IR 05000348/1986014
| ML20203P227 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 07/31/1986 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20203P223 | List: |
| References | |
| 50-348-86-14, 50-364-86-14, NUDOCS 8610270255 | |
| Download: ML20203P227 (33) | |
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ENCLOSURE SALP BOARD REPORT U.S. NUCLEAR REGULATORY COMMISSION
REGION II
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE INSPECTION
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REPORT NUMBERS 50-348/86-14, 50-364/86-14 Alabama Power Company Joseph M. Farley Units 1 and 2 January 1, 1985 through July 31, 1986 l
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8610270255 861022 PDR ADOCK 05000348 G
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I.
INTRODUCTION The Systematic Assessment of Licensee Performance (SALP) program is an'
integrated NRC staff effort to collect available observations and data on a periodic basis and to evaluate licensee performance based upon this information.
SALP is supplemental to normal regulatory processes used to ensure compliance with NRC rules and regulations.
SALP is intended to be sufficiently diagnostic to provide a rational basis for allocating NRC resources and to provide meaningful guidance to the licensee's management to promote the quality and safety of plant construction and operation.
An NRC SALP Board, composed of the staff members listed below, met on October 2,1986, to review the collection of performance observations and data to assess the licensee performance in accordance with the guidance in NRC Manual-Chapter 0516, " Systematic Assessment of Licensee Performance." A summary of the guidance and evaluation criteria is provided in Section II of ~
this report.
This report is the SALP Board's assessment of the licensee's safety performance for the J. M. Farley facility for the period January 1,1985 through July 31, 1986.
SALP Board for the J. M. Farley facility:
L. A. Reyes, Deputy Director, Division of Reactor Projects (DRP), Region II (RII) (Chairman)
A. F. Gibson, Director, Division of Reactor Safety, RII J. P. Stohr, Director, Division of Radiation Safety and Safeguards, RII D. M. Verrelli, Chief, Projects Branch 2, DRP, RII L. S. Rubenstein, Director, Directorate 2, PWR-A Division, NRR W. H. Bradford, Senior Resident Inspector, Farley, DRP, RII E. A. Reeves, Project Manager, Directorate 2, PWR-A Division, NRR Attendees at SALP Board Meeting:
K. D. Landis, Chief, Technical Support Staff (TSS), DRP, RII H. C. Dance, Chief, Project Section 2B, DRP, RII i
L. P. Modenos, Project Engineer, Project Section 28, DRP, RII B. R. Bonser, Resident Inspector, Farley, DRP, RII II.
CRITERIA
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Licensee performance is assessed in certain functional areas depending upon whether _ the facility has been in the construction, preoperational, or operating phase. Each functional area normally represents an area which is significant to nuclear safety and the environment, and which is a normal
programmatic area. Some functional areas may not be assessed because of little or no licensee activities or lack of meaningful observations.
Special areas may be added to highlight significant observations.
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One or more of the following evaluation criteria were used to assess each
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functional area; however, the SALP Board is not limited to these criteria
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and others may have been used where appropriate.
A.
Management involvement in assuring quality B.
Approach to the resolution of technical issues from a safety standpoint
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Responsiveness to NRC initiatives
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D.
Enforcement history E.
Operational and construction events (including response to, analysis of, and corrective actions for)
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Staffing (including management)
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Training and qualification effectiveness
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Based upon the SALP Board assessment, each functional area evaluated is classified into one of the three performance categories. The definitions of
these performance categories ar'e:
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Category 1:
Reduced NRC attention may be appropriate.
Licensee
management attention and involvement are aggressive and oriented toward
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nuclear safety; licensee resources are ample and effectively used so
that a high level of performance with respect to operational safety or l
construction is being achiev'ed.
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Category 2:
NRC attention should be maintained at normal levels.
Licensee management attention and involvement are evident and are
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concerned with nuclear safety; licensee resources are adequate and are
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reasonably effective so that satisfactory performance with resoect to
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j-operational safety or construction is being achieved.
I Category 3:
Both NRC and licensee attention should be increased.
Licensee management attention or involvement is acceptable and
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i considers nuclear safety, but weaknesses are evident; licensee resources appear to be strained or not effectively used so that minimally satisfactory performance with respect to operational safety or construction is being achieved.
The functional area being evaluated may have some attributes that would place the evaluation in Category 1, and others that would place it in either
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Category 2 or 3.
The final rating for each functional area is a composite
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of the attributes tempered with the judgement of NRC management as to the j
significance of individual items.
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The SALP Board may also include an appraisal of the performance trend of a functional area.
This performance trend will only be used when both a definite trend of performance within the evaluation period is discernable and the Board believes that continuation of the trend may result in a change of performance level. The trend, if used, is defined as:
Improving:
Licensee performance was determined to be improving near the close of the assessment period.
Declining:
Licensee performance was determined to be declining near the close of the assessment period.
No trends were noted by the Board for this period.
III. SUMMARY OF RESULTS A.
Overall Facility Performance The Farley facility is well managed by qualified and experienced personnel.
Senior plant managers hold active senior reactor operator licenses and the site is supported by a corporate organization that is composed of personnel who have extensive backgrounds in nuclear plant management and operations.
The licensee remains responsive to NRC concerns and the organization is safety criented.
Strengths were identified in the areas of plant operations, surveillance, radiological controls, maintenance, fire protection, outages, and licensing activities.
The Farley Nuclear Plant was effectively managed and continues to achieve a satisfactory level of operational safety.
The licensee has strong programs in all aspects of plant operation.
However, the weakness noted in the last SALP evaluation of procedure adherence is an area requiring continuing management attention.
The licensee has initiated corrective action which appears to be effective.
This is evidenced by a decrease in procedure violations in the surveillance area. However, violation of failure to follow procedure led to a Level III violation that rendered a train of the Residual Heat Removal System incapable of fulfilling its design function.
Even though this condition was indicated on the main control board, it was not detected for 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />.
During the SALP pariod the Farley plant had high availability, fewer
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than average number of reactor trips, few inadvertent ESF actuations, efficient operational and hardware response to the events that have occurred, prompt and thorough reporting of events when required, and low occupational radiation exposures.
The licensee recognized the potential plant-specific and generic consequences of the tendon failure problem and acted responsibly in reporting and resolving the even.
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The licensee has set high standards for cleanliness, radioactive waste.
control, general plant operations, and maintenance. The licensee is dedicated to long run time and short refueling outages.
Unit l's longest run time was 321 days.
This occurred during Cycle 6 from April 25, 1984 to March 13, 1985.
Nucleonics Week 1985 ranking of commercial reactors b'ased on cumulative capacity factor ranked Farley Unit 2 as #1 in the nation and #15 in world ranking.
B The performance categories fnr the current and previous SALP period in each functional area are as follows:
August 1, 1983 -
January 1, 1985-Functional Area December 31, 1984 July 31, 1986 Plant Operations
1 Radiological Controls
1 Maintenance
1 Surveillance
1 Fire Protection
2 Security
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2 Outages-(includes refueling)
1 Quality Programs and
2 Administrative Controls Affecting Quality Licensing Activities
1 Training
2 IV.
Performance Analysis A.
Plant Operations 1.
Analysis During this assessment period, inspections were performed by the resident and regional inspection staffs. The licensee had a positive-nuclear safety attitude and exhibited no significant administrative, management control or material problems. The licensee's supervisory staff was knowledgeable and proficient in day-to-day plant operations.
