IR 05000416/1986035
| ML20212K068 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 01/15/1987 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20212K059 | List: |
| References | |
| 50-416-86-35, 50-417-86-05, 50-417-86-5, NUDOCS 8701280469 | |
| Download: ML20212K068 (47) | |
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ENCLOSURE SALP BOARD REPORT U. S. NUCLEAR REGULATORY COMMISSION
REGION II
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE INSPECTION REPORT NUMBER
,- 50-416/86-35 AND 50-417/86-05 MISSISSIPPI POWER AND LIGHT COMPANY GRAND GULF UNITS 1 AND 2 MAY 1, 1985 THROUGH OCTOBER 31, 1986
12%h [5 G INTRODUCTION The Systematic Assessment of Licensee Performance (SALP) program is an integrated NRC s aff effort to collect available observations and data on a periodic basis and to evaluate licensee performance based upon this information. The SALP program 's supplemental to normal regulatory processes used 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 December 23, 1986, to review the collection of performance observations and data to assess 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 repor This report is the SALP Board's assessment of the licensee's safety performance at Grand Gulf for the period May 1,1985 through October 31, 198 SALP Board for Grand Gulf:
L. A. Reyes, Deputy Director, Division of Reactor Projects (DRP), RII (Chairman) _
J. P. Stohr, Director, Division of Radiation Safety and Safeguards (DRSS),RII V. W. Panciera, Deputy Director, Division of Reactor Safety (DRS), RII D. M. Verrelli, Chief, Projects Branch 1, DRP, RII W. R. Butler, Director, Directorate 4, BWR Division, NRR L. L. Kintner, Project Manager, Directorate 4, BWR Division, NRR R. C. Butcher, Senior Resident Inspector, Grand Gulf, DRP, RII Attendees at SALP Board Meeting:
H. C. Dance, Chief, Projects Section 18, DRP, RII W. Smith, Resident Inspector, Grand Gulf, DRP, RII L. P. Modenos, Project Engineer, Projects Section IB, DRP, RII K. D. Landis, Chief, Technical Support Staff (TSS), DRP, RII I 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 area. 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 appropriate.
i Management involvement in assuring quality Approach to the resolution of technical issues from a safety standpoint Responsiveness to NRC initiatives Enforcement history Operational and construction events (including response to, analysis of, and corrective actions for) Staffing (including management) 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, 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 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 so that minimally satisfactory performance with respect to operational safety or construction is being achieve The functional area being evaluated may have some attributes that would place the evaluation in Category 1, and other that would place it in either Category 2 or 3. The final rating for each t unctional area is a composite of the attributes tempered with the judgement of NRC management as to the 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 evaluatior. period is discerable 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 i close of the assessment period.
l Declining: Licensee performance was determined to be declining near the close of the assessment perio III. SUMMARY OF RESULTS Overall Facility Performance The Grand Gulf Nuclear Station 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 where the senior management has extensive nuclear experience. The licensee is responsive to NRC concerns, is safety oriented and has a conservative approach to technical issue The licensee appears to have put in place those organizational and staffing changes that should result in improved performanc Early indications of improvement are evident in the Training, Licensing and Emergency Preparedness functional area The licensee has initiated major organizational changes to further strengthen the organization. A major reorganization of the licensee's structure as related to the nuclear operations occurred in November 1985. These changes included the elimination of the position Senior Vice President, Nuclear and the assumption of this position's duties by the Vice President, Nuclear Operations and the Vice President, Nuclear Engineering & Support. The newly created position of Vice President, Nuclear Engineering & Support; the upgraded position of Senior Vice President, Personnel & Administration; and, the Vice President, Nuclear Operations will report directly to the President. The Vice President, Nuclear Operations has reporting to him the Director, Nuclear Licensing and Safety and a newly created position of Site Director GGN The Vice President, Nuclear Engineering & Support has reporting to him the Director, Quality Assurance; the Director, Nuclear Support; the Manager, Unit 2 Construction; and, the upgraded position of Director, Nuclear Plant Engineerin The Site Director GGNS has reporting to him the GGNS General Manager and the Manager, Unit 1 Projects (a newly created position providing overall management of outages and modifications). The position of Manager, Plant Modification and Construction was created to provide direct management oversight of activities for outages and modifications,
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and will report to the Manager, Unit No.1 Projects. The upgrade of
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the positions of Director, Nuclear Engineering and Construction to Vice President, Nuclear Engineering and Support; Manager, Nuclear Plant .
