IR 05000369/1986007
| ML15239A005 | |
| Person / Time | |
|---|---|
| Site: | Oconee, Mcguire, McGuire, 05000000 |
| Issue date: | 06/19/1986 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15239A003 | List: |
| References | |
| 50-369-86-07, 50-369-86-7, 50-370-86-07, 50-370-86-7, NUDOCS 8607100494 | |
| Download: ML15239A005 (39) | |
Text
JUN 19 1986 ENCLOSURE 2 SALP BOARD REPORT U. S. NUCLEAR REGULATORY COMMISSION
REGION II
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE Inspection Report Numbers 50-369/86-07 and 50-370/86-07 DUKE POWER COMPANY MCGUIRE NUCLEAR STATION UNITS 1 AND 2 September 1, 1984, through February 28, 1986 8607100494 86061 PDR ADOCK 050069
O5000&6 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 informatio The SALP program is supplemental to normal regulatory processes us.ed to determine compliance with NRC rules and regulations. The SALP program is intended to be sufficiently diagnostic to provide a rational basis for allocating NRC resources and to provide meaningful guidance to licensee management to promote quality and safety of plant construction and operatio An NRC SALP Board, composed of the staff members listed below, met on April 23, 1986, to review the collection of performance observations and data to assess licensee performance in accordance with 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 repor This report is the SALP Board's assessment of the licensee's safety performance at the McGuire Nuclear Station for the period September 1, 1984, through February 28, 198 SALP Board for McGuire Nuclear Station R. D. Walker, Director, Division of Reactor Projects (DRP), RH (Chairman)
A. F. Gibson, Director, Division of Reactor Safety (DRS), RH J. P. Stohr, Director, Division of Radiation Safety and Safeguards, RII J. Youngblood, Project Director, Division of PWR Licensing A, Office of NRR V. L. Brownlee, Chief, Reactor Projects Branch 3, DRP, RH D. Hood, Project Manager (McGuire), PWR Licensing Division A, NRR W. T. Orders, Senior Resident Inspector, McGuire, DRP, RH Attendees at SALP Meeting R. D. Walker, Director, Division of Reactor Projects (DRP), RII A. F. Gibson, Director, Division of Reactor Safety (DRS), RH J. P. Stohr, Director, Division of Radiation Safety and Safeguards, RII L. A. Reyes, Deputy Director, Division of Reactor Project, RII V. L. Brownlee, Chief, Reactor Projects Branch 3, DRP, RH K. Jabbour, Project Manager, PWR Licensing Division A, NRR W. T. Orders, Senior Resident Inspector, McGuire, DRP, RH K. D. Landis, Chief, Technical Support Staff, DRP, RH C. W. Burger, Project Engineer, RPB3, DRP, RH J. K. Rausch, Reactor Engineer, TSS, DRP, RII T. C. MacArthur, Radiation Specialist, TSS, DRP, RII
Enclosure 2
II. Criteria Licensee performance is assessed in selected functional areas depending on whether the facility has been in the construction, preoperational, or operating phase during the SALP review perio Each functional area normally represents an area which is significant to nuclear safety and the environment and which is a normal programmatic are Some functional areas may not be assessed because of little or no licensee activity or lack of meaningful NRC observation Special areas may be added to highlight significant observation One or more of the following evaluation criteria was used to assess each functional area; however, the SALP Board is not limited to these criteria and others may have been used where appropriat A. Management involvement in assuring quality B. Approach to the resolution of technical issues from a safety standpoint Responsiveness to NRC initiatives Enforcement history E. Reporting and analysis of reportable events F. Staffing (including management)
G. Training and qualification effectiveness Based upon the SALP Board assessment, each functional area evaluated is classified into one of three performance categorie The definitions of these performance categories are:
Category 1:
Reduced NRC attention may be appropriat Licensee management attention and involvement are aggressive and oriented toward nuclear safety; licensee resources are ample and effectively used such that a high level of performance with respect to operational safety or construction quality is being achieve Category 2:
NRC attention should be maintained at normal level Licensee management attention and involvement are evident and are concerned with nuclear safety; licensee resources are adequate and are reasonably effective such that satisfactory performance with respect to operational safety or construction quality is being achieve Category 3:
Both NRC and licensee attention should be increase Licensee management attention or involvement is acceptable and considers nuclear safety, but weaknesses are evident; licensee resources appear to be strained or not effectively used such that minimally satisfactory performance with respect to operational safety or construction quality is being achieve Enclosure 2
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 Category 2 or 3. The final rating for each functional area is a composite of the attributes tempered with the judgement of NRC management as to the significance of individual item 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 discernible and the Board believes that continuation of the trend may result in a change of performance leve The trend, if used, is defined as:
Improving:
Licensee performance was determined to be improving near the close of the assessment perio Declining:
Licensee performance was determined to be declining near the close of the assessment perio III. Summary of Results Overall Facility Evaluation During the SALP assessment period, the McGuire facility was effectively managed and achieved a satisfactory level of operational safet Strengths were noted in the functional areas of security and outage In both these areas, technical personnel were well staffed and demonstrated compentency in performing their tasks. Management at all levels in these areas continued to show satisfactory performance especially in planning and giving priority to assigned events. Weaknesses were noted in the functional areas of plant operations, fire protection, emergency preparedness and licensin Improvements are needed in these area For example more vigilance is needed by the licensee in assuming timely corrective action and more involvement and control by management in implementing Appendix R in the fire protection are May 1, 1983 -
September 1, 1984 Functional Area August 31, 1984 February 28, 1986 Plant Operations
3 Radiological Controls
2 Maintenance
2 Surveillance
2 Fire Protection Not Rated
2 Security and Safeguards
1 Outages
1 Quality Programs and
2 Administrative Controls Affecting Quality Licensing Activities
2 Training Not Rated
Enclosure 2
IV. PERFORMANCE ANALYSIS Plant Operations 1. Analysis During this assessment period, routine and special inspections of plant operations were performed by the resident and regional inspection staff Facility operations generally reflected adequate preplanning and assignment of prioritie Facility operating procedures were adequate. However, there were a number of occasions when these procedures were not followed and enforcement action resulted. In addition, although operational decisions were usually made at management levels adequate to assure appropriate supervisory involvement a weakness was noted in management effectiveness as detailed belo The operations staffing levels exceeded the minimum required shift crew composition during this assessment perio In October 1985, in-service testing identified an apparent degradation in performance of the 1A nuclear service water (RN)
system pump. To support continued operation, the licensee cross connected the Unit 2 RN system with the apparently degraded pum Extensive interaction with NRC management transpired to agree upon the condition that cross connecting the two units' RN systems was an unreviewed situation and not acceptable without formal NRC review. The licensee removed the cross connect and subsequently substantiated that the pump was not degraded, rather the flow measurement device was at faul During followup of this matter, the NRC became aware of signifi cant fouling of heat exchangers supplied by the RN syste NRC inspectors pointed out to the licensee that the 1A containment spray heat exchanger was exhibiting a differential pressure of 32 psid versus a vendor documented clean design value of 15 psi Again, extensive interaction was required between the NRC and licensee management to agree upon an extended program of on-line system testing designed to determine the degree of fouling and hence operability of this heat exchanger and other components supplied by R Both units have continued in routine operation while flow balance tests and heat balances were performed on the equipment. Once the problem was recognized, the licensee placed extensive resources on solving it. It should be noted however, that prior to NRC involvement the licensee was not vigilant with a program of performance monitoring of the RN system to detect early signs of foulin During review of the RN system the licensee reported that the original preoperational test did not test this system in its most limiting post accident configuratio Enclosure 2
Operating staff training, knowledge of the facility, and attitude appeared to be good. Particularly, noteworthy is the expertise displayed by the operators in response to plant transient Response to the loss of.instrum-ent air event of November 2, 1985, was exemplar Significant operational events which occurred during this assess ment period included:
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On November 21, 1984 a reactor trip on Unit 2 occurred. As a result, the licensee detected that certain (JA) jumpers had been missing from solid state protection system cards since at least June 6, 198 On December 21, 1984, a reactor trip on Unit 2 occurred from 100% power due to a low-low steam generator level when operators mistakenly removed a Unit 2 inverter from service, instead of the adjacent Unit 1 inverter. The resulting loss of power to the analog controllers for steam generator level, feedwater flow and steam flow resulted in a feedwater transient, which was corrected by switching to manual control and transferring the controllers to another channe However, the transfer to another channel was done incompletely and when control was returned to the automatic mode, it caused the steam generator level to fall to the low-low trip setpoint. The cause of this event was the failure of the operator and independent verifier to properly identify the equipment being removed from servic In addition, the transfer of the steam generator program to an alternate channel was performed incorrectl On October 24, 1985, a reactor trip occurred from 100% power as a result of Steam Generator "C" low leve The inadvertent opening of the output breaker on the Channel II vital instrumentation and control inverter initiated the event. The steam generator level program selector switch for the nuclear power contribution (Channel II) failed due to the loss of power and was causing a level error signal which was closing the feedwater control valves for Steam Generators "B" and "C".
