.2-EQUALITY ASSURANCE INVOLVEMENT The team assessed the involvement associated with and the effectiveness of the quality assurance (gA) and quality control (gC) program.
The team observed gA and gC activities and reviewed procedures and reports to assess the effectiveness of the program.
The gA program was described in Procedure SSP-3. 1, "guality Assurance Program," Revision 8.. Additionally, Technical Specifications Section 6.5.2.8 provided the requirements for the auditing of specified activities.
The gA organization used several verification elements to provide assurance that activities were being appropriately performed.
The veri'fication elements were audits, assessments, observations, monitoring, and inspections.
The team reviewed the licensee's audit plan for 1994 through the second
'quarter of 1995 and determined that the audits met the technical specifications requirements.
The team also reviewed the gA'udit and assessment log, five assessment reports issued during the third quarter of 1995, and four audit reports issued during 1994 and 1995.
The team noted that the assessments were appropriately focused in previously identified areas of weakness or areas with negative trends.
The team noted that the assessments were appropriately critical, identifying adverse trends and recommending increased management attention when needed.
The team noted that either immediate corrective actions were taken or PERs were issued to resolve the audit findings and implement corrective actions.
The team observed two QC inspections.
The QC inspectors were thorough and systematic in performing inspections.
When the QC inspectors identified unsatisfactory conditions, they properly wrote QC deficiencies.
The team observed portions of a QA surveillance of Unit 3 control room activities in preparation for fuel loading.
QA management planned to observe control room activities around the clock during fuel load.
The team concluded that the QA plan was a good initiative and noted that the QA inspector was performing the surveillance adequately.
On the basis of observations of activities and meetings, reviews of. reports, and discussions with QA personnel, the team concluded that QA/QC staff had.
adequate access to upper. management and identified meaningful issues to them.
7.3 CORRECTIVE ACTION PROGRAH
, The licensee's corrective action program was described in procedure SSP-3.4,
"Corrective Action Program,"
Revision 14.
The procedure described a process for identifying problems, and provided for adequate management review, timely determinations of operability and reportability, and initiation of corrective actions.
The licensee's problem reporting form is called a problem evaluation report (PER).
PERs are categorized at four different levels depending on safety significance, adverse trends, and generic applicability.
PERs were incorporated into a data base for tracking and trending purposes.
The team reviewed
PERs at various stages of completion, and concluded that the threshold of problem reporting was adequate, that the problem reports were
'ppropriately prioritized and dispositioned as required by the procedure, and that the root cause and causal factor analyses were adequate.
The timeliness of resolution was generally adequate, and NRC notifications and operability determination were made when required.
In Hay 1994, the licensee consolidated several. deficiency identification programs into the new Problem Evaluation Report (PER) program.
Licensee management lowered the threshold for reporting problems and adequately communicated management's desire to have problem areas reported.
The new PER program resulted in a large increase in the number of corrective action documents generated in 1995 compared to the previous ye'ars (e.g.,
256 generated in 1994 versus 1612 generated in three quarters of 1995).
The team considered this to be a very positive initiative on the part of management.
The team noted that procedure SSP-3.4 required that a Hanagement Review Committee (HRC) review the PER, assign a significance level (A through D),
and designate the responsible organization for root cause determination and corrective actions.
The team attended two HRC meetings.
Although not required by procedure, the team observed that maintenance and radiation protection were represented on the committee.
The licensee stated that, although a minimal HRC makeup was specified in the procedure for flexibility, the HRC, as a practice, would not review a
PER without appropriate functional area representation.
The team concluded that the HRC review process for PERs was a positive initiative which ensured active 'management involvement in the corrective action program,
The gA Department had an independent review process to assess the adequacy of corrective actions for PERs.
A team member observed a gA PER review meeting.
The team member observed good questioning, and a broad perspective exercised in the review.
gA identified issues missed by the responsible organization (e.g.,
the need to review previous similar events)
and identified additional corrective actions.
The team considered the independent gA review to be'
positive initiative.
The licensee's program for Tracking and Reporting of Open Items (TROI) is a
computerized system that tracks corrective action commitments.