1 Engineering to Director,-Nuclear Plant Engineering; and Manager, Plant F Outages to Manager, Plant Modification and Construction strengthened the' levels'of management and reflected additional responsibilities for modifications and project engineering. The positions and functions of Manager, Nuclear Services and Manager, Nuclear Fuels were consolidated to form a new position designated as Manager, Nuclear Services and Fuels. The licensee has also contracted with American . Technical Institute to provide a degree program for employee The program L involved support from Hinds Junior College and Alcorn State University and was in place.in late 198 ~
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, On July 28, 1986, the Middle South Utilities Chairman and President, i E. Lupberger, announced the establishment of a new Middle South Oper-ating Company. System Energy Resources, Inc. (SERI). SERI is to have
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headquarters in Jackson, MS and will assume primary responsibilities previously assigned to Mississippi Power and Light (MP&L) relating to the management and operation of Grand Gulf Nuclear Statio The 4'
President and Chief Operating Officer of MP&L assumed the position of
, President, Chief Executive Officer and Director of SERI and most of
- the present MP&L employees associated with Grand Gulf transferred to SERI. On September 2, 1986, MP&L and SERI. filed applications for 1 amendments .to - the Unit 1 Operating License and to the Unit 2 Construction Permit to transfer control of Unit 1 operation and Unit 2 construction from MP&L to SERI. The amendments to the Unit 1 Operating
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License and Unit 2 Construction Permit were issued on December 20,
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1986.
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The plant ' operations area is continuously ~ improving as operating
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experience is gained and the depth of licensed personnel is increase Radiation controls has shown definite improvement in performance and no
major problem areas were evident through the first refueling outage.
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Emergency Preparedness has shown much improvement and management i attention is evident. Although not previously evaluated, the outages ,
section reflected a high degree of management involvement and was well conducted considering the large work scope accomplished. The Quality Program section has shown improvement in initiating more meaningful assessments and improved training. Licensing has been more responsive to NRC initiatives and more management involvement was evident. The training section improvement is reflected by the improved results in recent NRC operator licensing examinations.
- Unit 2 construction activities are essentially stoppe Therefore, Unit 2 was not evaluated for this assessment period.
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Ratings of the current and previous SALP are provide October 1, 1983- May 1, 1985 -
Functional Area April 30, 1985 October 31, 1986 Unit 1 Plant Operations 2 2 Radiological Controls 2 1 Maintenance 2 2 Surveillance 2 2 Fire Protection 2 2 I Emergency Preparedness 3 2 Security 1 1 Outages Not Rated 1 Licensing Activities 3 2 Training 3 2 Quality Programs and 3 2 Administrative Controls Affecting Quality Unit 2 Construction Activities Not Rated Not Rated I PERFORMANCE ANALYSIS
l Plant Operations l
l Analysis
- During this assessment period, inspections were performed by the l
resident and regional inspection staffs. The startup test program was l in progress at the start of this assessment period. MP&L reached 100%
reactor thermal power for the first time on May 12, 198 Commercial operation was declared on July 1, 198 During this assessment period, there were thirteen unplanned reactor scrams of which five were caused by equipment failure and eight were I
due to personnel error. A scram reduction program was initiated in early 1985, to minimize unplanned reactor trips, by conducting a care-ful analysis of operational events. The guidance and recommendations of the Boiling Water Reactor (BWR) Owners Group, General Electric (GE),
Institute of Nuclear Power Operations (INPO) and Nuclear Utility Management Assessment Review Committee (NUMARC) were utilized to develop a program that assesses industry wide inputs for potential impact and review of plant specific events to determine root caus _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _
The assessment of individual events generates action items with ccmple-tion dates and assigned priorities. These items are tracked and a summary is issued to management quarterly. Although the scram rate per 1000 critical hours exceeded the industry average for 1985 and the first quarter of 1986, the trend is improving and it could bring the licensee to within the industry average for all of 1986. The licensee is implementing eleven design changes during the first refueling outage dedicated to the scram reduction progra The plant had a continuous run of 105 days (from April 12, 1986 thru July 25, 1986) without a shutdown. The shutdown on July 25, 1986, was initiated by a contractor worker inadvertently bumping a breaker while
. working in an electrical switchgear room in preparation for the upcoming fall outag A number of licensee initiated shutdowns were for the purpose of correcting equipment problems which at the time did not force a shut-down. This reflected management awareness and conservative approach to safety. For example, on August 23, 1985, the control room experienced the loss of a large number of annunciator The licensee chose to shutdown the plant until the causes and corrections were known. Also, on March 19, 1986, the licensee recognized the booster compressors for the instrument air supply to the Automatic Depressurization System were cycling on and off too often, indicating excessive leakage. Again the licensee ordered a plant shutdown and repaired the leak The Plant Safety Review Committee (PSRC) has been a conservative group that has insisted on thorough and comprehensive submittals to be developed for their revie In early 1985, the PSRC recognized the poor quality of some safety evaluations submitted for approval and discussions were held with Nuclear Plant Engineering (NPE) regarding .