Major operational decisions were made at a management level adequate to assure appropriate supervisory involvement.
Plant operations were generally conducted in a conservative manner to ensure plant safety.
Overall control of plant operations was satisfactory and was well planned with established and realistic priorities. The licensee was quick to take corrective action when problems or violations were identified by NRC.
The licensee has demonstrated responsiveness for items identified by the internal audit group.
Corrective actions in
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these areas were prompt.
The licensee has demonstrated a thorough knowledge of regulations, guides, standards and generic issues and interpretations of these documents and associated issues were conservative.
Licensee technical competence was well founded both in technical matters and general plant operations.
The plant staff responded to plant trips and other operational events during this review period in a professional and competent manner.
Daily conduct of business in the control room was performed in a professional manner. Access to the control room was controlled and limited to personnel conducting business.
Radios and reading material not directly related to plant operation are not allowed in the control room or plant.
Housekeeping throughout the plant was well maintained.
The licensee was well prepared at meetings with NRC. The licensee's staff was able to make immediate commitments or state the utility's position in a given area, especially in the enforcement conference held at the Region on June 3, 1986.
The qualifications of ~ plant management exceeded NRC requirements.
Most senior plant managers hold senior reactor operator licenses.
Plant management was oriented towards safety and efficiency.
This was demonstrated by the close supervision of plant operations. The plant was well managed with conscientious and capable personnel.
Licensee onsite evaluations were routinely performed to address, assess and correct reportable events.
An evaluation of the content and quality of a representative sample of Licensee Event Reports (LERs) was performed by the NRC using a refinement of the basic methodology presented in NUREG/CR-4178.
The results indicate that Farley has an overall average LER score of 7.8 out of possible 10 points, compared to a current industry average of 7.9.
The principle weakness identified in the LERs, in terms of safety significance, involve the requirements to provide a safety assessment and to adequately identify failed components in the text. A strong point for the Farley LERs is that the requirement to provide the failure mode, mechanism, and effect of each failed component was satisfied for all applicable LERs.
Seven reactor trips from power operation occurred on Unit 1 during the assessment period. Six trips were caused by equipment. failures and one by personnel error when a technician accidentally bumped a cable on a main feed pump which broke a wire and caused the pump to trip. Unit 1 trip rate was about 0.72 trips per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> of operation compared to a national average of 1.47.
Unit 2 had eight trips from power operation and one trip during start-up at low power level. Five trips were caused by equipment failure, one from personnel error, one by lightning, and one at low reactor power level from low electro-hydraulic fluid pressure at the steam generator feed pump.
Unit 2 trip rate was about 0.88 trips per 1000 hours0.0116 days <br />0.278 hours <br />0.00165 weeks <br />3.805e-4 months <br /> of operation.
Reactor trips are described in Section V.J.
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Seven violations were identi fied.
The plant staff is normally observant of Limiting Conditions for Operation (LCOs) and was generally conservative in its application of action statement requirements.
However, violations (a) and (b), listed below involved failure to follow procedures that resulted in improper system alignment.
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Violations (c), (d), (e), (f) and (g) involved procedural inadequacies and operator failure to comply with procedures.
Procedural violations indicates a lack of strict adherence in following procedures.
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The licensee has initiated strong corrective action to instill in all personnel that plant procedures must be rigidly followed.
The elimination of personnel errors has beccme a pointed objective of supervision. This is being accomplished by corrective action directed
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toward the employee as well as publication of personnel errors committed by the various work groups in the plant.
The personnel errors are displayed on closed circuit TV monitors located throughout
the plant and are tabulated and credited to the appropriate work l
groups. This process, though in the. early stages, has already shown positive results.
a.
Severity Level III violation without civil penalty for violating
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regulatory requirements in that procedures and technical specifications (TS) were not adhered to which caused ECCS subsystem "B" train of RHR to be incapable of transferring pump suction to the containment sump during the recirculation phase of
operation (348/86-10).
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b.
Severity Level IV violation for not placing an inoperable Unit 2 power range channel in the tripped condition within one hour as required by TS (364/85-11).
c.
Severity Level IV violation for failure to update control room reference drawings to conform to as built status, failure to
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adhere to requirements of a p'rocedure, and inadequate procedure j
(348,364/86-13).
i d.
Severity Level IV violation for failure to have a continuous fire watch posted when a fire door was blocked open by a rubber hose (364/86-10).
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Severity Level V violation for failure to adhere to the requirements of a procedure (348, 364/85-11).
i f.
Severity Level V violation for failure to have an adequate
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procedure to set the flow rate for the control room chlorine
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detector (348/84-32).
g.
Severity Level V violation when a fire damper penetration was not t
functional due to a telephone cord blocking the closure of the damper (364/86-11).
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Conclusion Category: 1 3.
Board Recommendations No changes in the NRC's reduced inspection resources are recommended.
B.
Radiological Controls 1.
Analysis During this assessment period, inspections were performed by resident and regional inspection staffs.
This included confirmatory measurements using Region II mobile laboratory.
The licensee's health physics and chemistry staffing levels were appropriate and compared well to other utilities having a facility of similar size.
An adequate number of ANSI qualified licensee and contract health physics technicians and of qualified chemistry technicians were available to support routine and outage operations.
Key positions in the radwaste management program and environmental surveillance programs were filled with qualified staff.
Two strengths of the health physics program were the quality of the health physics technicians and the experience level of the site health physics staff.
The staff has a low turnover rate and an effective training program.
.The performance of the health physics and chemistry staff in support of routine operations and outages was good. No substantive issues were identified in this area.
Management support and involvement in matters related to radiation protection, radwaste control and chemistry was adequate.
Health physics management was involved sufficiently early in outage preparations to permit adequate planning. The station health physicist and plant chemist received the support of other plant managers in implementing the radiation protection and chemical control programs.
Resolution of technical issues by the health physics and chemistry staff was generally adequate and responses to NRC initiatives were conducted in an effective and acceptable manner.
Audits performed by the corporate staff of the health physics, radwaste, environmental and chemistry programs were of sufficient scope.
and depth to identify problems and adverse trends.
Appropriate corrective actions were taken and documented. Audits performed by the site audit organization are discussed in Section I. _.
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The licensee's radiation work permit and respiratory protection programs were found to be satisfactory. Control of contamination and radioactive materials within the facility was generally adequate. From January 1985 to July 1986, the amount of contaminated area decreased from approximately 24,398 to 23,626 square feet which represents 20%
percent of the radiologically controlled area of the plant.
In 1985,
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there was a 33 percent decrease in the number of clothing and skin contamination incidents when compared to 1984.
During 1985, the licensee's cumulative exposure was 400 man-rem per unit.
This compares favorable to the national average exposure of 425 man-rem per unit observed at similar PWR facilities.
This lower than average collective dose results from the aggressive exposure control program established and implemented by the licensee.
During 1985, the licensee disposed of 8,730 cubic feet of solid i
radioactive waste per unit containing 410 curies.
This is less than the national average of 11,650 cubic feet per unit shipped by other utilities with similar facilities. This low amount is due primarily to a dedicated solid waste reduction program. A covered radioactive waste transfer facility is under construction to upgrade the outside bulk
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l loading area and reduce exposure of waste handling personnel.