A monthly status report for September 1995 showed that,'n. most cases, corrective actions were completed on time.
The team concluded the overall timeliness of corrective actions was adequate.
The procedural requirements for the licensee's trending program were described in procedure SSP-3.8,
"Trend Analysis," Revision 3.
The procedure established the overall process for trending adverse conditions within the scope of the nuclear gA program., Multiple trend reports were required to be periodically generated, by gA and were used by management to assess performance.
The team reviewed (1)
an August 2, 1995, PER trend report, (2) the fourth quarter 1995 windows report, and (3) the July 1995 root cause and causal factors trend report.
The PER trend reports discussed possible causes for the trend and the corrective actions for adverse trends.
The team noted that procedure adherence had been identified as a weakness since the third quarter of 1994, and that five quality improvement teams had been formed to address the problem.
Although an improving trend was noted in this area, the report stated that the procedure compliance and the procedure deficiency areas still needed management attention.
Likewise, the July causal factors trending indicated the highest number of problems in the areas of work practices and written communication.
The team also attended a site trend review committee meeting.
The team concluded that the licensee's trending programs were-strong and provided valuable management inFormation.
7.4
.
ROOT CAUSE AND FAILURE ANALYSIS The team examined the licensee's root cause program for effectiveness.
Procedure SSP-12.9,
"Incident Investigation and Root Cause Analysis," Revision 12, provided instructions for conducting incident investigations.
Additional guidance was provided in procedure BP-236,
"Event Critique and Root Cause Analysis," Revision 0.
Procedure SSP-1.5,
"Human Performance Enhancement Program," also provided guidance for evaluating human performance.
The licensee's program required a formal root cause analysis for the more important PERs using one of the industry-recognized methods described in BP-236.
Also, procedure SSP-12.9 recommended that incident investigation team.
members be qualified in root cause analysis (RCA).
The team reviewed three incident investigations performed in 1995, and determined that the investigations met the guidelines of procedure SSP-'12.9.
The identified root causes and causal factors were reasonable.
The team noted a gA assessment describing a situation in which personnel assigned to determine the root cause of a reactor scram had not been trained in the
appropriate root cause methodology applicable to the event.
The licensee was in the process of ensuring that appropriate corrective action was being. taken.
On March 30, 1995, a Unit 2 reactor scram occurred due to a human error during a test and a
PER was written.
The team noted that the licensee's corrective action was to eliminate the test.
The test was an important test, although not a test required by the Technical Specifications.
The team considered the licensee's corrective action to be inappropriate.
The licensee stated that the PER had not been fully reviewed and that the test would not be eliminated.
The NRC resident inspector stated that the residents would follow up on this item.
The team concluded that the licensee had established an adequate program and adequate procedures for root cause evaluation, and the quality of the evaluations were generally adequate.
7.5 INDEPENDENT VERIFICATION POLICIES The licensee's requirements for independent verification are specified in procedure SSP-12.6,
"Verification Program,"
Revision 2.
The team's observation of licensee activities, including maintenance and surveillance testing, indicated that activities were adequately verified.
7. 6 CONCLUSION The team concluded that the licensee's safety assessment and quality verification program implementation was adequate.
Reactor safety engineering
'nd review group evaluations were appropriately critical and recommended corrective actions beyond those originally approved by line management.
gA was actively involved in critical activities such as fuel load, and gA staff
.had adequate access to upper management.
The new PER program encouraged the staff to report problems and led to a large increase in the number of corrective action documents generated.
The team considered this to be a very positive initiative.
The independent gA and management review processes for PERs were positive initiatives which ensured abundant and active gA and management involvement in the corrective action program.
8.0 FIRE PROTECTION PROGRAN The licensee's fire protection program was examined to verify that the licensee had properly implemented and maintained the fire protection program
,
required by the operating license.
8. 1 RE(UIREHENTS Operating License, OPR-68, Condition 2.C(7) requires, in part,, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report (FSAR) for the facility.
Section 10. 11 of the Unit 3 FSAR contains the licensee's commitments for the fire protection systems and fire protection program.