their submittals. There are still occasions where the PSRC rejects safety evaluacions as being inadequate but the overall rejection rate has decreased and submittal quality has greatly improve The PSRC has received management suppor The plant has had an effective cleanliness and housekeeping program, although a slight degradation was noticed just prior to the start of the first refueling outage. The positive effects of having an active clean up and painting program was evident and positive comments were heard from other visiting NRC inspectors regarding the condition of the plant. Control room decorum was adequate. The control room had a large number of personnel present during the startup test phase, but this was necessary to conduct testing. The plant staff's morale has been uniformly high during this evaluation period which reflects substantial management involvement in daily activities. There have been no turnover of licensed personnel in the operations area during this evaluation perio _ _ . _ .
Management involvement in the success of the plant in attaining a state of operational readiness was evident in the licensee's report entitled Grand Gulf Nuclear Station, Unit 1 Post Warranty Run Operational Readiness Review. The report was well written and adequately covered the aspects of operational readiness. Inspectors followup of the report's recommendations indicated satisfactory resolutions.
In late 1985, the newly created position of Site Director, GGNS was filled and reporting to him is the GGNS General Manager and the newly created position of Manager, Unit No. 1 Projects. The new position of Manager, Plant Modification & Construction was created reporting to the Manager, Unit No. 1 Project This reorganization strengthened the site staff and provided more management control over outage / equipment modification activities that could affect plant operation and safety.
Another plant staff reorganization occurred in June 1985. The Operations Superintendent assumed a new position of Plant Licensing Superintenden An Assistant to the Operations Superintendent was promoted to the Operations Superintendent position. The Manager, Plant Operations assumed the position of Manager, Plant Support and his Technical Assistant was promoted to Manager, Plant Operations. This reorganization placed operational experience in other areas of plant management and thus created a stronger overall staff.
The licensee increased the number of licensed personnel to implement a six shift rotation schedule on April 13, 1986. There are 15 Senior Reactor Operators (SR0s) and 24 Reactor Operators (R0s) in the Operations Section. The Operations Superintendent and two Operations Superintendent assistants are SR0s.
The potential for operational difficulties has existed due to discrepancies between the system operating instructions, piping and instrument. diagrams and the actual plant configuratio This area is discussed in the section on Quality Programs and Administrative Centrols Affecting Quality.