The decreasing steam generator levels were not noticed by the operators until the low-level alert was received at approximately the 45 percent leve Attempts to manually recover from this feedwater transient were unsuccessfu In April, 1985 during restart of Unit 2 following the refueling outage a significant water hammer occurred on the
"C" main steam line which was attributed to mechanical gags left on steam line drain valve Enclosure 2
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In April 1985, during a reactor trip recovery on Unit 2, The unit was made critical below rod insertion limit During a review of the regulatory requirements germane to the preoperational and surveillance testing of the Auxiliary Building Filtered Exhaust System (VA), it was determined that preoperat.ional testing was not performed in accordance with documented commitment On November 2, 1985 the flexible discharge line of shared instrument air compressor B failed resulting in reactor trips on both units and a safety injection on Unit On January 15, 1985 it was identified that Unit 1 had been operated with safety injection flowpath valves inoperabl Enforcement regarding this issue was pending at the conclusion of this evaluation perio Licensee upper management was extensively involved in the establishment of corrective actions for violations, stressing the importance of following procedures and correcting inadequacies in the procedures. Senior plant management demonstrated particular interest in determining the exact nature of problems and subsequently addressing those findings in management meetings, training and procedural review This is considered to be a significant strengt Further, an evaluation of the content and quality of a representa tive sample of the Licensee Event Reports (LERs)
submitted by McGuire 1 and 2 during the September 1, 1984 to February 28, 1986 Systematic Assessment of Licensee Performance (SALP)
period was performed using a refinement of the basic methodology presented in NUREG/CR-417 The principle weakness identified in the LERs, involved the failure to adequately identify failed components and to reference previous similar events. The failure to adequately identify the components that fail prompts concern that possible generic problems may go unnoticed by the industry for a longer time period. A strong point for the McGuire LERs is that the root cause, safety assessment, corrective action, and personnel error discussions were generally well writte The Licensee Event Reports (LERs),
in the main, contained adequate descriptions of the occurrences, enabling knowledgeable readers to fully understand the events. In several cases, the licensee provided a comprehensive update to the LER Licensee in-station investigations were routinely performed to address, assess, and correct both reportable and non-reportable event Enclosure 2
Eleven violations and one deviation were identified during this evaluation perio The violations can be categorized in the general areas of:
failure to follow procedures, failure to use procedures, inadequate procedures and operational non-compliance with existing Technical Specification requirement The identified violations and the deviation were: Severity Level IV Technical Specification violation for failure to maintain two trains of pressurizer heaters with their requi.red emergency power supplies as required by Technical Specification (369/85-30) Severity Level IV procedural violation for failure to have the senior reactor operators designated on the shift super visors' turnover checklist in the control room. (369/85-30, 370/85-32)
c. Severity Level IV Technical Specification violation for entering Mode 6 without performing an analog channel operational test on the source range monitors within the previous seven days and for beginning core alterations without performing an analog channel operational test on the source range monitors within the previous eight hours as required by procedure. (369/85-23) Severity Level IV procedural violation with (3) examples:
(1) failing to return the personnel airlock inner interlock key switch to the active position as required by procedure, (2) failing to complete or follow the shift supervisor's turnover checklist as required by procedure and (3) misiden tifying a valve while performing the Safety Injection System Operating Procedure. (369/85-21, 370/85-22)
e. Severity Level IV procedural violation for failing to adhere to an operating procedure when performing an estimated critical rod position. (370/85-21) Severity Level IV procedural violation with (3) examples:
(1) failure to return the main steam line drain valves to service as required which resulted in a main steam line water hammer, (2) operating an unlabeled valve which resulted in the rupture of the upper head injection sightglass, and (3)
failing to remove from containment loose debris, trash, and/or plastic which could cause a containment sump restriction. (370/85-17) Severity Level IV procedural violation for inadequately implementing a control power inverter shutdown procedur (370/85-03)
Enclosure 2
h. Severity Level IV procedural violation with two examples:
(1) failing to implement the requirements of applicable procedures resulting in testing two protective channels simultaneously (2) failing to lock open an isolation valve as specified following completion of maintenanc (369/85-06, 370/85-06)
i. Severity Level IV Technical Specification violation for operating from initial criticality until November 1984 with less than three operable channels of the overpower Delta T reactor trip logic. (370/84-35)
j. Severity Level IV procedural violation for performing an inadequate post trip review prior to reactor startup in that the post trip review did not evaluate and correct the abnormal response noted on 2 Channels of the overpower Delta T reactor trip system. (370/84-35) Severity Level IV procedural violation for performing an inadequate post trip review prior to reactor startup in that the post trip review did not evaluate and resolve the abnormal response noted on Pressurizer Heater Bank "A".
(369/85-45)
1. Deviation for failure to notify station security as committed to by the licensee pertaining to the McGuire Safe Shutdown System. (370/84-33)
2. Conclusion Category: 3 3. Board Recommendations The Board is concerned about the number of violations which occurred in this category, but is encouraged by an apparent positive trend during the SALP period that corresponds in time with changes in onsite managemen The Board is particularly concerned that apparent operational deficiencies associated with the nuclear service water system would not have been promptly identified or corrected without NRC involvemen Radiological Controls 1. Analysis During the assessment period, inspections were performed by the resident and by regional based inspector This included confirmatory measurements using the Region II mobile laborator Enclosure 2
The licensee's health physics staffing level was adequate and compared favorably to other utilities of similar size in that an adequate number of ANSI qualified licensee and contract health physics technicians were available to support routine and outage operation The radiation protection staff had been relatively stable over the past several years with promotions being the primary reason for personnel losse The licensee appeared to do an adequate job of screening contract radiation protection technicians before employment and had a high rate of contract technician returnees each outag The licensee has an adequate formal training and qualification program for radiation protection and chemistry technicians as well as contract technicians and plant personne The licensee submitted the radiation protection and chemistry technician training programs to INPO for accreditation in December of 198 Licensee management's support and involvement in the radiation protection program was generally strong. The licensee's approach to resolution of health physics technical issues was usually adequate and timely. The licensee maintained an onsite technical staff for resolution of technical problems and involvement of the corporate radiation protection staff appeared to be significant, particularly in the areas of radwaste and bioassay. Radiological involvement in preplanning for refueling outages was good with extensive involvement of the ALARA staff in developing work packages used in work evaluation and which formed the basis of radiological controls specified by Radiation Work Permit Both the Radiation Work Permit and the Respiratory Protection programs were found to be satisfactory in that no intakes exceeded the NRC action level of 40 MPC-hour The licensee's understanding of technical issues and the general approach to problem solving for radiological measurements were also adequate; however, several issues indicated lack of adequate management review and the timely resolution of identified concerns. Specific concerns included biases in gaseous effluent measurements, inaccurate Fe-55 measurements conducted by the licensee's approved vendor laboratory, and failure to adequately review, identify, and resolve biases for radiological environ mental gamma spectroscopy Quality Control (QC) data. The licensee has initiated a proposed change to Technical Specifications requirements for reactor coolant samplin The new change, requiring the development of new procedures and technology, is projected to maintain accurate measurements while reducing significantly the doses-received by technicians conducting sampling and analyse The licensee submitted the required effluent and environmental reports during the rating perio Both liquid and gaseous effluents were within limits for total quantities of radioactivity
Enclosure 2
release Licensee estimates for whole-body doses from liquids (9.66 E-2 mrem)
and gases (1.53 mrem) for January to June 1985 were similar to values reported from 1982 through 198 No significant trends in radioactive effluent release estimates nor dose estimates were note During the rating period, two reactive inspections were conducte The first concerned an unmonitored release of spent resin beads via the Unit 1 vent to the roof of the Auxiliary Building which was the result of failure to follow procedure The licensee's corrective action implemented design changes and procedure revisions to preclude recurrence of such release The second reactive inspection resulted from NRC review of ventilation systems which indicated that preoperation testing of filters for the auxiliary and control room ventilation systems deviated from FSAR commitment The deviation was the result of inadequate technical review of preoperational testing results by management and management failure to ensure compliance with regulatory requirements. Resolution of the deviation required the issuance by the NRC of two confirmation of action letters requiring the licensee to conduct the correct test Testing showed that the systems were adequate to meet their intended safety functions consequently, the licensee's corrective action was satisfactor However, actions to prevent further deviations were deemed inadequate. This issue is still under revie Personnel exposures for the site during this assessment period were approximately 777 man-rem for 1985 which was an increase in collective dose when compared to 505 man-rem in 1984. Nonetheless the collective dose remained below average for a two unit pressurized water reactor facility (approximately 850 man-rem).