8.2 REVIEM OF FIRE PROTECTION PROCEDURES The team reviewed the licensee's approved program as defined in the FSAR for the facility.
The team reviewed the licensee's fire protection program implementing procedures which are contained in the licensee's Fire Protection Report.
The team's review of procedures determined that, overall, the procedures adequately implemented the approved fire protection program.
However, the team noted one procedure discrepancy.
The procedure initially used by operators, if a fire occurred, did not direct or reference a procedure which secured ventilation in the fire area.
Information Notice (IN) 89-52,
"Potential Fire Damper Operational Problems,"
had notified licensees about the failure of some fire dampers to close, if ventilation was not secured.
The licensee's Fire Hazard Analysis, Section 3. 1., defined a fire area.
It stated that,
"A Fire Area is defined as an area in the plant that is separated from other areas by boundary barriers (walls, floors, or roofs) with any openings or penetrations protected with seals or closures having a minimum fire resistance equal to the rating required of the barrier."
In fire area evaluations, the licensee st'ated that, for fire area isolation, "Fire dampers will isolate the HVAC [Heating, Ventilation, and Air Conditioning] ducts from the adjacent Fire'reas.
Procedures are in place to require the Control Room to initiate HVAC zone isolation when a fire is verified in an area.
This shuts down ventilation to the specific area and allows the dampers to adequately seal off the affected area."
The team noted that, the licensee's procedure O-AOI-30-1, "Fire Protection Ventilation Lineup," Revision 4, dated November 8, 1994, gave directions for securing ventilation when a fire was verified in a fire area.
The team interviewed four people who held, or formerly held, SRO licenses.
Three of them erroneously stated that procedure 0-AOI-30-1 was for smoke removal and the other one was uncertain when the procedure should be implemented.
The team noted that if a fire occurred, operators initially used procedure EPIP-21,
"Fire Emergency Procedure",
Revision I, dated July 6, 1995..
However the EPIP procedure did not direct operators to implement procedure 0-AOI-30-1 to isolate ventilation for the affected fire area.
The team concluded that procedures and training for securing ventilation in a fire area were inadequate.
This was considered a deficiency.
(Deficiency 50-296/95-201-05)
8.3 PLANT TOUR The team visually inspected various areas of the reactor building, control building, turbine building, intake structure, and diesel generator building and noted that housekeeping was well maintained.
No buildup of transient combustible materials was noted.
The team observed the following:
Fire protection equipment, such as hose reels, hoses, detectors, and fire extinguishers were in good material condition.
.27
Fire sprinkler systems and deluge systems'were operable and well maintained.
~
Emergency lights observed were available and in operable condition.
~
One fire extinguisher had no monthly inspection signoff on its tag.
The extinguisher was in a lay down area, and was not one of the wall-mounted extinguishers made available for general use.
As corrective action, the licensee immediately removed the out-of-date extinguisher from the building.
Four additional fire extinguishers had no monthly inspection sig'noffs on their tags.
These extinguishers were observed in the fire brigade's Emergency Equipment Cages I and 2 in the turbine building.
The licensee stated that the plant staff had temporarily placed the extinguishers in the cages during an area cleanup and had not been returned them to the tool room as intended.
The extinguishers were not staged for use and fire fighters would not have gone to the cages to obtain an extinguisher in a fire situation.
As corrective action, the licensee returned the extinguishers to the tool room.
The five fire extinguishers in question were all tool-room-issued equipment,.
and not permanently mounted fire protection equipment.
,The e'xtinguishers had been designated
'as lost on the licensee's status lists.
The team noted adequate numbers of operable fire extinguishers placed throughout all units.
The team concluded that the overall extinguisher control program was well controlled.
The team also concluded that the search for and return of lost extinguishers issued by the tool room for temporary use could be improved.
The licensee agreed.
During the inspection, the team observed discussions, regarding the program, between licensee fire protection staff and various other site personnel.
.The team noted that licensee fire protection personnel had a very good working relationship with other onsite organizations.
, Procedure SSI-16,
"Control Building Fire," Revision 0, lists equipment that may be required for safe shutdown during a control room fire.