An event occurred on July 30, 1986, which revealed another problem in the licensee's controls for review of significant events / reports and vendor information letters. In this event, a control rod, while being withdrawn from notch 8 to notch 10, continued to slowly withdraw past notch 10 and eventually stopped at full out (notch 48). GE had issued Service Information Letter (SIL) No. 292 with recommended actions. The licensee had not adequately reviewed the subject SIL for applicability to GGNS. Subsequently, the licensee agreed to review approxirrately 350 older GE SILs for impac Implementation of procedural changes resulting from these reviews are scheduled to be accomplished by December 31, 1986. This is further discussed in the Quality Programs sectio y
Review and evaluations of the Licensee Event Reports (LERs), by the staff has noted that:
(1) the licensee needs to improve their record for reporting LERs within their prescribed time limit Close to thirty percent of the 10 CFR . 50.73 reports were late. About half of the late reports were overdue ty less than six days, but the others were at least two weeks overdu (2) the licensee generally identified and analyzed events properl About one in five LERs needed revisio (3) there appears to . be no significant pattern of repetition of reported events, with the exception of the reactor water cleanup (RWCU) system. The kinds of RWCU system isolations experienced by the licensee is fairly typical of the problems experienced by other owners of the BWR/6 product line. These considerations suggest that corrective actions are usually effectiv (4) The licensee should consider means to reduce the number of reactor scrams. During the reporting period the plant maintained an average availability of 69*. excluding the current refueling outage. The average reactor service factor during the reporting period was 69% excluding the current outag The plant was critical for 6709 hrs during the reporting period and experienced an average of 2.08 scrams /1000 hrs critical. This scram frequency is nearly double the current national average of 1.14 scrams /1000 hrs. critica There were ten violations identified during this assessment perio These violations did not indicate a specific programatic weakness but did reflect personnel failure to follow procedures as a major contributo Other violations reflecting inadequate procedures were the result of inadequate reviews. These violations indicate a need for increased adherence to plant procedures and increased awareness of the significance of adequate procedures. Management issued memos to all personnel emphasizing the importance of being aware of the potential consequences of individual actions and pointed out that personnel errors had resulted in emergency equipment actuations and building isolations. It was pointed out that personnel at all levels are accountable for their actions and appropriate disciplinary action would be taken as necessar In April 1986, a management committee consisting of the Plant Operations, Plant Maintenance and Plant Support Managers were designated to review each incident and provide a report to the GGNS General Manager. This action appears to have had a positive effect on the number of events involving personnel error Severity Level IV violation for failure to follow lineup procedures resulting in two valves being out of correct position (416/85-20).
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b. Severity Level IV violation for failure to follow procedures to initiate .a Limiting Condition for Operation (LCO) . report when auxiliary building door was left open (416/85-22).
c. Severity Level IV violation for failure to follow procedures- to initiate an LC0 report when manually aligning the High Pressure Core Spray suction to the condensate storage tank (416/85-28).
d. Severity Level IV violation for failure to follcw procedure to initiate an Incident Report regarding safety relief valve operability (416/85-33).
e. Severity Level IV violation for failure to follow procedures for placing RHR in shutdown cooling mode with recirculation loop suction temperature above 150'F, for maintaining feedwater pressure 100 psig greater than reactor pressure and for monitoring all available reactor vessel water level instrumentation during a startup (416/85-46).
f. Severity Level IV violation for faibre to follow procedures '
regarding correct control rod alignment prior to reducing power below the low power set point (416/86-06).
g. Severity Level IV violation for an inadequate procedure for determining flow rate and throttle valve position for standby service water system (416/86-08).
h. Severity Level IV violation for operating the control room ventilation system in the fresh air mode with the chlorine detectors inoperable and failure to procedurally define operational requirements for use of the fresh air mode of operation (416/86-11).
1. Severity Level IV violation for failure of procedure to require isolation valves to be locked open as required by system drawing and numerous procedural error, in the temporary jumper / alteration log (416/86-20).