In the area of radiological confirmatory measurements, the licensee
participated in the NRC's spiked sample program.
. he licensee has had T
i consistent problems with the FE-55 analysis for the past three years, indicative of a weakness in the radiological measurements program; however, the 1986 spiked sample results showed agreement with known concentration of Fe-55, but only after reanalysis by the licensee.
The licensee submitted the required radiological effluent and environmental reports during the evaluation period.
Radioactive gaseous effluents for 1985, for Units 1 and 2 combined, were 2,368 r
curies of noble gases, 6.0E-4 curies of halogens (including I-131),
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5.0E-5 curies of mixed fission product and irradiation product
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particulates, and 470 curies of tritium. Alpha-emitting particulates
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aerosols were-not detected. The 1985 Region II averages for a two unit site (based on 21 operating PWRs) were 10,360 curies of noble gases, 0.12 curies of halogens and 190 curies of tritium. Radioactive liquid i
effluents for the two unit site totalled 0.071 curies of mixed fission i
and irradiation products, 1,105 curies of tritium and 2.0E-4 curies of long-lived alpha emitters released in 2.1 E7 gallons of liquia plant effluents.
The 1985 Region II averages for a two unit site were 2.7 curies of mixed fission products, 840 curies of tritium and 2.2E-4
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curies of alpha emitters. The licensee's releases were less than the average annual releases reported by 21 Region II plants of similar size and type for 1985, with the exception of tritium.
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Both liquid and gaseous effluents were within regulatory limits for quantities of radioactive material released and for dose to the maximally exposed individual.
For 1985 releases, the maximum calculated total body dose to a member of the public was 0.03 mrem from
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liquid releases and 0.13 mrem from gaseous effluents. These calculated
doses represented 0.12 percent and 0.52 percent of-the 40 CFR 190 limit of 25 mrem / year. There were two unplanned gaseous releases and one unplanned liquid release during the evaluation period.
The liquid release was the result of leakage from the Component Cooling Water System into the Service Water System. The gaseous releases were caused by inadvertent venting of the Hydrogen Recombiner System into the Auxiliary Building. The design that vented the RHR Sump Vent into the Component Cooling Water Heat Exchanger Room was corrected. The total
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activity for unplanned releases was 0.006 curies for liquid and 11.5
curies for gas.
Unit 2 had no unplanned releases during this assessment period.
In the area of plant ' chemistry the steam generators had, in prior years of operation, accumulated significant amounts of iron-copper oxide
sludge as well as potentially corrosive species (e.g, chloride,
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sulfate) that were present as " hideout return." Consequently, several
days were required during startup after each lengthy outage to achieve the desired level of chemi stry control.
During the last two fuel cycles of each unit the licensee had achieved stable plant operation and a high level of chemistry control while making progress in removing both sludge and reducing the effects of hideout from the steam
generators. In an effort to eliminate the detrimental effect of copper as a corroding element, the licensee had replaced all copper heat
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exchanger tubes in the condensate /feedwater train.
In addition, inleakage of air condenser cooling water through the condenser had been effectively eliminated. All elements of the chemistry program had been upgraded to implement the recommendations of the Steam Generator Owners Group.
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Two violations were identified for failure to assure that radioactive material shipped for burial was without free standing liquid.
a.
Severity Level IV violation for failure to assure that radioactive material shipments for burial were without free standing liquids
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(348,364/85-34).
b.
Severity Level IV violation for failure to have adequate
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with free standing liquids (348, 364/85-34).
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Conclusion Category 1
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Board Recommendations:
No change in the NRC's reduced inspection resources are recommende.
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C.
Maintenance 1.
Analysis During this assessment period, inspections were conducted by the resident and regional inspection staffs.
The maintenance program continued to be strong. Management involvement in maintenance planning and practices were evident.
First line supervisors and maintenance personnel indicated a high awareness for procedural adherence. This is indicative of the positive nuclear safety attitude in the preventive and corrective maintenance programs.
The licensee's approach to the resolution of technical issues continues to be sound.
The licensee's maintenance program was well controlled by specific procedures.
The personnel participating in activities affecting equipment on the Q-list were aware of the quality assurance (QA)
controls. The craft personnel performing maintenance and surveillances were knowledgeable of maintenance procedures and plant equipment.
Maintenance Work Request (MWR) packages had the required reviews and approvals prior to the start of the work. The MWR indicates the proper Q-list classification, work was completed and inspected as required, and post-maintenance testing was conducted.
Use of the Nuclear Plant Reliability Data System (NPRDS) has increased the licensee's awareness of potential plant problems. Upgrades in the Computer Historical and Maintenance Program System (CHAMPS) and implementation of data verification has improved the data base used for maintenance planning and scheduling.
Staffing increases added maintenance planners who provided better scheduling and coordination of the activities of each maintenance discipline.
During a regional maintenance inspection, instances of breakdowns in the corrective maintenance process occurred. One event included the licensee's failure to properly conduct corrective maintenance activities involving wiring errors associated with the feedwater flow control valves.
A second particular concern was the licensee's inadequate processing of the maintenance work request on a failed electrical penetration which had caused a forced outage.
These instances indicate that under some circumstances, a less than meticulous attention to detail has been directed towards corrective maintenance activities.
A special inspection conducted to evaluate the licensee's actions in response to Generic Letter 83-28 revealed that maintenance activity and post-maintenance testing were adequate to ensure reactor trip system reliabilit,aa:
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Once identified, equipment and-components received adequate preventive maintenance. However, inadequacies were identified in the scope of the preventive maintenance program.which included the failure to incor-porate compressed air system pressure switches and inverter circuit breakers.
The licensee utilizes a predictive maintenance analysis which includes oil and vibration analysis on mechanical equipment and infrared analysis on electrical equipment.
These techniques have enabled the licensee to predict degrading trends in equipment performance and effect repairs before equipment failure occurs.
The licensee was responsive to NRC concerns and conducted evaluations to identify and correct, if required, activities related to maintenance which appeared to be contrary to the prescribed function of equipment.
This is exemplified by the licensee's action in the investigation and repair of Unit 2 containment building post-tensioning system and modification to the Atwood Morrill Company main steam isolation valves on Unit ? in which the valve shafts were modified. Unit I will be modified during the next refueling outage.
Six. violations were identified.
Five of these resulted from not following existing procedures and drawings as noted below.
One involved independent in process inspections.
a.
Severity Level IV violation for not performing independent in process inspection for Class 1 and 2 pipe welds (348/85-33).
b.
Severity Level IV. violation for failure to wire feedwater control valve in accordance with the work request and complete maintenance prescribed procedures or drawings (343/85-40).
c.
Severity Level V violation for failure to follow prescribed procedures for Class 2 pipe support spring hangers in that the support settings were not recorded and verified (348/85-33).
d.
Severity Level V violation for failure to install spacers between the cells of the service water batteries and the uninterruptible power supply batteries as required by sendor drawings (348, 364/85-20).
e.
Severity Level V violation for having combustible liquids unattended in the hot machine shop (348/85-24).
i f.
Severity Level V violation for having combustible liquids unattended in the hot machine shop (348, 364/86-11).
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Conclusion
Category 1
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Board Reccmmendations Due to the findings identified during. a team inspection, the Board recommends that the routine inspection program be conducted in the maintenance area.
D.