The team randomly selected some of the equipment and verified it was accessible and well labeled, and that emergency lighting for using the equipment was adequate.
8.4 FIRE RESPONSE EgUIPHENT The team visually inspected the fire response equipment in Fire Emergency Equipment Cages I and 2.
The equipment was well maintained, accessible, within calibration, and in good working order.
The team performed a walkdown of the fire protection water supply system and the diesel building Cardox system.
All valves were properly positioned, and fire water pumps and other equipment were operable and well maintained.
8.5 THERMO-LAG 330-1 FIRE BARRIERS The team discussed the actions the licensee had taken to resolve Thermo-Lag 330-1 fire barrier issues generic to the industry.
Thermo-Lag 330-1 is a fire barrier material manufactured by Thermal Science Inc.
The licensee had the material installed in the intake structure as required by their analysis.
The licensee resolved the generic issue by ensuring that the Thermo-Lag material was installed in a configuration which had been qualified by a satisfactorily tested configuration.
8. 6 STAFFING The team reviewed the plant staffing for fire protection.
The licensee had sufficient engineers associated with the fire protection program.
Discussions with the engineers indicated that they knew the fire protection program and the National Fire Protection Association code requirements.
They also demonstrated a detailed understanding. of fire hazards associated with the station.
The licensee also maintains a dedicated fire brigade composed of full-time trained fire fighters.
.As a result of discussions with fire brigade personnel and a review of their training documentation, the team concluded that the fire brigade was well trained and capable of responding to a fire emergency.
The team considered that the onsite presence of a full-time fire brigade was a
significant program strength.
Browns Ferry is only one of a small number of licensees that devote the resources to maintain a full'-time dedicated fire
, brigade.
The dedicated fire brigade results in more rapid response to fire alarms with a sufficient number of well-trained staff to extinguish a fire in the incipient stages.
8. 7 TRAINING
~Fi Bi d
The team reviewed the fire brigade composition, qualifications, and training.
In.addition, the availability of manual fire fighting equipment and protective clothing was inspected.
The fire brigade staffed five full-time fire fighters per shift, a fire brigade leader and four trained fire fighters.
The fire brigade leader and at least two other fire brigade members were required to have sufficient knowledge of safety-related systems to understand the effects of fire and fire suppressants on safe-shutdown capability.
The team reviewed the fire brigade training records.
All fire fighters were trained in initial training classes and requalification classes.
In addition, practical fire fighting training was done by the Tennessee Valley Authority at its training facility.
The fire brigade performed quarterly fire drills and each member was required to participate in at least two drills annually.
The team verified that all fire brigade members took the required annual physical examinations.
The team's review of the training records indicated that the fire brigade members were well trained.
The team interviewed fire brigade staff and concluded they were knowledgeable about the fire brigade program requirements, specific locations of safety equipment in the plant, and the effects of fire on the safe-shutdown capability of the plant.
The team questioned a fire brigade leader about the use of water on an electrical cable fire.
The fire brigade leader had a very good understanding of the proper techniques for extinguishing an electrical cable fire.
The team visually inspected the fire brigade equipment necessary for fire fighting.
The fire equipment included personal protective equipment such as turnout coats, boots, gloves, hard hats, emergency communications equipment, portable lights, and portable ventilation equipment.
The equipment was well maintained, adequate for the intended use, and readily accessible to fire brigade members.
Licensee Personnel The team interviewed six licensee employees who were not directly involved in fire protection, to evaluate their knowledge of the fire protection program.
All personnel interviewed were familiar with their duties and responsibilities and with general program requirements.
8. 8 EQUALITY ASSURANCE 'AUDIT The team reviewed the quality assurance audits of the fire protection program.
Specifically, audits SSA 95005,
"Fire Protection Program (Triennial Audit),"
and NA-BF-95-034, "Appendix R Assessment,"
were reviewed.
These audits were comprehensive in scope and provided an in-depth evaluation of the fire protection and prevention program.
Discrepancies and opportunities for improvement were identified and the audit finding responses were tracked to closure.
The team concluded that the audits were effective and resulted in meaningful findings.