J. Severity Level IV violation for failure to follow procedures resulting in the isolation of a standby liquid control system pressure gage and the inadvertent start of Division 2 diesel generator (416/86-21). Conclusion Category: 2 Board Recommendations Management attention should be continued to ensure procedure complianc B. Radiological Controls Analysis During this usessment period, inspections were performed by the resident and region inspection staff Inspections included confirmatory measurements using the Region II Mobile Laborator The licensee's health physics (HP) staffing level compared favorably with other utilities having a facility of similar size. An adequate number of ANSI qualified licensee HP technicians was available to support routine operation During outage operations, additional contract HP technicians were used to supplement the permanent plant HP staff. During the assessment period, the licensee had begun increasing the size of the corporate HP technical staff which would provide support functions for the onsite HP grou During the assessment period, the Plant Chemist was promoted to Chemistry / Radiation Control Superintenden Improvements in the responsiveness to NRC initiatives and aggressiveness in addressing radiation control problems have been noted since this chang The Chemistry / Radiation Control Superintendent was instrumental in obtaining the s+ ate of the art whole body friskers and whole body counters for use at the licensee's facilit During 1985, the licensee performed a self-assessment of the qualifi-cations of the onsite HP staff. As a result, critical job performance criteria were estallished and level of knowledge training was provided by onsite groups, she staff from other boiling water reactors and by the Oak Ridge Associated Universities (ORAU). One health physics individual has graduated from Senior Reactor Operator Training and has returned to health physics duties, which provides improved coordination with the Operations grou One strength noted in the health physics program was the stability of the health physics technician staf The low turnover rate has resulted in a more experienced group of individuals and has provided the time necessary to implement an effective and continuing training program for the technician The performance of the health physics staff in support of routine and outage operations was good. No substantive issues were identified in this are Health physics controls established to cover refueling floo* activities were well prepared and enforced. This was evident from the refusal by the Chemistry / Radiation Controls Superintendent to allow a subcontractor to return to work after possibly trying to bypass radiation and contamination controls. Health physics n.anagement was aggressively involved in outage planning early in outage preparation The HP group received permission from plant management to use the unfinished Unit 2 as a mock-up training area for dose intensive tasks such as in-service inspections inside the reactor vessel annulu ,
Management support and involvement in matters related to radiation protection was a program strengt During the evaluation period, licensee management authorized the purchase of an onsite thermolumi-nescent dosimeter (TLD) system in lieu of using vendor supplied and processed TLDs.
The licensee participated in the National Voluntary Laboratory Accreditation Program (NVLAP) for personnel dosimetry and recef ved NVLAP accrediation for the program during the evaluation period.
Resolution of technical issues by the health physics staff was a program strength as demonstrated by the licensee's assessment of radiation doses assigned to workers when the workers' TLDs were accidentally irradiated during shipment to the TLD processo The licensee's investigation was aggressive and thorough. The NRC was kept.
informed during the investigation.
Audits performed by the corporate health physics staff of the health physics. program were marginally adequate and were not of suf ficient scope and depth to identify problems and adverse trends. Additionally, the site internal audit organization conducted audits of the health physics program using personnel minimally experienced in the health physics area. A violation was issued for failure to control access to very high radiation areas as required by the licensee's Technical Specifications. This issue had been reviewed by the site internal audit organization, which documented several instances of locked high radiation area doors being found open. However, the audit organization did not issue a nonconformance report for this finding, and it remained uncorrected.
The licensee's radiation work permit and respiratory protection programs were found to be adequat The licensee exercised an aggressive contamination control program with the decontamination crew reporting to health physic The licensee began trecking plant contaminated areas. In May 1986, 494,500 square feet of the plant were designated to be tracked for contamination control purposes. In September 1986, 38,000 square feet of the plant were maintained as contaminated which represented 7.68 percent of the total are During 1985, the licensee's cumulative exposure was 110 man-rem as measured by TLDs which was well below the national average of 800 man-rem per unit observed at BWR facilities. Through October 31, 1986, the cumulative exposure as measured by TLDs was 380 man-re During 1985, the licensee made 49 solid radioactive waste shipments totalling 21,249 cubic feet (ft3 ) and containing 259 curies of activity. This value is well below the national average of 28,800 ft 3 per reactor of waste shipped by other BWR facilitie Through September 1986, the licensee had made 46 solid radioactive waste shipments totalling 10,657 ft3 and containing 1,170 curies of activit .