Surveillance 1.
Analysis During the assessment period, inspections were performed by the resident and regional inspection staffs.
These included activities related to inservice inspection and testing: surveillance, containment building tendons, and containment intergrated leak rate testing.
Routine plant surveillance related activities appeared to be planned and well defined.
The licensee has continuously upgraded the surveillance program.
Review of surveillance activities was performed by prescribed licensee reviewers who were qualified to perform these activities.
Review of surveillance records revealed that they were readily available, complete, and adequately maintained.
Onsite evaluations were routinely performed to address, assess and correct surveillance concerns. The licensee's nnsite corporate QA organization was heavily involved in the surveillance program.
Licensee response to NRC initiatives was timely and there were few long-standing regulato ry issues attributable to the licensee.
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Understanding of technical issues was apparent with timely resolution.
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Viable, sound and thorough responses were offered.
Licensee management involvement in Inservice Inspection and Inservice Testing activities was adequate.
Decision-making was usually at a level that assured adequate review. Corporate management was involved in site activities, and reviews were timely, thorough and technically sound.
Records were complete, well maintained, and readily available.
The surveillance procedures reviewed, tests that were witnessed, and examinations of test results, revealed that the licensee's surveillance procedures were technically adequate and satisfactorily executed.
Inspection of the snubber surveillance - program-identified a problem with the visual inspection procedure.
The licensee agreed to. revise their procedure to eliminate any confusion with the TS requirements.
The snubber surveillance records were complete, well maintained,
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legible, and retrievable.
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- The four violations identified are not considered to indicate significant programmatic deficiencies. Violations (a) and (d) involved procedure violations.
Violations (b) and (c) concerned control of measuring and test equipment.
a.
Severity Level IV violation for not conducting a review of a completed surveillance test procedure within the time frame specified by an administrative procedure (364/85-44).
b.
Severity Level V violation for changing the work sequence from that which was specified on the Maintenance Work Request without appropriate review and approval (348/85-17).
c.
Severity Level V violation for not establishing suitable environmental conditions for calibration of measuring and test equipment (348,364/85-25).
d.
Severity Level V violation for not establishing adequate measures to assure that measuring and testing devices are calibrated with sufficient frequency to assure accuracy (348, 364/85-25).
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Conclusion Category 1 3.
Board Recommendations No change in the NRC's reduced inspection resources are recommended.
E.
Fire Protection 1.
Analysis
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During this assessment period, inspections were performed by the resident and regional inspection staffs. A special team inspection was conducted of the licensee's fire protection / prevention program reevaluation of 1985 with respect to compliance with 10 CFR - 50 Appendix R, Sections III.G., III.L., and III.O.
On November 19, 1985, the Commission granted exemptions to 10 CFR 50
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Appendix R at the licensee's request for 33 of 49 specific fire areas of Unit 2 and areas shared with Unit 1.
The remaining requests for exemptions for 16 fire areas are under Commission review. Additional justification have been provided by the license.
In addition, exemptions for 27 specific fire areas of Unit 1 were requested by the licensee.
The exemption resulted from the licensee's fire program reevaluation noted above.
As of July 31, 1986, Commission action remains open for these 27 fire areas on Unit 1.
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The licensee has issued the appropriate alternative shutdown procedure for a fire in the cable spreading room and control room.
This procedure was found to meet Appendix R,Section III.L. requirements.
With respect to Section III.G.,
Fire Protection of Safe Shutdown Capabilities, the fixed fire protection extinguishing systems, fire / smoke detection systems, one hour raceway fire barrier enclosures, and fire area three hour fire barrier boundaries were found to be in Service. In addition, these permanent plant fire protection features were found to be adequate with respect to maintaining one train of systems necessary to achieve and maintain hot standby free from fire damage.
The inspectors also found the reactor coolant pump oil collection system design to meet the seismic and oil collection requirements of Section III.O.
The licensee identified, analyzed and reported fire prevention events and discrepancies as required by license condition or technical specifications.
These reports were reviewed and found to be satisfactory.
In general, the management involvement and control in assuring quality in the fire protection program is evident as demonstrated by the completeness of the engineering analysis associated with the inple-mentation of the Appendix R requirements.
The licensee's apprcach to resolution of technical fire protection issues indicates a clear understanding of the issues. The responsiveness to NRC initiatives are technically sound and thorough in almost all cases.
Licensee identified fire protection related events or discrepancies are properly analyzed, promptly reported and effective corrective actions taken.
The previous SALP report refers to a well qualified staff and high quality training program.
No violations of deviations were identified.
2.
Conclusion Category 1 3.
Board Recommendations:
No changes in the NRC's reduced inspection resources are recommended.
F.
Analysis During the assessment period, inspections were performed by resident and regional inspection staffs. These included observation of a small scale emergency preparedness exercise in September 1985.
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Inspections disclosed that the licensee had adequate emergency preparedness organization and staffing at the plant and corporate level.
Corporate management appeared committed to an effective emergency response program.
Senior corporate officials were directly involved in the annual emergency exercise, drills, and followup critiques.
The following essential elements of emergency response were determined to be acceptable:
emergency detection and classification; protective action decision making, except as discussed below; shift staffing and augmentation; training, except as indicated below; dose calculation and assessment; public information; annual quality assurance audits of plant and corporate emergency preparedness programs; changes to emergency plan and implementing procedures; coordination of offsite agencies; identification of weaknesses during drills and exercises.
The exercise demonstrated that the emergency plan and respective procedures could be implemented, although one violation involving notification of emergencies within 15 minutes was noted.
Three of the four weaknesses identified were identified by the licensee. The licensee failed to follow the format agreed upon between the states and the licensee in making initial offsite notification.
During the exercisc, no protective actions were taken onsite during and following the simulated plume passage.
Onsite communications needed improvement in that the Recovery Manager was not informed of the Emergency Director's reclassification of the Site Area emergency to an Alert until 16 minutes after the reclassification had been announced to offsite officials. Also, one plant procedure did not clearly define the use of plant personnel in the dose assessment group. The licensee committed to resolve the above exercise weaknesses.
The violation noted is not indicative of a programmatic breakdown.
Severity Level IV violation for failure to provide the capability and ' procedures for notification of offsite State and local agencies within 15 minutes following emergency declarations (348, 364/85-37).
2.
Conclusion Category 2 3.
Board Recommendations:
No change in the NRC's reduced inspection resources are recommended.
.
e
._.
.
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. - -... _
_ _ -
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-
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.
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,
.
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G.
Security and Safeguards
.
1.
Analysis During the assessment period, inspections were conducted by the i
resident and regional inspection staffs.
A Regulatory Effectiveness
Review (RER) was also conducted.
Although the RER report was not
]
issued during the rating period, the licensee has taken actions to compensate for a potential safeguards vulnerability identified during l
the RER. Further, the licensee has established a program for upgrade
'
and/o'r replacement of physical security hardware identified as
,
inadequate in the RER. Additionally, the licensee is using members of the security force as compensatory measures for RER identified safeguards inadequacies and concerns until completion of hardware j:
upgrade / replacement.
Procedures have been placed in effect by the j
licensee to correct other procedural problems identified by the RER.
The licensee is working with the Division of Safeguards, NMSS, in order
'
to resolve other issues arising from the RER.