The licensee lost some effectiveness in their contamination control program over the assessment period. On September 1, 1984, the licensee maintained as contaminated 15,361 square feet or 2 percent of the controllable area of the plant whereas by February 28, 1986, this area had increased to 24,615 square feet or 35.7% of the controllable area of the plant. The licensee had designated several areas of the plant as not controllable, e.g.,
the evaporator rooms, and these were omitted from the above figure During the last quarter of 1985, the licensee had initiated action to increase their decontamination effort During the assessment period, 476 instances of personnel contamination had been documente One of these resulted in an overexposure of 10.6 rem to the skin of the whole body of a worker in a calendar quarter. The licensee initiated prompt corrective action to prevent recurrenc Enclosure 2
During the assessment period, the licensee disposed of 30,954 cubic feet of solid radioactive waste containing 909 curies. This represented approximately a 30% increase over the national average of 23,300 cubic feet shipped by other utilities with similar PWR facilities. However, the increase is not considered significan Approximately 1,173 cubic feet of solid waste remained onsite at the end of the.assessment perio The following violations and deviations were identifie a. Severity Level IV violation for failure to post a radiation are (369/85-22, 370/85-23)
b. Severity level IV violation for failure to control licensed material such that an individual received an occupational dose in excess of NRC limits of 10.6 rems to the ski (369/85-22, 370/85-23)
c. Severity Level IV violation for failure to perform routine surveys. (50-369/85-44, 50-370/85-45) Severity level IV violation for failure to follow an operating procedure resulting in the release of radioactive spent resi (369/85-11)
e. Deviation for failure to complete preoperational testing of Control Room Area Ventilation (CV) systems in accordance with FSAR Commitments. (369/85-39, 370/85-40)
2. Conclusion Category: 2 3. Board Recommendations No recommended changes in NRC inspection resource C. Maintenance 1. Analysis During the evaluation period, routine inspections were performed by the resident and regional inspection staff The maintenance program appeared to be well organized with a well trained, qualified staf Maintenance related decisions were usually made at management levels to assure appropriate supervisory involvemen Licensee resolutions to maintenance related technical issues generally
Enclosure 2
indicates clear, thorough understanding of the issues and were usually conservative and viable. Maintenance activities generally exhibited evidence of adequate preplanning and assignment of prioritie Significant events which occurred during this assessment period included:
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On October 27, 1984, an Upper Head Injection gas entrainment problem on Unit 1 occurred and ultimately involved both units. The problem was attributed to reversed plumbing and calibration non conservatisms of the accumulator level transmitter On June 24, 1985 a two inch main feedwater bypass line on Unit 2 failed during a reactor tri The failure was attributed to a poorly designed mechanical suppor In July 1985 the Unit 2 electrical generator experienced a complete mechanical failure of the permanent magnet generato It was noted, however, that a disproportionate number of the unplanned reactor trips can be either directly or implicitly related to maintenance activities. In that view, a review of the preventive maintenance program, associated prioritization and backlog is recommende Procedures were generally adequate with a continuing effort to locate and eliminate weaknesse The licensee has a detailed process for completed maintenance record review, which generally was very thorough and identified and corrected deficiencies contained in their record The use of procedures in accom plishing maintenance activities was generally adequate, with procedures detailed enough to allow proper performance of the specified task The licensee's program for removal and restoration of equipment was adequate. Maintenance personnel were sufficiently knowledge able of program requirements to allow for proper implementatio Three violations and a deviation were identified as detailed below which are not considered indicative of a programmatic breakdow a. Severity Level III upperhead injection accumulator system inoperable in Modes 1, 2, and 3 with pressurizer above 1900 psig and failure to provide adequate instructions, acceptance criteria, and test program. (369/84-34, 370/84-31)
Enclosure 2
b. Severity Level IV violation for maintenance actions which took both trains of control room ventilation out of service simultaneously. (369/85-03, 370/85-03)
c. Severity Level IV violation for maintenance activities associated with accumulator level transmitter. (370/85-29)
d. Deviation for failure to perform discharge tests on all four vital and instrument control batterie (369/85-10, 370/85-11)
2. Conclusion Category: 2 3. Board Recommendations No change in NRC inspection activity is recommende D. Surveillance 1. Analysis During the evaluation period, routine inspections were performed by the resident and regional inspection staff The licensee appeared to have an adequate program for scheduling surveillance testing which identified surveillance requirements by due dates and issued a weekly schedule. This program is computerized and controlled by the integrated scheduling personne Tests were normally completed on tim As a general rule, surveillance activities reflected adequate preplanning and assignment of prioritie Facility surveillance procedures were usually adequate with few examples of deficiencies identified. Surveillance activities were, in general, thorough and proper with exceptions identified belo The surveillance records were given thorough post completion review The surveillance testing and calibration control program implementation appeared adequate and the attitudinal emphasis and quality were favorabl However, programmatic weaknesses were identified in that procedural deficiencies existed and oversights have occurred such as missing reviews and scheduling errors in the Periodic Maintenance/Periodic Test (PM/PT) master inde Licensee resolution of surveillance related technical issues generally indicated a clear and thorough understanding of the issues and was usually conservative and viabl Enclosure 2
Six violations were identified in this area as detailed below:
a. Severity Level IV violation for failure to test diesel generator fuel oil transfer pump within surveillance interva (369/85-06, 370/85-06).