_ _ In the area of radiological confirmatory measurements, the licensee demonstrated good overall performance. In the NRC's spiked sample program the licensee showed disagreement for Iron-55 in 1985 and for tritium in 1986. The licensee evaluations of these findings was timely and comprehensive. During measurements of split . samples with the NRC Region II mobile laboratory, all measurements were in agreemen A single inspection in the area of plant chemistry was made during the evaluation period three months after the plant became operational in 1985. Although a high level of chemistry control was being maintained, significant weaknesses in the qualification and training of the chemistry staff were identified. The position of Plant Chemist had not been filled. A major revision of plant procedures was still underwa The licensee was following INP0 guidelines for chemistry control instead of the BWR Owner's Group guidelines. Efforts to provide greater training were being made while the chemistry staff was also supporting plant operatio During subsequent inspections of other functional areas, it was noted that improvements have been made in all of these areas during the last year; e.g., a plant chemist has been hired, new members have been added to the Chemistry staff, the licensee has endorsed the BWR Owners' Group guidelines, most of the chemistry technicians have completed a 17-week training course, and shift capabilities have been upgraded by on-the-job-trainin The licensee submitted the required effluent and environmental reports
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during the evaluation perio The total quantity of radioactivity in the licensee's gaseous releasts was less than the average annual releases reported by four Region II plants of similar size and type for
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1985, as well as the liquid releases for 1985. Both liquid and gaseous effluents were within regulatory limits for quantities of radioactive material released and for dose to the maximally exposed individual but the plant has had a relatively short operating histor For 1985 releases, the maximum calculated total body dose to member of the public was .07 mrem from liquid releases and .31 mrad from gaseous effluents. These calculated doses represented 5 percent of the 4C CFR 190 whole body limit of 25 mrem / year. There were no unplanned gaseous or liquid releases above limits required to be reported to the NRC during the evaluation period. No adverse impact due to the plants'
operation was detected by the radiological environmental monitoring progra Three violations were identified:
. Severity Level IV violation for failure to adhere to 10 CFR 20 and
. procedural requirements during work on the transverse incore probes (416/85-24).
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13 Severity Level IV violation for failure to prevent unauthorized entry into areas with dose rates in excess of 1,000 millirem per hour (416/86-14). Severity Level V violation for having hydro-lazing performed by licensee personnel who had not completed decontamination training (416/86-03). Conclusions Category: 1- Board Recommendations None C. Maintenance Analysis During this assessment ,ae lod, inspections were conducted by the resident and regional inspection staffs. Two major outages occurred during this SALP period and events relating to the outages are discussed in the Outage sectio On November 6, 1985, while conducting post maintenance testing of the Division 1 diesel generator a diesel overspeed occurred. It was later determined that the overspeed occurred due to the inadequate refill and venting of the diesel's Woodward governor. The diesel generator was completely disassembled, inspected and reassembled. NRC personnel involved in the review of the licensee's actions regarding the teardown, inspection, reassembly and failure analysis had very favorable comments as to the thoroughness and professionalism demonstrated during this even The licensee's approach to the resolution of the technical issues was considered good and management's involvement was evident by the effort devoted to this even 'liolation (d) addresses some of the problems identified during this even NRC resident inspectors have accompanied maintenance personnci on special inspections i.e., IEN 86-03, Potential Deficiencies in Environmental Qualification of Limitorque Motor Operated Valve Wiring, and Raychen seal problems. Management's attention was evident from the preparations and care in accomplishing the inspection and any required rework. Maintenance was accomplished in a thorough and professional manner. The attitude of management and licensee personnel was to accomplish the job correctly the first tim . .-_ . _ . . .
The licensee participates in the Nuclear Plant Reliability Data System (NPRDS). The plant Machinery History Log is the only on-site source for past maintenance problem areas. Retrieval of maintenance history records is not readily available.
Weaknesses were identified in the measuring and test equipment (M&TE)
program. Procedures used during the calibration of instruments did not address environmental conditions. Frequently, the quality oversight function provided by QA audits was neither _ timely nor thorough.
Nonconservatism was exhibited by licensee management in that the M&TE program did not provide for prompt evaluations when M&TE was found out of calibration.
There were seven violations identified. Violations (b), (c), (d), (e),
and (f) involved personnel failure to follow procedures. The three examples of violation (d) were associated with the damage to the Division 1 diesel generator that occurred during the maintenance outage of October 13, 1985. Violations (a), (b), and (e) resulted in reactor scrams. Violation (g) resulted in the inadvertent initiation of an Engineered Safety Features system. Severity Level IV violation for inadequate procedure resulting in a reactor scram and failure to perform a safety evaluation on a temporary change to the facility (416/85-20). Severity Level IV violation for failure to follow procedures to add retest instructions resulting in a reactor scram (416/85-22). Severity Level IV violation for failure to follow procedure to promptly evaluate Measuring and Test Equipment found out of tolerance (416/85-27). Severity Level IV violation for failure to follow procedures in that retest instructions were not approved by the responsible maintenance engineer, retest instructions were specified by unauthorized personnel and retest instructions failed to specify required operations (416/85-45). Severity Level IV violation for failure to have written instructions for reset of safety relief valve trip units resulting in a reactor scram (416/86-11). Severity Level V violation for failure to follow procedures where inspectors were the same people that had accomplished the work being inspected (416/85-38). Severity Level V violation for an electricians handling of a feeder breaker which resulted in an Engineered Safety Feature actuation (416/85-45).