Authority and responsibilities associated with the security organi-
.!
zation were cleariy delineated and appeared to be effective. The site organization is adequately staffed and appropriately trained and
>
j-equipped.
The facility guard Training and Qualification Plan is i
implemented on a continuing basis at all levels of the security organization using the onsite training staff supplemented by corporate i
specialists.
Changes to the licensee's Physical Security Plan were submitted on a timely basis under the provisions of 10 CFR 50.54(p).
The licensee's independent security program audit covers all aspects of
!
the site security program and the program auditors seem well acquainted with the prsgram.
t
.!
Three violations were identified.
The violations appear to have been caused by a lack of effective program oversight rather than guard force
inadequacy, a.
Severity Level IV violation for failure to protect vital. equipment with two physical barriers (348, 364/85-08).
b.
Severity Level IV. violation for several protected area perimeter
inadequacies:
several protected area gates were not protected by
an intrusion detection system, the security fence was not secured
at the bottom, and a portion of the microwave system was inadequate (348, 364/85-08).
I c.
Severity Level V violation for inadequate security procedures
'
(348,364/85-08).
i,
{
f
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_
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.
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._
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-
i
.
..
.
I
l 2.
Conclusion-
Category 2.
3.
Board Recommendations:
Management attention should be directed to the prompt resolution of the RER findings.
No changes to the NRC's inspection resources are recommended.
H.
Outages
+
ii 1.
Analysis During the assessment period, inspections were performed by the resident and regional inspection staffs.
The regional staff. also
!
reviewed the design change program, inservice inspections of safety-
.
related components and associated piping, supports, and snubbers; j
inservice testing of pumps and valves; welding and nondestructive testing.
Unit I had one refueling outage from April 6,1985 to J
- 4, 1985.
Two refueling outages were performed on Unit 2, January b,
'985~to l
March 3, 1985 and April 5, 1986 to May 29, 1986.
Major act..ities conducted during these refueling outage consisted of:
-
'
a.
The Anti-vibration bars (AVB's) in Unit 1_ steam genera *,r 1B, and
~
i Unit 2 steam generators 2A and 2B were replaced wi a modified AYB's to reduce tube wear.
'
i b.
An extensive inspection and repair program was completed on the
!-
containment building tendons of_ Units 1 and 2.
See also Section IV.J. of this report.
I
c.
The high pressure turbine rotor, blade rings and nozzle blocks were replaced.
i d.
All feedwater heaters on both units have been replaced with
!
heaters having stainless steel tube bundles.
I i
e.
Eddy current testing of steam generator tubes and tube removal on
Unit 2.
!
!
f.
Local leak rate testing and containment integrated leak rate j
testing on Unit 2.
i l
g.
Unit 2 reactor vessel level monitoring system installation.
I
!
!
L
!
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L
. _. - - - _ _. - _ _,. _ _ _ _.... _
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-
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.
.
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-
.
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.
.
.
The licensee followed management approved refueling procedures. The procedures were-enhanced by monitoring up-to-date fuel status boards
!
inside and outside containment. The licensee's safety audit engineer
^
review group performed audits during the refueling period.
The a
licensee scheduled and followed the refueling outage with the aid of flow and critical path charts. At the conclusion of each refueling
'
outage. the licensee conducted a complete review of completed work.
Problem areas were identified and analyzed.
Special attention was
.
given to these areas for future refueling outage scheduling.
The licensee's overall control and planning for refueling outages results in a well planned and controlled evolution.
All work is planned with regard to scope, repair parts and work procedures.
!
Planning for the next refueling cutage starts at the conclusion of the present outage.
There are in the order of 70 to 100 modifications
'
performed on each unit during a refueling outage with each refueling outage typically scheduled for six weeks. Extensive operator training
,
is conducted to familiarize personnel with plant modifications.
'
l The licensee's interface and control of contractors during refueling -
outages has become stronger.
This is primarily due to business meetings which the licensee has set up with the contractors prior.to
'
the start of the work.
This accounts for the licensee having better
'
control and understandi.ngs with the contractor.
j Licensee management involvement in inservice inspection activities
appeared to be adequate and decision making was at a level that assured I
adequate management review.
Records were complete, well maintained,
,
and available.
Procedure and policies were occasionally violated as j
evidenced by the violations listed below.
Six violations were identified.
Violation (a) involved inadequate activities performed by a contractor quality control inspector.
>
Violations (b), (c), and (d) involved failure to comply with Technical Specifications requirements. Violations (e) and (f) involved procedure
'
violations. These violations, while not indicative of a programmatic
'
l problem, indicate procedural adherence problems.
a.
Severity Level IV violation for failure to follow the inspection
'
plan for inspection of steam generator welds (348/85-22).
b.
Severity Level IV violation for failure to adhere to the requirement of a procedure which violated Unit 1 containment
integrity by having both inner and outer doors of the containment auxiliary hatch open during refueling operation (348/85-20).
c.
Severity Level IV violation for failure to adhere to procedure requirements which caused the loss of both Unit 1 RHR trains for
52 minutes during a refueling outage (348/85-20).
I
,~
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- -. - -
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.-
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---
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.
d.
Severity Level V violation for failure to have one charging pump in the boron injection flow path operable as required by Technical Specification during Unit 1 refueling operations (348/85-20).
e.
Severity Level V violation for performing reactor - core video inspection without a procedure to govern the activity (364/85-04).
f.
Severity Level V violation for failure to fully implement fuel handling procedure sequence in releasing the top fastener during new fuel receipt and inspection (364/85-43).
2.
Conclusion Category 1 3.
Board Recommendations No changes in the NRC's reduced inspection resources are recommended.
I.
Quality Programs and Administration Controls Affecting Quality 1.
Analysis During the assessment period, inspections -were conducted by the resident and regional inspection staffs.
The following areas were reviewed by the regional staff:
licensee actions on previous enforcement matters, quality assurance / quality control (QA/QC)
administration, audits, document control, and licensee actions on previously identified inspection findings.
Interviews with licensee personnel indicated that the QA program was e
adequately stated and understood.
Frequent site communication was evident and indicated that corporate QA management was actively involved in onsite activities.
Key staff positions had been identified and authorities and respon-sibilities for these positions were procedurally delineated. Staffing was adequate.
During this assessment period, two senior reactor
operators were assigned to -the audit staff.
Their addition provided l
depth and additional expertise to operational auditing activities.
Audits performed by onsite QA personnel are basically compliance audits.
Audits were written by the licensee in a professional and adept manner. Although violation (a) was identified in this area, the
violation was administrative in nature.
Audits and their responses were completed in a timely manner, comprehensive checklists were t
'
utilized, and all audit findings were reviewed by the Senior Vice
!
President.
However, the site internal audit organization lacked sufficient expertise in the area of health physics to perform
}
meaningful evaluation. _
__.
.
-
-
.
..
.
The audits examined contained two types of findings, noncompliance and
,
comments.
The noncompliances were licensee identified violations of
'
regulatory and site procedural requirements.
Comments appeared to be used by the audit group to identify weaknesses in the site's methods or procedures to management. Of the comments examined by the NRC, some of those appeared to be in grey areas which were not strictly defined by regulation; a subset of those comments appeared to be borderline
noncompliance.
Overall, the comment concept is acceptable for its feedback potential.