b. Severity Level IV violation for failure to perform required vital battery surveillance. (369/85-10, 370/85-11) Severity Level IV violation for failure to verify valve motor design specification. (369/85-16, 370/85-17)
d. Severity Level IV violation for inadequate procedures and failing to follow procedures during surveillanc (369/85-23, 370/85-24)
e. Severity Level IV violation for failing to perform PORV and refueling canal drain surveillance test. (370/85-41)
f. Severity Level IV procedural violation for failing to provide an adequate procedure to ensure that the overpower Delta T lead-lag derivative cards were correctly installed and for failing to test the overpower Delta T reactor trip system in a manner that would confirm that the system would perform satisfactorily. (369/84-40, 370/84-35)
2. Conclusion Category: 2 3. Board Recommendations No change in NRC inspection activity is recommende Fire Protection 1. Analysis During this assessment period, inspections were conducted by the Regional and Resident Inspection staff of the licensee's fire protection progra The Regional inspection efforts were primarily a review of the dedicated Standby Shutdown System (SSS)
and associated fire protection features which were provided to meet the requirements of 10 CFR 50, Appendix The Appendix R safe shutdown and related fire protection features for McGuire were required to be implemented for Unit 1 on April 29, 1983 and prior to March 1, 1984 for Unit These inspections identified that although the Appendix R dedicated shutdown system, identified as the SSS, was operational prior to these dates it was not maintained fully operationa The diesel
Enclosure 2
engine for the SSS emergency generator was out of service on several occasion Surveillance tests on the Unit 1 standby makeup pump, which is part of the SSS and provides reactor coolant system makeup should the normal charging system be unavailable, were not conducted between April 1983 and April 1984. The boron water supply to the Unit 2 standby makeup pump was not verified for the correct boron concentration between March 1984 and September 1984. Surveillance procedure tests for portions of the SSS emergency diesel generator were not available and not implemented until after September 198 Several of the SSS instrumentation devices for the Unit 1 portion of the SSS remote shutdown panel were not properly calibrate These items were identified as examples of a violation involving the failure to maintain the SSS fully operationa The inspection also identified a number of areas in which the licensee failed to meet Appendix R. Also, the licensee immediately prior to the Region II inspection identified a number of items at McGuire which did not meet the Appendix R require ments. Some of these items are considered minor and the licensee has submitted a deviation request with appropriate justification to NRR for review and approva Several items were more significant and the licensee took action to correct the discre pancie Cabling to the valve operators for the SSS Unit 1 turbine driven auxiliary feedwater pump suction valves in one plant area and the control cables for both trains of charging and auxiliary feedwater systems in another plant area were in the same fire area as the redundant shutdown component cable These were not provided with the required fire protection features, either the SSS or normal shutdown train was not enclosed within a three hour fire barrier. This item was identified as a violatio The shutdown related circuits were reviewed and due to the availability of the SSS were found to meet the NRC associated circuits concerns for common bus, spurious signal and common enclosur A review of the plant operational procedures identified a number of concerns, which were addressed by the Region II Confirmation of Action letter that was sent to Duke on October 9, 198 The licensee promptly revised the procedures to address the inspectors concerns. A review of the licensee's program indicated that a well organized, detailed and comprehensive training program was implemented for the operation and use of the SSS using the available procedure Also, fire damage control procedures were provided to identify components needed for cold shutdown and the required restoration if any component or associated cabling is damaged by fir The equipment and cabling required by these procedures are controlled and well maintaine Enclosure 2
Eight hour emergency lighting units are provided to meet the requirements of Appendix R Section III.J, except for portions of the plant in which the licensee has committed to use battery powered hand light However, these hand lights were not available at the beginning of the inspection. This was identified as a deviation. Procedures for the maintenance and testing of the emergency lighting units were available, but were considered inadequate. The licensee committed to revise the procedures to address the inspectors' concern Communications between the various areas of the plant in which local control actions must be taken during shutdown operations using the SSS were deficien The licensee has committed to provide portable radios for use when the SSS is require Portable radios were available, but communications could not be established between the local control stations and the SSS facility due to transmission interferences apparently caused by plant structures. This was identified as a deviation ite Based on a review of construction documents, the inspectors determined that the oil collection system for the reactor coolant pumps met the requirements of Appendix R, Section 11 In general, the management involvement and control in assuring quality in the implementation of the Appendix R fire protection requirements was somewhat deficient. The SSS was not maintained operational after turnover to the operational group and a number of other plant areas did not meet the Appendix R requirement The licensee's approach to resolution of technical fire protection issues indicates an apparent understanding of the Appendix R requirements. The responsiveness to NRC initiatives are generally timely, but have required repeated submittals on a few items to obtain acceptable resolutions. Fire protection related violations periodically occur but do not indicate a programmatic breakdow Corrective action is normally timely and effectiv Licensee identified fire protection related events or discrepancies are properly analyzed, promptly reported and effective action take Staffing for the fire protection program is adequate to accomplish the goals of the position within normal work hour Fire protection staff positions are identified and authorities and responsibilities are clearly define Personnel appear well qualified for their assigned dutie The following violations and deviations were identified:
a. Severity Level III violation involving the failure to provide the Appendix R Section III.G fire protection and separation features required for redundant trains of normal shutdown system and the dedicated Standby Shutdown System components and cabling. (369/84-28)
Enclosure 2
b. Severity Level IV violation involving the failure to provide structural steel fire barrier supports with a fire resistant rating equivalent to the fire resistant rating of the barrier. (369/84-28, 370/84-25)
c. Severity Level IV violation involving the failure to perform periodic surveillance tests on the Standby Shutdown Syste (369/84-20, 370/84-17)
d. Severity Level IV violation for failure to assure unlocked fire doors were closed. (369/85-21, 370/85-22)
e. Severity Level V violation for failure to remove combustible liquid penetrant materials from a control access are (370/85-05)
f. Deviation for the failure to provide adequate radio communication capability between local control stations and the Standby Shutdown System control roo (369/84-28, 370/84-25)
g. Deviation for the failure to provide battery powered hand lanterns in the control room for use in plant and yard areas which do not have the required eight hour battery powered emergency lighting unit (369/84-28, 370/84-25)
2. Conclusion Category:
3. Board Recommendation The Board notes that a number of plant areas did not meet the 10 CFR Appendix R requirements during the SALP period. However, once identified they were properly analyzed and effective action take No change in NRC inspection activity is recommende F. Emergency Preparedness 1. Analysis During the assessment period, inspections were performed by regional and resident inspection staff These included observation of two exercises, the conduct of two routine inspections, and an emergency response facility appraisa Routine inspections and exercise evaluations indicated that the onsite emergency organization was effective in dealing with simulated emergencie Adequate staffing of the emergency response facilities was demonstrate Corporate management appeared to be committed to maintaining an effective emergency
Enclosure 2
response program and was directly involved in the annual exercises and associated critique Personnel assigned to the emergency organizations understood their emergency response roles, and were adequately trained in required areas of emergency response, except as indicated abov During routine inspection interviews, walk through, and observations, emergency response personnel demonstrated the following capabilities:
prompt and effective classification of hypothetical emergency events; implementation of appropriate action to control the plant casualty; prompt notification of State, local and to the offsite organizations; protective action recommendations; and performance of dose assessments and projections; and controlled management of field monitoring team Inspections, disclosed one violation in the area of promptness in submittal of Emergency Plan Implementing Procedure revisions to NR Exercise observation by the NRC disclosed weaknesses in the following areas:
training of offsite support agencies; access control to the Emergency Response Facilities; effective management control and direction of OSC facility and staf A comprehensive evaluation of the Emergency Response Facilities was conducted to determine the status of completion of require ments defined in Supplement 1 to NUREG-073 The team appraisal identified two weaknesses in the meteorological measurements and Control Room dose assessment area Six incomplete items and thirty-one areas for improvement were also identified. There were no appraisal findings which would cause a major impediment to an emergency respons Plant and corporate management have been responsive in resolving the identified weaknesse Notwithstanding the above findings, routine inspections and exercise evaluations indicated that the onsite emergency organization was effective in dealing with simulated emergencie Adequate staffing of the emergency response facilities was demonstrate The following essential elements for emergency response were found acceptable:
emergency classification; notification and communi cations; public information; shift staffing and augmentation; emergency preparedness training; dose projection and assessment; emergency worker protection; post accident measurements and instrumentation; changes to the Emergency Preparedness Program; and annual quality assurance audits of the plant and corporate emergency planning programs, except as identified abov The exercises demonstrated that the plan and procedures could be
Enclosure 2
effectively implemented in the areas of communications, accident assessment, and exposure control. The licensee also demonstrated an adequate working relationship with offsite emergency support organization The licensee -has been responsive to NRC initiatives regarding correction of identified weakness and suggested program improvement One violation was identified. These findings were not indicative of a programmatic weakness or breakdown:
Severity Level V violation for failure to submit copies of Emergency Plan and procedures to NRC within 30 day (369/85-02, 370/85-02)
2. Conclusion Category:
3. Board Recommendation The Board notes plant and corporate management have aggressively pursued problems. No change in the NRC inspection resources are recommende G. Security and Safeguards 1. Analysis During this evaluation period, various inspections were performed by the resident and region staff In addition, one special inspection was conducted in response to the licensee reporting a safeguards even The licensee continues to exhibit management involvement, at both Corporate and site levels, with the planning and prioritization of the entire security program. Independent audits performed by the General Office are considered thorough and accurate, and findings are appropriately resolved. The licensee exhibits an aggressive ness in identifying and correcting programmatic weaknesses as evidenced by the fact that two of the four violations were discovered by site security personne The licensee utilizes a contract security force which is monitored by proprietary Security Technical Associates who continually audit the contractor and resolve licensee identified issue Additionally, the contractor has its own Contract Compliance Review Program which ensures each security shift adheres to the licensee's approved security procedure Enclosure 2
The licensee's responses to NRC findings and its submittals of Plan revisions can be relied upon as factual and reflective of an understanding of technical issues. The licensee's reporting of safeguard events (bomb threats) are timely, accurate and thoroug The licensee's response to such events is considered well coordinated and supervise During this evaluation period the site security force was found to be well staffed, appropriately equipped and effective in the performance of its routine security dutie Four violations were cited during this evaluation period:
a. Severity Level IV for failure to maintain a security barrie (369/84-37, 370/84-32)
b. Severity Level IV for failure to protect vital equipmen (369/85-26, 370/85-31)
c. Severity Level IV for failure to maintain a security barrie (369/85-26, 370/85-31)
d. Severity Level IV for failure to maintain a security barrie (369/86-03, 370/86-03)
2. Conclusion Category:
3. Board Recommendation No change in the NRC inspection resources are recommende H. Outages 1. Analysis During this evaluation period inspections were performed by the resident and regional office staff Fuel handling activities were witnessed from the refueling floor, spent fuel pool and control roo Staffing during refueling was adequate with authorities and responsibilities defined in the procedures applicable to fuel loadin Total core unloading for Unit 2, started February 24, 1985 and ended March 3, 198 Adequate housekeeping, radiological, and accountability controls were established and implemente Enclosure 2
One deviation was identified for Unit 2, failure to provide procedures for core unloading and reloading to prescribe operator actions as stated in the November 21, 1984 response to IEB 84-0 Licensee resolution to technical issues generally reflected clear and thorough understanding of the issue Five inspections were conducted during this evaluation period by Regional Based Inspector Areas inspected included inservice inspectors activities (ISI), performance testing of pumps, valves and hydraulic snubbers, personnel training, nuclear service water pump repair and weldin The licensee continues to show satisfactory performance in the aforementioned areas. The inservice inspection program is staffed by competent personnel who are thoroughly cognizant of applicable code requirements and implement them in a conservative manne The pump and valve performance testing program and the hydraulic snubber functional testing programs are administered by equally competent personnel who are thoroughly familiar with code require ments. Technical/maintenance personnel in both areas were found to be adequately trained for their assigned task Although a violation was recently identified in the pump and valve surveil lance program, it appears to be one of oversight rather then one with broad programmatic breakdown implication It is noteworthy here to mention the large maintenance and construction cadre located at McGuir The force is employed to efficiently and effectively implement outage maintenance activities and plant modifications. This inordinately large, maintenance/modification staff is a strength in terms of outage executio The one aforementioned violation and deviation were as follows:
a. Severity Level IV violation for failure to comply with Technical Specification requirements on valve position indicator verificatio (369/86-05, 370/86-05)
b. Deviation for failure to provide procedures for core unloading and reloading to prescribe operator actions in response to IEB 84-03. (370/85-07)
2. Conclusion Category:
3. Board Recommendation The Board recognizes an improving trend and has no recommended changes in NRC inspection resource Enclosure 2
I. Quality Programs and Administrative Controls Affecting Quality 1. Analysis During this assessment period, routine inspections were performed by the resident inspector and regional staff. The following areas were reviewed by the regional staff during this period:
QA program, QA/QC administration, measuring and test equipment, offsite support staff, audits, surveillance testing and calibra tion control, design control, test programs, procurement, and receipt, storage, and handlin The Quality Assurance (QA)
maintained an acceptable QA program throughout this assessment perio It was determined by inspection that lead auditor training was well defined and implemented. The QA surveillance and audit programs functioned well; however, a program deficiency was identified in that procedures for handling the corrective actions for nonconformances and audit findings were inadequately defined. These inadequacies were discussed with licensee management during a telephone conversation conducted on November 1, 198 Based on this conversation, licensee management agreed to revise existing procedures to strengthen the handling of corrective actions for nonconformances and audit finding The issuance of audits within Technical Specification (TS)
timeframes was identified as being deficien This problem was also identified during a Joint Utility Management Audit (JUMA).
Corrective actions were being taken to assure that audits were issued as require The offsite support staff was evaluated as being satisfactor Management has reorganized the QA staff to provide for increased effectiveness of QA activitie The test and experiments program was well developed and adequately delineated procedurally. However, a program deficiency associated with the performance of nuclear safety evaluations was identifie This concerned the inadequacy of the nuclear safety evaluation checklist in documenting specific reviews and actions taken to arrive at the determination of whether or not an Unreviewed Safety Question (USQ) exist Management's responsiveness to the resolution of this issue was demonstrated when they revised the checklists to provide substantiating information for USQ determinatio Control of parts and materials was excellent due in part to strong supervisory oversigh A new level "A" storage facility was recently completed. The procurement policy was well understood by the staff; well coordinated interfaces existed between the various
Enclosure 2
site and corporate office staff personnel for procurement activitie Adequate and complete records were available for verifying procurement program implementatio Receipt inspection and onsite certification activities were adequately controlle The licensee identified a weakness relative to preventing the purchase of defective components identified by 10 CFR 21 Notifications.. Corrective action was in progress for the weaknes In October 1984, the nuclear station modification program (design program)
was revise This resulted in the preparation of the Nuclear Station Modification Manual which specifies the appropriate requirements to be met to implement a modification at an operational nuclear statio Concurrently, the Design Engineering Department Manual was reformatted and revised to allow a better understanding and handling of the Department Manual procedure Design program requirements appear to be well delineated; however, a programmatic deficiency was identified in that past modification test requirements and test acceptance criteria were not adequately specified by the Design Engineering Department for station modifications designed by this departmen This inadequacy is most apparent in the failure of the Upper Head Injection (UHI)
accumulator system. An evaluation of this incident identified one of the root causes to be inadequate post-modification test procedure An improved post-modification test program is required to better demonstrate management's approach to the resolution of technical issues from a safety standpoin A civil penalty was imposed on Duke Power Company in connection with an event that involved the failure of the Upper Head Injection (UHI)
accumulator system isolation valves to close at the required UHI accumulator water leve An evaluation of this event identified the root cause to have been inadequacies in the electronic differential pressure transmitter instrument installa tion, post-modification testing procedures, and instrument calibration procedures. The combined effect of these inadequacies is indicative of a weakness in the QA program as it pertains to the training and qualification effectiveness of Duke Power Company employee Additional failures of the QA program in the functional areas of design changes, operations, and surveillance were demonstrated by violations identified during this reporting perio These failures identify a continued need for management's involvement in assuring quality and an improved approach to the resolution of technical issues from a safety standpoin Enclosure 2