8. 9 CONCLUSIONS The team concluded that within the areas inspected, the licensee had an effective fire protection program.
The staffing of a de'dicated professional full-time fire brigade was a significant program strength.
The licensee had well-maintained fire protection systems and response equipment.
Licensee administrative controls were properly implemented.
The plant employees interviewed had a good understanding of program requirements.
guality Assurance was involved in fire protection activities and performed effective audits.
One deficiency was noted; the procedures and training for, securing ventilation in a fire area were inadequate.
9.0 ENGINEERING AND TECHNICAL SUPPORT 9. 1 ORGANIZATIONAL STRUCTURE Engineering activities took place in two departments:
(l)Engineering and'aterials and (2) Technical Support.
The Engineering and Materials Department prepared design changes notices (DCNs)
and performed the technical analyses to support the DCNs, prepared and updated drawings, provided technical assistance
to the plant, procured parts and material, and performed warehousing and material storage.
The Technical Support organization had plant system engineers and reactor engineers and was responsible for preparing surveillance test instructions and performing program oversight in containment integrity testing, ASME Section XI inservice testing, plant performance monitoring, and reactivity management.
Technical Support also participated in developing troubleshooting plan for maintenance activities:
Staffing within Engineering and Materials was at a sufficient level to have completed the design work for the 1996 Unit 2 refueling outage and the majority of the design work for Unit 3 restart'ffort.
Engineering and Materials management stated that long term staffing was forecast to decrease since the work load was expected to drop and a plan for budgeting the department's resources for expected emergent work had been developed.
Staffing within Te'chnical Support was adequate, although the team noted that a
good deal of overtime was being used in preparing for Unit 3 restart.
However, none of the. system engineers interviewed expressed a concern about how much overtime was being worked.
Technical Support management stated that no changes were anticipated in the basic stru'cture and staffing of the department.
The manager.'s expected the resources involved in Unit 3 recovery to be absorbed into the parent areas and contractor support to be reduced.
Engineering knowledge and experience levels were good.
Engineering had specialists in many areas, including pipe stress analysis, corrosion and hydraulics.
Engineering's ability to retrieve original plant design and
.construction documents from 1967 was very good.
Original analyses for the drywell head loading, performed by a contractor's engineering staff, were quickly located.
The inspector observed that an indication of adequate resources was the low drawing backlog.
Also, control room drawings were current to the proper.
revisions.
'.2 ENGINEERING PERFORMANCE To asses's engineering performance, the, team evaluated the group's engineering work products.
In the case of Engineering and Materials, the products were DCNs, analyses and calculations which supported modifications, plant drawings and drawing control, and control of procurement.
The team reviewed eight DCN packages with the responsible engineers, or peers, to determine the engineers'nowledge of the modifications, the validity of,the analyses performed, the completeness of the DCN records package, and the technical adequacy of the engineering work performed.
The modification and design change control program was controlled by approved plant procedures.
The team considered that modifications reviewed were generally technically and administratively correct.
The engineering design criteria reviewed were considered to be sound overall.
'However, the team identified two discrepant conditions;
(1)
The licensee had identified a drawing, which should have been updated as part of two DCNs, but had not been updated.
The drawing should have shown the elimination of a pipe cap on a containment penetration and the addition of a piping syst'm added by the first DCN.
The first DCN installed reactor vessel level instrumentation for shutdown conditions.
The piping was later modified again by the second DCN to add a reference leg back-fill system as recommended by the Boiling Water Reactor Owners Group.
All other piping drawings associated with the two DCNs were correctly revised to show the added piping.
The licensee discovered the drawing oversi.ght before the team's review and questions.
The Engineering and Material Department had reviewed the containment integrated leak rate test procedure to provide assurance that the procedure had included all required containment isolation boundaries.
During that review, the reviewing engineer
'had discovered the penetration drawing discrepancy and had completed a request for the drawing to be revised.
Engineering had begun drafting the drawing change during the inspection.
The team concluded that although the two.DCNs should have identified the need to change the penetration drawing, there was no technical consequence to the omission and the licensee's actions were appropriate.