Based on the samples selected by the inspectors,. the process of-
releasing'and controlling documents for the purpose of maintenance and operation of the plant was effective. Aside from some minor filing problems at the user level, the document control program met regulatory requirements and also met requirements that site personnel had placed on the system.
,
.
'
The procurement of safety-related equipment and services and the receipt, storage, and handling of materials met regulatory require-ments.
Procurement documents were complete, accurate, and equipment
.
storage areas were well organized and clean. The licensee constructed a new warehouse which is capable of containing all safety-related parts
!
and equipment under one roof in an environmentally controlled
'
atmosphere.
The licensee has been responsive to NRC concerns as evidenced by successfully taking corrective actions for previously identified enforcement matters.
Two previously identified -inspection findings were also reviewed and although they could not be closed, corrective
action was ongoing.
The special tests and experiments program was adequate; however, a violation was identified because one special test package was not
,
reviewed by the plant manager prior to implementation.
The apparent
!
root cause of this problem was that site procedures had not - been updated to raflect this technical specification requirement.
Records for this program were readily retrievable.
Safety evaluations were
'
thorough and technically adequate.
The Quality Program and Administrative Controls Affecting Quality
.
'
section of this SALP report includes an assessment of the licensee's ability to identify and correct his problems. As such, each specific SALP functional area provides input for judging QA program effective-ness. As previously mentioned in this report, the licensee takes pride in the'c plant as evidenced by standards set for cleanliness, radwaste co itrol, general plant operations, and maintenance.
These attributes
>
reflect positively on QA program effectiveness. However, the problems addressed in Section K,
Training and Qualification Effectiveness pertaining to wrong unit / wrong train reflects negatively on the QA program effectiveness.
2.
-_ _ _,
._ _
.
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..
l
-
Five violations were identified.
Violation -(d) resulted when site procedures were not updated to the technical _ specification require-ments.
a.
Severity Level IV violation for failure to establish measures to verify correct item replacement which allowed incorrect fusible links to be installed in 2B and 2C containment air. coolers (364/85-05).
b.
Severity Lavel IV violation for failure to have a procedure reviewed independently of the group that wrote the procedure (348, 364/85-34).
c.
Severity Level V violation for failure to perform evaluations on test equipment and prompt assessment of safety significance for measuring and test devices found out of tolerance (348, 364/85-25).
d.
Severity Level V violation for failure to have measures established to assure that the plant manager approves tests and experiments prior to implementation (343, 364/85-32).
e.
Severity Level V violation for failure to list persons contacted during the audit (348,'364/85-21).
2.
Conclusion Category 2 3.
Board Recommendations No cha'nges to the.NRC's inspection resources are recommended.
J.
Licensing Activities 1.
Analysis Performance in the area of licensing continues to demonstrate a high level of management involvement in assuring quality in licensing activities.
Corporate management is frequently involved in site activities.
This attribute was most certainly. evidenced by the-containment tendon problem on Unit 2 described below.
During the third refueling outage on Unit 2, a degraded vertical tendon was found during preparation for the containment building integrated leak rate test.
Licensee senior management organized and directed an aggressive program of inspection and repair of -the tendons because of an uncertainty in the licensing basis for the containment structural
_.
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- -
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integrity.
Licensee management briefed the Commission staff on the proposed action plan during a meeting on February 7, 1985, in Bethesda, i
Later, on March 1,1985, licensee management again briefed the Commission staff on the inspection and repair program for Unit 1.
,
'
The initial repair phase was completed on Unit 2 in April 1985,-and on Unit 1 in June 1985. Followup licensee actions have been identified by
the licensee to assure continued reactor containment-building i
structural integrity. Structural integrity was maintained-at all times during the entire test and. repair program.
Licensee planning and prioritizing methods for license amendment
requests has continued in a satisfactory manner as during the previous assessment period. Meetings were held at the Farley site in June,1985,
-
and at the licensee's headquarters in January 1986, between the Operating Reactors Project Manager and the licensee's staff, for discussions of licensing priorities and schedules. These meetings were fruitful, resulting in a clearer understanding of the licensee's
,
requests as well as Commission initiated licensing actions.
The licensee provides quarterly updates in the form of a " Status of Licensing Items" which is a helpful tool.
These updates show consistent evidence of the licensee's planning and assignment of licensing priorities.
,
,
!
The licensee usually demonstrates a clear understanding and approach to resolution of technical issues. The example, noted above, relating to
,
the resolution of the containment tendon anchor failures shows how the licensee solved a very complex technical problem in a timely manner.
..
However, for another technical issue relating to the analyses provided l
by the licensee to support changes to the heatup/cooldown curves for
each unit, a weakness was evident.
In the Unit 2 application for changes to the curves, the NRC staff noted that the licensee's submittals were not technically sound and did not exhibit conservatism when considering safety significance. A reanalysis was required for the Unit 2 submittal.
The responses to NRC initiatives are generally timely.
During our
review of licensee requests for 76 specific fire protection exemptions, the licensee revised their submittals as requested for 21 exemption i
i requests to document additional fire protection commitments.
Their
'
proposals to resolve our concerns were viable, technically sound, and are being accepted.
In the licensing support activity, the licensee has increased the number of qualified senior reactor operators on the corporate nuclear support staff. These trained and qualified managers, associated with licensing support, provide a positive contribution in understanding
.
operations and in coordinating license amendment evaluations with the l
NRC staff.
,
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.
.
I
The licensee's staff for licensing actions is quite adequate.
j Operations qualified personnel are integrated into the corporate levels of licensee management. This is a positive factor which enhances the
licensee's ability at the corporate level to evaluate licensing matters
- .
which frequently involve operations.
One violation was identified, j
i
A violation of anti-trust licensing condition No. F.2 initiated an enforcement action to require compliance.
The violation was
'
i issued pursuant to 10 CFR 2.206 against both Units 1 and 2.
2.
Conclusion
!
Category 1 3.
Board Recommendations
!
None.
K.
Training and Qualification Effectiveness
,
1.
Analysis During the assessment period, inspections were conducted by the resident and regional staffs.
Inspections included three licensing examination site visits and a two week training assessment.
.
Farley's training center consists of lecture rooms, maintenance labs,
!
and a site specific simulator.
This versatile and professional j
facility provides an atmosphere conducive to the proper training of licensed operators and plant staff. The site specific simulator has
'
become a valuable tool in replacement and requalification licensed l
operator training.. The instructors appear to be quite proficient and
!
abreast of the latest plant modifications. Commensurate with the plant i
modifications is a procedure which keeps the simulator updated to i
reflect current plant layout hardware and operating parameters.
'
l Licensed operators felt that the simulator was an important aspect of (
their training.
l l
The licensing examinations for replacement and upgrade operators were l
administered in January and August of 1985 and February and July of 1986.
In spite of the excellent training facilities noted above, examination results have yielded a failure rate which is above the industry average.
January 1985 examination results yielded a 3 694 (5 of 14) failure for SR0s and 40?; (2 of 5) failure for R0s.
August 1985 results yielded a 67?s (4 of 6) failure for SR0s and a 40?s
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, - -. -
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(4 of 10) failure for R0s.