Six violations were identified:
a. Severity Level IV violation for failure to implement nuclear safety evaluations for changes to the Xenon Follow/Predict Program. (369/85-20, 370/85-21) Severity Level IV violation for failure to retain completed shutdown margin calculations that document compliance with acceptance criteria. (369/85-20, 370/85-21)
c. Severity Level IV violation for failure to perform adequate safety evaluations for operation of a single cell battery charger. (369/85-10, 370/85-11)
d. Severity Level IV violation for failure to provide adequate design control measures to ensure that wiring separation criteria are met. (369/85-06)
e. Severity Level IV violation for failure to take prompt corrective actions to notify Operations personnel of potential degradation of the Auxiliary Feed Water System and correct improper installation of the turbine driven auxiliary feedwater pump discharge stop check valv (369/85-06, 370/85-06) Severity Level V violation for failure to perform audits within Technical Specification required time fram (369/84-32, 370/84-29)
2. Conclusion Category: 2 3. Board Recommendations No recommended changes in NRC inspection resource Licensing Activities 1. Analysis This performance assessment is based on our evaluation of the licensee's performance in support of licensing actions that had a significant level of activity during the evaluation period. These actions include licensee request for amendments and exemptions or relief from regulatory requirements, responses to generic letters, and various submittals of information for multi-plant and NUREG-0737 action Licensing actions were completed as delineated in Supporting Data, Section Enclosure 2
There is evidence of prior planning and assignment of priorities, and decision making appears to be at a level that ensures management revie Well stated, controlled, and explicit procedures are in place for control of activitie Reviews are generally timely, and technically sound. Communications with NRR is frequent and effectiv Management involvement was particularly evident during NRC reviews and meetings on licensee's requests involving plant modifications (e.g.,
storage of Oconee spent fuel in McGuire Unit 2 pool, UHI deletion, RTD bypass removal). Effective management involvement was also evidenced by completion of environmental qualification of electrical equipment within the schedule specified by 10 CFR 50.4 Increased management attention is needed to improve the adequacy and content of Duke's proposed technical specification amendment Three submittals were returned by NRR without processing because they contained ambiguous and inadequate bases for No Significant Hazards Considerations. Five submittals were denied by the NRC in total or in part because of inadequate technical justificatio Staff review of one submittal involving Doghouse Water Level Instrumentation was complicated by the absence of any descriptive system information in the submittal or in the FSA The licensee understands the technical issues and the responses are generally soun The licensee considers carefully and thoroughly the impact of various NRC requests and positions on the plant. Conservatism is generally exhibite This resulted in efficient reviews by NRR for licensee's request associated with reload amendments for Unit 1 Cycle 3 and Unit 2 Cycle 2, storage of Oconee fuel at Unit 2, UHI deletion, increased containment integrated leak rate criterion, detailed control room design reviews and safeguards program The licensee understands well the regulatory environment and takes an active role from the safety standpoin Duke often takes.the lead or is an active participant with the nuclear industry to help resolve matters of generic concer For example, the licensee participated in the Westinghouse Owners Group to develop improved steam generator tube rupture and small-break LOCA method The licensee also plays a leadership role in current NRC-Industry efforts to improve Technical Specifications. In response to NRC positions regarding records on RTS Breaker Maintenance, Duke has committed to work with appropriate ANSI committees to determine generic positions regarding the appropriate retention period for post-trip record Enclosure 2
The NRC recommends continued and more frequent use of combined facility submittals when requesting technical specification changes. This should provide a needed improvement in coordination and consistency of position among Duke facilities while providing for more efficient use of man power resource It should also provide for more timely requests on the part of each individual facilit For example, the request on McGuire to increase the number of operable and operating RC loops consistent with the safety analyses occurred more than a year after the same correction had been identified on Catawb The licensee usually provides timely responses to NRC requests for information. Responses to technical issues are generally complete and acceptable resolutions are initially proposed in most case The licensee has provided timely response to a large number of staff surveys and telephone requests such as the surveys regarding diesel generator requirements for cold fast start Duke attempts to meet deadlines and notifies NRC when they cannot be met. However, it appears that the licensee is more responsive to those issues that Duke considers as having higher priority (those issues affecting plant operation or modifications and involving relief from requirements). Issues to which Duke assigns lower priority frequently require schedule extension Duke should assume a more aggressive role in pursuing design changes to improve effective sustained operation of the Auxiliary Building Filtered Ventilation Exhaust System during humid condition From our review of licensee's responses to enforcement issues, NRR finds licensee's resolutions to be generally technically sound and effectiv During site visits on June 21, September 9 and October 8, 9, 21, and 22, 1985, the staff toured several plant areas including the Auxiliary Building, Turbine Building, Control Room, and Safe Shutdown Facilit The staff found the plant to be in relatively good order with respect to cleanliness, and housekeepin Activities in the control room were observed to be conducted in a professional manner with assigned personnel appearing to be alert and attentive to duty. Staff morale appeared to be hig Most personnel seemed to exhibit pride in their facility and in their job. Conclusion Category: 2 Board Recommendations
Enclosure 2
Licensee should pay increased attention to its submittals to the NRC and should seek to improve the timeliness of various types of responses to NRC request Licensee should strive to be more comprehensive in analyses and actions following operational event K. Training 1. Training During the assessment period, routine inspections of plant training programs were performed by Regional and Resident inspection staff Although weaknesses were identified in the administration of certain training programs, training was determined to be acceptable to support safe facility operatio Management continued to be responsive to NRC initiatives and sought training program improvement throughout the assessment perio Managements responsiveness was exemplified by the establishment of a program to periodically place non-routine licensed watch standers on shift, efforts to achieve INPO accreditation and the implementation of the Employee Training and Qualification Syste Adequate facilities were provided to enhance instructional delivery and achieve plant training goal The Technical and Technology Center located near the McGuire site houses, the Technical Training Center which is used for basic training for all Duke facilities in all phases of nuclear power plant functions such as Operations, Instrument and Electrical, Chemistry, Engineering, Performance Technician training, et In addition, it houses the McGuire simulator for plant specific simulator training. The Technical Training Center alone occupies approximately 60,000 sq. ft. and has been in use since October of 198 Licensed operator requalification training was determined to be satisfactory with the exception of administrative deficiencies in the delineation of administrative requirements, the accountability and specification of exemption practices, and the documentation and control of lecture attendance. Examinations provided compre hensive assessments of trainee knowledg Simulator instruction was well managed and provided adequate practice manipulations and lecture reinforcemen Operating staff training, knowledge of the facility, and attitude appeared to be goo Operator licensing examinations were conducted during the evaluation period, including both written simulator and oral examination Licensing examinations were given to two reactor operator candidates and fourteen senior reactor operator candidates; both reactor operator (RO)
and ten senior reactor operator (SRO) candidates passed-their examinations and received license Two of the senior reactor operator
Enclosure 2
candidates who failed the initial examination were administered retake examinations with both passin These results are comparable to the industry norm. Based on the examination results for licensed operators, the licensee appeared to have instituted an adequate licensed operator training progra A well organized, detailed and comprehensive training program was implemented for the operation and use of the SSS using the available procedure Overall training for non-licensed employees remained satisfactory throughout the assessment period. Basic training was adequately administered and ensured the competency of plant personne. Conclusion Category: 2 3. Board Recommendations No recommended changes in NRC inspection resource V. Supporting Data and Summaries Licensee Activities Unit 1 McGuire Unit 1 began the assessment period at full powe In addition to the reactor trips which are discussed elsewhere in this report, the unit experienced a number of operations impediment In October of 1984, the unit had to be shut down due to elevated temperatures inside containment which was attributed to fouled containment cooler Power was reduced in January and February 1985, respectively, due to freezing of exposed instrument line and a hydrogen cooler leak in the main electrical generato The unit underwent a refueling outage during the April - June timeframe returning to critical operations on June 2 The unit was forced to severely reduce power twice in September due to low reactor coolant pump oil leve In November 1985, the unit experienced a reactor trip and safety injection due to a loss of instrument ai The unit completed the assessment period at full powe Enclosure 2