(2)
The team identified a design criteria discrepancy, associated with the two DCNs discussed above, which. involved pipe break criteria.
The Browns Ferry pipe break design criteria discussed the methodology used to evaluate pipe rupture and missile generation.
The criteria were directed toward protecting the containment shell against the effects of pipe whip and jet impingement.
The 1'icensee had evaluated possible pipe break effects in a July 1, 1987, study.
The team observed that the design criteria document did not evaluate piping that terminated on the reactor vessel head.
This included a six-inch head spray line and a two-inch head vent line.
A postulated break of the'ead spray line at the reactor vessel head would have required restraining the pipe or providing an energy-absorbing crushable material on the containment shell to be in accordance with the design criteria.
Responsible engineering staff agreed that the piping connected to the reactor vessel head should have been evaluated.
However, the licensee
.
noted that the Unit 2 head spray line had been removed before Unit 2's restart and that the Unit 3 head spray line had been removed during the recovery activities for restart.
The licensee stated that Engineering would evaluate the reactor vessel head vent line.fully, but on the basis of a preliminary review; they had concluded that the head vent was sufficiently restraine'd and would not jeopardize containment integrity.
'he team considered that the licensee's preliminary assessment was technically reasonable.
The failure to perform a pipe whip evaluation for the reactor vessel head piping was considered an observation.
(Observation 50-296/95-201-06)
9.3 TECHNICAL SUPPORT GROUP PERFORMANCE The team examined the System Engineering group.
System Engineering was
'nvolved in system surveillance testing, prepared system status reports, provided support to the plant, and reviewed temporary plant modifications.
To assess system engineer involvement.and knowledge, the team discussed the system status w'ith the system engineers for the feedwater, extraction steam and heater drain, residual heat removal (RHR) service water, emergency essential cooling water, feedwater control, diesel generator, and primary containment isolation systems.
The team reviewed system performance trending to determine the validity of the data trended'.
The system engineers monitored and reported system trends.
The team noted that the level of formality varied.
For example, data on the extraction steam and heater drain system included turbine heat rates, feedwater heater shell levels, and flow rates.
The required trend data were documented on a form contained in a plant surveillance procedui e.
However, RHR service water system trending was documented by the system engineer on a
spread sheet which'as not described'n a procedure or in any other guidance document.
The absence of guidance would not necessarily result in poor trending; however, in a case observed by the team, the system engineer was trending data which was not meaningful to heat exchanger performance.
Although the heat exchanger performance trending being performed was not meaningful, the inspector noted that the licensee had committed to a different method of monitoring heat exchanger performance.
In responding to Generic Letter 89-13 on service water system performance, the licensee had committed to open, inspect, and clean the heat exchangers every refueling outage.
This method was acceptable to the NRC and was being adequately implemented.
In addition to the committed method, the system engineer was attempting to trend RHR heat exchanger performance by relating RHR service water flow to heat -exchanger fouling factor.
The relationship of flow rate to fouling factor was assumed to be linear and proportional.
A calculated fouling factor was then compared to an assumed fouling factor limit of 10 per cent.
The data were used to determine the RHR heat exchanger cleaning frequency.
As a result of the team's questions, Technical Support asked the Engineering and Materials Department to verify the validity of the assumed fouling factor.
Engineering determined that the allowable fouling factor for each RHR heat exchanger was not 10 per cent but rather was related to the total fouling of the two heat exchangers which made up one train.
Engineering concluded that if one heat exchanger had a fouling factor of 10 per cent, the other heat exchanger should only have an allowed fouling factor of 3 percent.
Also, the team considered that it was not valid to solely use system flow rate to assess the fouling factor, since the deposition of organic material on the tube wall would not significantly reduce flow area or flow rate, but would have a
significant effect on heat transfer.
Technical Support management acknowledged the problems with the system engineer's informal flow-based performance-trending method.
Management state that it would formalize a heat exchanger thermal performance trending method and was considering revising its generic letter commitment to periodically open and inspect the heat exchangers.
An additional system engineer activity was to provide technical assistance to the plant during operation and maintenance activities.
The system engineers interviewed by the team were knowledgeable about their systems and aware of temporary alterations that were in place on those systems.