February 1986 results yielded no failures for two SR0s and two R0s. July 1986 results yielded an overall failure rate of 40% (4 of.10) for SR0s and no failure for one R0. Areas of generic weakness noted during the candidate's operating examinations were as follows:
Difficulties in-classifying emergency plan levels Inadequate use of procedures during simulator exams Inability to diagnose minor malfunctions and abnormal situations on simulator exams
Inconsistent use of abnormal operating procedures During inspection (85-15) conducted in March 1985, nine apparent violations were identified; however, as a result of the current NRC policy statement and agreement with INPO on training and qualification of nuclear power plant personnel, these apparent violations are being carried as unresolved items.
The following summary describes the corrective actions taken by the licensee with regard to these unresolved items. (It should be noted that the NRC has not reinspected these items but is taking steps to determine whether appropriate correctiv.e actions have been taken.)
(a)
In December 1984, the Accreditation Board of the Institute of Nuclear Power Operations (INPO) awarded Farley accreditation for several training programs including Operator License, License Upgrade, an'd Shif t Supervisor Training.
One of the unresolved items. pertains to Farley's failure to implement the INPO accredited SRO Upgrade Training program. The licensee has stated this training is now specifically addressed in procedures and is implemented in their program.
(b) The licensee conducts the annual procedure review simultaneously with control manipulations. This practice has not ensured that all procedures are reviewed, or that a procedure is utilized in its entirety as required by 10 CFR 55, Appendix A, 3.d.
The licensee stated current training specifically addresses this matter.
(c) Since completion of the initial training in mitigating core damage in May of 1981, replacement licensed operators have not received the equivalent training pursuant to NUREG 0737, II.B.4, nor had the training been specifically conducted as part of licensee requalification training. Additionally, the licensee had failed to provide nitigating core damage training to all I&C technicians as committed to in their letter dated February 9, 1981.
The licensee has stated that current training is now provided to these individuals.
(d)
In the area of operational feedback experience, it was noted that the distribution of pertinent information to the individual mechanics and I&C technicians was informal, uncontrolled, and not
.
.
.
documented. Operational experience was not incorporated into the training and retraining programs for mechanics or I&C technicians.
The licensee has stated that more operational feedback experience is being incorporated in their training and is being documented.
(e) Operational feedback experience provided in operator requali-fication training was in the form of reading the event reports verbatim to the students which leaves the interpretation of the event and its applicability to Farley Nuclear Station to the student.
The importance of this lack of operational feedback experience training is best exemplified when reviewed in conjunction with the number of wrong unit / wrong train and tagging event errors occurring at Farley as documented in their internal incident reports.
It should be noted that while a majority of these incidents are minor in nature, several have caused entry into limiting conditions of operation.
(f)
In addition certain other unresolved items not described in detail are listed herein for completeness:
1) require vendor licensed operator instructors teaching SRO/R0 requalification to have a NRC SRO certification or license, attend requalification lectures, and take the annual requalification examination; 2) establish training program for quality control inspectors; 3) provide management training to STA candidates; 4) provide General Employee Training to members of plant management.
The licensee has stated these items have been adaressed and corrected.
No violations or deviations were issued.
2.
Conclusion Category 2 3.
Board Recommendation No changes to the NRC's inspe, tion resources are recommended.
V.
Support Data and Summaries A.
Licensee Activities During the assessment period, the licensee conducted major activities during the one refueling outage for Unit 1 and two refueling outages for Unit 2.
The anti vibration bars for steam generators 1B, 2A and 2B were replaced.
The licensee detected, evaluated and repaired as required the containment building tendons; replaced the high pressure turbine rotor, blade and nozzle blocks; and replaced all feedwater
. - - - - - _ - - _-_- - - _. -, _ _
..
..
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1 heaters for both units.
In Unit 2, the licensee conducted eddy current testing of steam generators; installed the reactor vessel level monitoring system; and conducted containment local and integrated leak rate testing.
INP0 conducted an operations evaluation during June 1986 and an accreditation visit during July 1986.
B.
Inspection Activities During the assessment period, routine inspections were performed at the J. M. Farley facility by the resident and regional inspection staffs.
A special team inspection was conducted by the fire protection /
prevention program as described in Section IV.E, above. A small scale emergency preparedness exercise was conducted (Section IV.B.).
Three licensing examination site visits, a two week training assessment, and a supplementary reactive inspection following the RHR inoperability were conducted as described in Section IV.A.
C.
Licensing Activities UNIT 1/ UNIT 2 TITLE OF AMENDMENT DATE
--/48 Heatup Cooldown Curves 01/22/85 Capsule U Schedule Only 57/49 Reporting Requirements (GL 83-43)
02/19/85 58/--
Heatup/Cooldown Curves to 7EFPY 05/02/85 59/E0 Update Surveillance for DC Batteries 05/25/85 60/51 Organizational Changes 01/27/86 61/52 QPTR Changes to Allow Full Core Map 03/14/86 62/53 Turbine Trip Before Latching 04/15/86 63/54 Deletion of Shutdown for Cumulative 04/16/86 Iodine
__/55 Heatup/Cooldown Curves for 8EFPY 04/21/86
__/56 Deletion of Fuel Rod Height 04/22/86 64/57 Deletion of Rod Bow Penalty 06/16/86
- -
-
-.
_..
EXEMPTIONS GRANTED Appendix R, 33 Technical Exemptions from Section III.G.
11/19/85 (Unit 2 and shared Unit 1 areas)
ORDERS ISSUED Confirmatory Order - Additional Commitment on Scheduling 07/25/85 Final Emergency Response Capability RELIEFS GRANTED ISI Relief from ASME Code for Reactor Vessel Ligaments, 12/27/85 and for Reactor Coolant Pump Interior and Flange Areas ISI Relief from ASME Code for Certain Valve Body Welds 06/19/86 and Internal Pressure Boundary Surfaces D.
Investigation and Allegations Review There is currently one significant investigation in progress. This investigation is being conducted by the Office of Investigations.
E.
Enforcement History During this SALP period, 57 inspec tions resulted in one antitrust, 12 Unit 1 and 11 Unit 2 Severity Level IV violations, and 14 Unit 1 and 12 Unit 2 Severity Level V violations. One Severity Level III violation was identified.
The Sevgrity Level III violation is related to one train of the RHR system on Unit 1 being unable of transferring pump suction to the containment sump during recirculation phase.
Control board operators failed to assure operability during 12 shifts of turnover operations.
During an enforcement conference at Region II on June 3, 1986, the licensee reviewed the details of the event.
Because of self identification and prompt and extensive corrective action the Severity Level III violation was issued without a civil penalty.
F.
Management Conferences Held During Appraisal Period 1.
Farley 2 Containment Tendon Field Anchor Failures Resulting in IN 85-10 - 2/7/85 and 3/1/85 2.
Project Manager Meeting at Licensee Offices to Review 1986 Licensing Schedules - 1/15-16/86 3.
Project Manager Site Visits:
Commissioner Asselstine's site visit 1/23-25/85 SALP Review Meeting with Licensee 4/10-12/85 Quarterly PM Visit and Tendon Review 6/22-27/85 Appendix R Fire Protection Audit 8/21-26/85 Regulatory Effectiveness Review Audit 2/5-7/86
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.
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.-
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.
4.
Enforcement Conference at Region II relating to the RHR valve being inoperable - 6/3/86 G.
Operational Events During this 19 month period, the licensee reported 42 non-security events to the NRC Operations Center to comply with 10 CFR 50.72 requirements.