Unit 2 McGuire Unit 2 began the assessment period at full powe In October 1984, the unit was forced to operate at reduced power levels due to a leaking main feedwater check valve and a high nitrogen content in the upper head injection (UHI)
water inventor The unit was forced to operate at reduced power levels.part of the month of November 1984 due to UHI inoperabilit The unit underwent a routine refueling outage during the period of January -
May timeframe. The unit was taken critical on May 5 and operated virtually unencumbered until July 12 when the permanent magnet generator on the main electrical generator faile In November 1985, the unit experienced a reactor trip due to a loss of instrument air. Following recovery from the trip, the unit operated until December 11 when the unit was shut down for a short outage to plug leaking steam generator tube On December 25, following the short maintenance outage, the unit was returned to power where it remained virtually throughout the remainder of the report perio Inspection Activities During the assessment period, routine inspections were performed in the
- areas of facility operations, radiation protection, radiological controls, surveillance activities, maintenance activities, fire protection, emergency preparedness, security and safeguards, refueling activities, steam generator modification activities, inservice inspection, and quality assuranc Six special inspections were performed in the areas of Fire Protection, Security, and Plant Operation Four team inspections were performed in the areas of Emergency Preparedness, Plant Operations, and TMI Action Item Licensing Activities The basis for the appraisal in this area was the licensee's performance in regards to both plant-specific requests (primarily for amendments to change Technical Specifications) and responses to generic issue These items included those which were either concluded or sufficiently active during the rating period to provide a basis for assessmen Plant-Specific Licensing Actions
-
Delete surveillance of SG blowdown valves
-
Response to DPO Tech Specs
-
Unit 2/Cycle 2 Reload
Enclosure 2
-
Unit 1/Cycle 3 Reload
- Storage of Oconee Spent Fuel at Unit 2
- Surveillance of Ice Condenser Doors
- Snubber-Inspection Sample Plan
- Surveillance of CL Accumulator
- Surveillance of UHI
- Working Hours of Plant Staff
-
Dose Projections of Normal Releases
- Use of ASME Code Cases N-411 and N-397
- Safeguards
- Excore Thermocouple Schedule
-
Rod Position Indication System
- Admin. Controls and Reporting
-
RTS Outage Times
-
Fire Pump Power Source
- Containment Pressure Control System
-
Doghouse Water Level Ins Increase in Number of Operable RC Loops
-
UHI Deletion
-
Operate at 46% power without UHI
-
Increase Containment Leak Rate
-
Retention of Post-Trip Records Generic Licensing Actions
- GL 83-28 (Salem ATWS) Items 1.1, 1.2, 3.1, 3.2, 4.1, 4.2, 4. RVLIS and Subcooling Monitor
-
Control of Heavy Loads (Phase I & II)
-
Safety Parameter Display System
- Elimination of Large Primary Pipe Breaks
- GL 84-14 Replacement and Requal. Training Programs
- Detailed Control Room Design Review
-
Hydrogen Control License Amendments Issued 37/18 Operation at 46% power w/o UHI 10/31/84 38/19 Time Overcurrent Trips for DG Breakers 02/01/85 39/20 Delete Operation at 46% Power w/o UHI 02/06/86 40/21 Subcooling Margin Monitors and RVLIS 02/28/85 41/22 Delete Surveillance of SG Blowdown Valves 03/18/85 42/23 Unit 2 -
Cycle 2 Reload 03/22/85 43/24 Unit 1 -
Cycle 3 Reload 05/15/85 44/25 Storage of Oconee Fuel at Unit 2 07/26/85 45/26 Surveillance of Ice Condenser Doors 09/16/85 46/27 Snubber Inspection Sampling Plan 09/30/85 47/28 Surveillance of CL Accumulators and UHI 11/01/85
Enclosure 2
48/29 Working Hours/Overtime for Plant Staff 11/12/85 49/30 Dose Projections/LC on Core Exit 11/22/85 Thermocouple Schedule 50/31 Rod Position Indication System 01/09/86 Investigation and Allegation Review No major investigative activities occurred during this assessment perio Escalated Enforcement Actions 1. Orders None Civil Penalties
-
A Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $50,000 was issued February 20, 1985, based on the failure of the upper head injection (UHI)
accumulator system isolation valves to close at the required UHI accumulator water leve The licensee responded on March 22, 1985, and after consideration of the response, an Order Imposing Civil Monetary Penalty was issued on June 21, 198 The licensee paid the civil penalty on July 3, 198 A Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $40,000 was issued on June 8, 1984, based on a violation involving the mispositioning of a Unit 2 containment spray recirculation valve and the failure to properly perform an independent verification of the valve position. The licensee responded on July 6, 1984, and after considering the response, an Order was issued on September 26, 198 The licensee paid the penalty on October 25, 198 F. Management Conferences Held During the Evaluation Period
-
An enforcement conference was held at the Region II office on November 14, 1984, to discuss the inoperability of the Upper Head Injection Syste An enforcement conference was held at the Region II office on March 26, 1985, to discuss the inoperability of the Control Area Ventilation System Chille An enforcement conference was held at the Region II office on July 3, 1985, to discuss the failure to meet the operability requirements for DC batterie Enclosure 2
-
An enforcement conference was held at the Region II office on July 12, 1985, to discuss an overexposure to the ski An enforcement conference was -held at the Region II office on January 14, 1986, to discuss the yard drainage system and barrier An enforcement conference was held at the Region II office on February 28, 1986, to discuss the inoperability of the Volume Control Tank isolation valves and the inoperable Chemical and Volume Control Syste Confirmation of Action Letters A Confirmation of Action Letter was issued by Region II on October 9, 1984, concerning certain deficiencies in your procedures used to achieve and maintain hot standby and to proceed to cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as required by 10 CFR 50, Appendix A Confirmation of Action Letter was issued by Region II on October 23, 1985, concerning control room and auxiliary building ventilation system filter testin A Confirmation of Action Letter was issued by Region II on November 5, 1985, concerning an air-aerosol mixing uniformity test for the control room area ventilation filter system H. Review of Licensee Event Reports and 10 CFR 21 Reports Submitted By the Licensee During the assessment period, 31 LERs for Unit 1 and 37 LERs for Unit 2 were evaluated by the NRC staff to determine event caus The distribution of these events were as follows:
Cause Number Unit 1 Unit 2 Component Failure
7 Design
1 Construction/Fabrication/Installation
Personnel
- Operating Activity
11
- Maintenance Activity
3
- Test/Calibration Activity
3
-
Other Activity
6 Out of Calibration
-
Other
2 TOTAL
37
Enclosure 2
I. Enforcement Activity UNIT SUMMARY FUNCTIONAL NO. OF DEVIATIONS AND VIOLATIONS IN EACH AREA SEVERITY LEVEL D
V IV III II I
UNIT N /2 1/2 1/2 1/2 1/2 1/2 Plant Operations 0/1 7/7 Radiological Controls 1/1 4/3 Maintenance 1/1 1/2 1/1 Surveillance 5/6 Fire Protection 2/2 0/1 3/3 1/0 Emergency Preparedness 1/1 Security 4/4 Outages 0/1 1/0 1/1 Training Quality Programs and 1/1 5/4 Administrative Controls Affecting Quality TOTAL 4/6 3/3 30/30 2/1 FACILITY SUMMARY FUNCTIONAL NO. OF DEVIATIONS AND VIOLATIONS IN EACH AREA SEVERITY LEVEL D
V IV III II I
Plant Operations
11 Radiological Controls
4 Maintenance
2 Surveillance
Fire Protection
1
Security
Outages
1 Training Quality Programs and
5 Administrative Controls Affecting Quality TOTAL
3
1
Enclosure 2 34 Reactor Trips Reactor Trips (Unit 1)
Seven unplanned trips occurred during this evaluation perio The unplanned trips are listed below: January 28, 1985. The reactor tripped on Steam Generator (S/G)
"B" 10-10 leve The low S/G level condition was caused by the loss of the Main Feedwater Pump Turbine (FWPT)
1B which had tripped on low suction pressure. A low suction pressure did not actually exist but a pneumatic pressure transmitter had failed, giving a false low pressure signal to trip FWPT 1.
February 5, 198 The reactor tripped on a high negative flux rate signa The exact cause of the nuclear instrumentation trip signal could not be determined during post-trip investigation An independent review was performed by knowledgeable station personnel to determine the cause of the trip prior to a unit restar The investigation was inconclusive with the available post-trip dat. June 23, 1985. The unit generated a trip signal from Mode 3 when a chart recorder was plugged in apparently generating a spike in the steam generator "B" level control syste This generated an unplanned Engineered Safeguards Features (ESF)
actuation on a
"loss of both main feed pumps" which subsequently caused a trip signa. November 2, 1985. At approximately 0640, a section of braided, flexible pipe on the discharge of Instrument Air (VI) compressor B ruptured at a welded sea As a result, all VI loads not protected by check valves experienced decreased VI pressure. The low VI pressure caused the main feedwater (CF)
control valves on each unit to begin to clos This caused steam generator (S/G)
feedwater levels to decreas At 0641, Unit 1 experienced a reactor/turbine trip from 100% due to S/G 1A low-low leve Pressurizer pressure began to drop and at 0645 Safety Injection (SI)
was actuated on Unit 1 when the pressure dropped below 1845 pounds per square inch gauge (PSIG).
Unit 2 experienced a reactor/turbine trip due to S/G 2A low-low leve Pressurizer pressure did not decrease to the SI setpoin. November 19, 1985. The reactor tripped due to a turbine trip from 53% powe The turbine trip was initiated when both main feedwater pump turbines (FWPT)
trippe FWPT 1A tripped at 1541 on overspeed caused by a failed fuse in its control feedback circui An automatic turbine/reactor runback was initiated, reducing turbine load to approximately 700 Megawatts electric (MWe) and driving control rods in to reduce reactor power. It was later determined that reactor power was not reduced enoug As
Enclosure 2
the result of increasing steam generator (S/G)
levels and a lowered program level setpoint for the S/Gs (due to the reduction in reactor power), the main feedwater control valves closed. FWPT 1B tripped on high discharge pressur. December 22, 1985. The Unit 1 reactor tripped due to a turbine trip from 93%. powe The turbine trip was caused by a ground fault within a motor operated disconnect (MOD) on the lB unit main power buslin The ground fault was due to burnt contact
"fingers" on the MOD. The ground fault resulted in the opening of both generator breakers and the turbine tripped due to overspeed upon loss of load. The reactor automatically tripped on turbine trip since reactor power was greater than 48%.