The team reviewed several temporary alterations and concluded that they were'n accordance with procedures.
The team observed that some temporary test equipment used by the system engineers was not controlled by procedures.
The team observed some high impedance isolation devices which were stored in an engineer's work location.
The devices were used for troubleshooting activities on the main feedwater pump turbine speed control sensor.
The isolation devices were neither tested nor controlled by the plant's Measuring and Test Equipment (M8TE) program.
The isolation devices are ordinarily tested to assure that they had not lost their high impedance.
Although the test for high impedance was being performed by the system engineer and although the system engineer was very familiar with the design, operation, and maintenance of the device, the team considered the lack of formal control of the devices to be a potential problem.
The licensee agreed and stated that the devices needed additional administrative controls.
9.a COVCLuSIOVS Overall, the team considered Engineering to be a strong area.
Engineering staffing levels were good and engineering experience levels were a strength.
The design change process provided adeq'uate control of design and construction, and assured that design documents were updated.
Additionally, the team concluded that the Technical Support group provided adequate support and assistance to the plant, and that system engineers were knowledgeable and involved.
10.0 EXIT NEETING The inspection scope and findings were summarized on October 27, 1995, with those persons indicated in Appendix C.
The licensee did not identify as proprietary any of the materials provided to or reviewed by the team during the inspection.
APPENDIX A - DEFICIENCIES DEFICIENCY 50-296/95-201-01, Section 4.3:
Procedure Adequacy - Some operations procedures were not adequate.
Three examples were noted.
DEFICIENCY 50-296/95-201-03, Section 4.5:
Procedure Adherence - Failure to record required information in the control room log as required by procedure.
DEFICIENCY 50-296/95-201-04, Section 5.3:
Maintenance procedures were not followed.
DEFICIENCY 50-296/95-201-05, Section 8.2:
Procedure Adequacy-Procedures and training were not adequate to ensure fire dampers would close in a fire are APPENDIX B <<OBSERVATIONS OBSERVATION 50-296/95-201-02, Section 4.4:
Operations personnel failed to follow good operations and radiological control practices.
OBSERVATION 50-296/95-201-06, Section 9.2:
Engineering to complete the Reactor Vessel head vent line pipe whip analysis'.
APPENDIX C ATTEKDAKCE LIST U.S. Nuclear Re ulator Commission K.
R.
J.
H.
R.
p.
S.
L.
J.
TVA H.
M.
R.
S.
A.
p.
A.
D.
F.
Clark, Public Affairs Officer, Region II Gallo, Chief, Special Inspection Branch, NRR Johnson, Deputy Director, Division of Reactor Projects, Region II Lesser, Chief, Reactor Projects Branch 6, Region II Musser, Resident Inspector, Browns Ferry Narbut, Team Leader, Special Inspection Branch, NRR Varga, Director, Division of Reactor Projects I/II Wert, Jr.,
Senior Resident Inspector, Browns Ferry Williams, Browns Ferry Project Manager, NRR T.
C.
J.
C.
C.
R.
C.
T.
0.
R.
J.
R.
L.
G.
E.
p.
T.
G.
J.
R.
H.
E. Abney, Recovery Manager, Nuclear Assurance and Licensing W. Beasley, TVA Communications H.
Cor ey, Manager, Radcon/Chemistry H. Crane, Assistant Plant Manager T. Dexter, Manager, Training P.
Greenman, Technical Support S. Hsieh, Site Licensing Johnson, TVA Communications D. Kingsley Jr.,
President, TVA Nuclear (by telephone conference)
D. Machon, Vice President, Browns Ferry Site E. Maddox, Manager, Maintenance and Modifications J. Holi, Manager, Plant Operations Newman, TVA Nuclear D.. Pierce, Manager, Technical Support Preston, Plant 'Manager Salas, Manager, Site Licensing D. Shriver, Manager, Nuclear Assurance and Licensing W. Waldrop, Independent Review and Analysis H. White, Outage Manager V. White, Fire Protection Hanager L. Williams, Manager, Engineering and Materials Contractors W. Peabody, Anatec International