Ten events involved losses of Emergency Response Capabilities such as failures of communications or meteorological equipment. One involved damage to a fuel assembly during installation and one involved failures of the containment vertical tendon field anchors.
Review of the 10 CFR 50.72 reports for these events indicates appropriate hardware and operator response subsequent to scrams, prompt and clear reporting by the licensee, and appropriate repairs prior to returning to power. None of the events involved a radiation release.
Eleven events involved human error, three by operators and eight by technicians. With the exception of the vertical tendon failures (See Section IV.J), none of the events were considered to be significant, especially in terms of being generic, recurring, or precursory in nature.
During the SALP period, Farley 1 exhibited nigh availability. In 1985 the reported reactor availability was 84.3?; and for the first 6 months of 1986 the availability was 98.8*4.
The 1985 figure includes a 51-day refueling outage. During the same period, Farley 2 exhibited slightly above-average availability.
In 1985, the reported reactor availability for Unit 2 was 77.8%. For the first 6 months of 1986 the availability was 72.2?s, yielding an overall average for both units during the reporting period of about 82.5?;, or 14?; above the 1985 national average for availability, 68.5?s.
H.
Review of Licensee Event Reports and 10 CFR 21 Reports submitted by the Licensee During the assessment period, there were 27 LERs reported for Unit 1 and 22 LERs reported for Unit 2.
The distribution of the first 44 events analyzed by cause, as determined by the NRC staff, was as follows:
.
..
_
Cause Unit 1 Unit 2 Component Failure
8 Design
1 Construction, Fabrication, or
1 Installation Personnel
- Operating Activity
4
- Maintenance Activity
2
- Test / Calibration Activity
2
- Other
-
Out of Calibration
-
-
Other
1 TOTAL
19 I.
Inspection Activity and Enforcement-
.
FUNCTIONAL NO. OF VIOLATIONS IN EACH SEVERITY LEVEL AREA V
IV III II I
Unit No.
1/2 1/2 1/2 1/2 1/2 Plant Operations 2/2 1/3 1/0 Radiological Controls 0/0 2/2 Maintenance 4/2 2/0 Surveillance 3/2 0/1 Fire Protection 0/0 0/0 Emergency Preparedness 0/0 1/1 Security 1/1 2/2 Outages 1/2 3/0 Quality Program and 3/3 1/2 Administrative Controls Affecting Quality Licensing
Training TOTAL 14/12 12/11 1/0
- 0ne violation with no s eve r i t.-
level issued against licensee activities of anti-trust licensing condition No. 2.
J.
Reactor Trips Unit 1 3/13/85 Reactor trip due to low-low water levels in steam generators (SGs) 18 and IC. This was caused by closure of the turbine governor and intercept valves due to spurious actuation of a limit switch on a main steam isolation valve (MSIV).
The
.
..
limit switch on the MSIV was replaced.
Additionally, operations personnel now verify the proper MSIV limit switch positions prior to each unit start-up.
6/08/85 Reactor trip occurv ed due to underfrequency on the reactor coolant pump (RCD) electrical buses.
The underfrequency condition occurred because the RCP bus power sources had not been realigned prior to tripping the main turbine. The event was caused by personnel error and procedural inadequacy.
Subsequently, corrective actions were taken which included personnel counseling and revisions to appropriate plant procedures.
6/23/85 Reactor trip occurred due to an electrical short between two control rod drive system cables which were routed through the same containment electrical penetration.
The cables have been repaired and rerouted.
Additionally, all CRDM
penetration modules are undergoing replacement with an improved module manufactured by Conex (Unit 1, 7th refueling outage (R.O.) and Unit 2, done in 4th R.0).
07/17/85 Reactor trip occurred due to low-low SG level following a trip of the 18 steam generator feed pump (SGFP).
The SGFP tripped when a technician accidentally bumped a cable and broke a connection on a wire leading to the SGFP thrust bearing wire protective unit.
The broken wire caused the protection unit to indicate excessive thrust bearing wear.
Discussions are underway to either reroute or provide conduit for the above cable.
02/28/86 A reactor trip occurred as a result of dropped control rod.
A short existed in the containment electrical penetration for the control rod stationary and movable grippers and caused the control rod to drop.
The cable was rerouted to spare terminals in the penetration. All CRDM penetration modules are undergoing replacement with an improved module manu-factured by Conax.
05/18/86 A main turbine trip occurred due to ruptured diaphragm of an automatic stop oil / hydraulic system interface valve.
The ruptured diaphragm caused the turbine auto stop pressure to decrease to the trip setpoint resulting in a turbine trip.
Replacement of the diaphragm is to be included as a preventative maintenance item for subsequent refueling outages.
07/02/86 Unit 1 tripped from 99*; reactor power on a negative rate trip.
The trip was caused by a short in control rod F14 stationary gripper coil circuit in the containment pene-tration, resulting in blown fuses and control rod F14
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dropping into the core. All systems functioned as designed.
The cabling for control rod F14 stationary gripper coil circuit was - rerouted through spare conductors in the same penetration.
Unit 2 03/28/85 Reactor trip due to 2A SG low-low level caused by the loss of B main feed pump control. This was due to a printed circuit card being removed incorrectly from the 28 SGFP control cabinet.
The event was caused by personnel error.
Appropriate personnel were counseled in the importance of exercising caution while performing maintenance on operating equipment.
03/30/85 Reactor trip due to low-low level in 2A SG following the loss of SGFP 28.
During instrument calibration, an isolation valve leaked causing the SGFP to trip due to an incorrectly indicated low vacuum condition.
The isolation valves was replaced.
07/15/85 Reactor trip occurred due to the loss of power in two rod control system power cabinets. This was caused by lightning.
To eliminate the potential for future failures of this nature, surge arrestors were installed on the auxiliary power supplies to each CRDM power cabinet during Unit 2 4th R.0.
Arrestors will be installed durir.g Unit 1 7th R.0.
07/17/85 Reactor trip occurred due to low-low level in the 2C SG following a SGFP and main turbine trip caused by high level in the 2A SG. The high SG level occurred due to a main feedwater regulating valve which apparently failed to respond in manual control.
Trouble-shooting of the control circuit did not identify a problem.
Operations personnel were counseled in the importance of monitoring / maintaining SG levels in manual.
08/02/85 Reactor trip occurred due to over-temperature-delta temperature (OTDT). This event was caused by the failure of the IB inverter while one channel of OTDT had been placed in test for maintenance with the bistable in the tripped condition. A faulty ferroresonant transformer in inverter 2B was replaced.
The inverter was returned to service.
01/17/86 A turbine trip was initiated manually following the loss of both steam generator feedwater pumps (SGFP).
This resulted in a reactor trip. A short in the SGFP circuit control panel resulted in the loss of the redundant power supplies which serve both SGFPs.
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05/13/86 During start-up from the Unit 2 Cycle IV refueling outage, while performing test with the turbine generator at 1800 RPM, feed flow from the steam generator feed pump went low due to electro hydraulic (EH) fluid low pressure. This caused a low-low level in the steam generators, resulting in a reactor trip.
Apparently the low EH pressure was due to a faulty turbine valve actuator. These actuators are to be replaced at each refueling outage as preventive maintenance.
06/08/86 A reactor trip occurred when both motor generator (MG) sets malfunctioned. This allowed all control rods to fall in the core resulting in a high negative flux rate causing the reactor trip breakers to open.
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