7. January 5, 1986. A reactor trip occurred as a result of a steam generator (S/G)
D low-low level signa The low-low level was caused by a loss of feedwater to S/G D after the main feedwater control valve for S/G D, 1CF-17, failed closed. The valve failed closed when the automatic portion of its controller-driver card failed in the 7300 series process control system (PCS)T The attempt to manually recover from this feedwater transient was unsuccessful and a reactor trip occurred. The plant was operating at 100% at the time of the inciden Reactor Trips (Unit 2)
Nineteen unplanned trips occurred during this evaluation perio The unplanned trips are listed below:
1. October 23, 1984. The unit tripped from 100% power due to a power range negative high flux rate. This occurred when Instrument and Electrical (IAE) personnel caused group one of control rod bank B to fall into the core while trouble shooting the full length rod control system. A general trouble shooting procedure for the rod control system was written and employee training and qualification on systems was enhance. October 25, 1984. The reactor was manually tripped from 28% power per procedure when the operating main feed pump tripped on high discharge pressure resulting in a main turbine trip on loss of both main feed pumps. Water was discovered in the control oil system of the tripped main feed pump. After draining the water from the control oil system, the main feed pump was started, tested and found satisfactory. The unit was returned to servic. November 15, 198 The reactor was manually tripped from 20%
reactor power following the loss of both feedwater pumps, with one feedwater pump isolated for maintenance, the second pump tripped on low condenser vacuum, caused by a leaking valve on the isolated pump condense Corrective action consisted of repairing the valv Enclosure 2
4. November 24, 1984. Reactor tripped from 100% power when a two out of four overtemperature DeltaT (OTDeltaT) reactor trip signal was generated (DeltaT is the difference in water temperature between the reactor cold leg and hot leg).
The OTDeltaT reactor trip signal occurred when channel one OTDeltaT was in its test position and a downward spike occurred in the channel four OTDeltaT setpoint, satisfying the two out of four trip logi. December 17, 1984. Reactor tripped from 100% power on a low-low level in C Steam Generator (S/G) Signal. The low-low level in S/G C occurred when.2A Feedwater Pump (FWP)
trippe B FWP was unable to supply sufficient flow during the subsequent turbine runback, and level reached the trip setpoint in S/G A FWP tripped on a low FWP turbine condenser vacuum signal. A reduction of cooling water through the 2A FWP condenser allowed vacuum to decrease. The licensee attributed the reduction of cooling water flow to using the wrong type of amertap ball in the condenser tube cleaning syste The applicable procedure was modified to correctly identify the type of amertap balls to be used in the condenser tube cleaning syste. December 21, 1984. Reactor tripped from 100% power when operators mistakenly actuated the 2EVIB manual transfer switch for bus 2EKVB, removing it from service without having the Unit 2 alternate supply power available to supply the Channel II instrument and control load Corrective action included a re-emphasis with operators on the importance of following procedures and verificatio. May 8, 1985. The reactor was manually tripped from 10% power per procedure when the main feed pump was lost. Due to a problem with the feed pump controller the main feed pump was lost while the operators were attempting to swap the steam supply to the main feedwater pump from auxiliary steam to main stea. May 16, 1985. The reactor was manually tripped from 96% powe The licensee was feeding and bleeding the main generator hydrogen due to unacceptable purit The process of bleeding hydrogen caused an excessive loss of hydrogen; generator hydrogen pressure dropped from 75 to 1 psig. The control room operators attempted to manually runback below P8, but the loss of hydrogen was such that a manual turbine trip was require A reactor trip automatically followe. June 1, 1985. The reactor tripped from 100% power when a high doghouse level caused feedwater containment isolation on "B" and
"C" steam generators. Both main feedwater pumps tripped causing a turbine trip and a subsequent reactor tri The cause of the spurious hi doghouse level could not be determine It was assumed to be from an intermittent groun Enclosure 2
10. June 24, 1985. The reactor tripped from 100% power from a steam generator C lo-10 leve The followup evaluation revealed that the solenoid on the N2 control failed, which caused CF-28 (the Feedwater Containment Isolation for "C" Steam Generator) to fail close. July 12, 198 The reactor tripped from 100% power when both channels of the generator
"X" phase differential current protective devices actuate This actuation was initiated by a generator input/output current mismatch signal. The turbine trip initiated a reactor trip. Extensive testing and inspections were performed on the generator and busline The cause of the differential current trip could not be determined until after the turbine trip on July 29, 198 The permanent magnet generator was found extensively damaged during the investigation, which followed the tri The data collected following the trip provided evidence that this failure could not have caused the differential current relay actuation which led to the turbine trip, but had occurred after the tri. July 29, 198 The reactor tripped from 60% power when the Channel I
"X" phase differential current protective device actuate The cause of this trip was found to be cracked and misaligned aluminum flux shields on the generator current transformer. July 29, 1985. The reactor was manually tripped from Mode 3, Hot Standby, when control board position indication was lost for shutdown bank E, rod D-This action was taken as specified by Technical Specifications. The failure was attributed to a failed Digital Rod Position Indication (DRPI) Data A encoder car.
October 24, 1985. A reactor trip occurred from 100% power as a result of Steam Generator "C" low level. The inadvertent opening of the output breaker on the channel II vital instrumentation and control inverter (2EVIB) initiated the even The analog controllers for the steam generators and pressurizer were being supplied by the channel I power supply and were unaffected by the loss of power. The steam generator level program selector switch for the nuclear power contribution was in the N41-N42 (channel I, channel II) position at the time of the incident. The N42 channel had failed due to the loss of power and was causing a level error signal which was closing the feedwater control valves for steam generators "B" and "C".
The decreasing steam generator levels were not noticed by the control operators until the low level alert was received at approximately 45 percent level. Attempts to manually recover from this feedwater transient were unsuccessful and a reactor trip occurre Enclosure 2
1 October 26, 1985. The reactor tripped due to a turbine trip from 91% powe The turbine trip was initiated when an improperly aligned fuse in the generator voltage regulator sensing circuitry caused the voltage balance blocking relay (60)
to energize and swap control from "automatic" to "manual".
Because of the deadband in the regulator automatic compensation circuits and the higher voltages applied to the exciter from the recently installed permanent magnet generator, a significant step-change in output terminal voltage was seen by the generator protective relayin The loss of field relay (40B)
sensed this voltage step as a loss of excitation condition and operated to isolate and shutdown the generato The reactor trip followed the turbine trip as designe.
November 2, 1985. The reactor tripped from a loss of instrument air when the flexible discharge line of Instrument Air Compressor B failed. This incident also resulted in a Unit 1 trip and is discussed further under Unit.
December 11, 1985. The reactor tripped from Mode 3 due to source range channel N31 spiking high. At the time of the incident, Unit 2 was in the latter stages of shutting down for maintenance work. The turbine was off-line; all control rod control banks were inserted; and the control rod shutdown banks were being inserte The reactor was subcritical at zero power with approximately 10,000 counts per second (cps)
on both source ranges. The source range channel N31 spiked high going above the high level trip setpoint of 100,000 cps, causing the reactor to tri Indication from channel N31 remained errati It is believed that water in the detector canister caused the failur. January 15, 1986. The reactor tripped from 80% reactor power due to steam generator (S/G)
2A low-low level automatic tri The low-low S/G level was caused by a loss of main feedwater (CF).
Feedwater was significantly reduced initially when CF pump turbine 2A tripped due to a loss of condenser vacuum. Feedwater could not be maintained when CF pump turbine 2B began losing its condenser vacuum. The loss of vacuum on CF pump 2A was due to a malfunction of two valves in the vacuum priming system directly associated with CF pump 2A. Upon receipt of the reactor trip signal, the main turbine automatically tripped as designed with power above 48%.
1 January 23, 1986. The unit was being shutdown due to excessive reactor coolant system leakage when the reactor tripped from approximately 8% power due to the Intermediate Range High Flux Reactor Trip. The trip occurred when the Power Range Detectors reached the P-10 interlock (8% on 3 out of 4 P/R) before the intermediate range high flux reactor trip bistables had rese This was attributed to the lack of calibration of the source range 1 intermediate range detector.