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15 Conclusion Category: 2 Board Recommendations The Board notes that.there is a need for more management attention in ensuring compliance with procedures and additional management involvement in assuring quality during implementation of
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corrective action D. Surveillance Analysis During this assessment period, inspections were performed by the resident and regional inspection staff The regional staff's review of the surveillance testing and calibration control program revealed-that the surveillance test procedures were clearly written, and generally the surveillance test schedules were adhered to; surveillance data packages were complete and easily retrievable; for the most part they were properly reviewed; and test acceptance criteria were clearly defined for the surveillance activity being performed. Licensee staff involved in the preparation of surveillance test schedules were knowledgeable in the area of policies and requirements of the surveillance test progra The licensee's technical resolution of problems and response to NRC concerns has been very positive. On June 19, 1986, a potentially generic deficiency was identified that could affect the operability of the High Pressure Core Spray (HPCS) diesel generator. Following a surveillance run (or any other operation), the normal shutdown mode includes a cooldown period of ten minutes operation at an idling speed of approximately 450 rpm. If an emergency signal was received during this period, the diesel generator would accelerate to rated speed but would not build up voltage. This deficiency is a design proble introduced by the manufacturer, Morrision-Knudso The System Operation Instruction and the Operability Verification procedures were revised to require the operator to manually reset the voltage shutdown circuit during the HPCS diesel generator shutdow The 18 month functional test and the monthly functional test were also changed. A design change is being pursued as a final fix resolution to the proble Surveillance violations were issued as identified belo However, violations for missed surveillances identified by the licensee were not issued. Some of these events, which are noted below, indicate a need
) for more management involvement in the day-to-day activities. On J August 13, 1985, during a quarterly battery cell check surveillance, a i cell in the Division 1 battery bank was recorded as having a specific
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gravity of 1.196. It was not recognized nor evaluated until August 16,-
1985, that this value, when compared to the average of all the cells, made the Division 1 battery bank technically inoperabl On September 11,1985 the licensee determined that four motor operated valves - and two drain line check valves of the Main Steam Isolation Valve Leakage Control System had not been tested within their required frequency. Licensee evaluation determined there was no formal program to ensure new- surveillances were included in the licensee's
Surveillance Program Tracking System (SPTS). On September 20, 1985, a smoke detector in the control building heating, ventilation and cooling system was found to have been inoperable since June 20, 1985, due to an error in the computer data base entry. On December 22, 1985,- a review of a quarterly surveillance conducted on September 14, 1985, revealed that the isolation time of a valve was greater than TS limits. A review of a similar surveillance conducted on December 11, 1985, revealed that TS limit had also been exceeded and in both cases the surveillance criteria had been erroneously marked acceptabl On April 17, 1986, an error was discovered in a surveillance procedure that failed to require measurement of isolation time for a containment power operated isolation valve. The requirement to measure valve isolation time was inadvertently deleted from the procedure during the last revision. On June 19, 1986, an instrument channel which provides an Automatic Depressurization System actuation permissive signal was not tested due to the wrong Division surveillance data package being attached to the surveillance task car Although there has been an improvement in meeting licensee commitments, there are examples of continuous problems such as Deviations (e), (f)
and (g) that reflect a lack of management involvement in meeting NRC commitments. A significant equipment problem was discovered during the performance of flow balancing testing of the new Standby Service Water (SSW) pump installed during the October 13, 1985 outage. The licensee failed to periodically inspect and test the Engineered Safety Features (ESF) switchgear room coolers as committed.in the FSAR. In response to deviation (f), the licensee committed to test the ESF switchgear room coolers on a quarterly basis until a definite time period could be established. Subsequently, during the refueling outage of September 6, 1986, it was found that plugging of the ESF switchgear room coolers and other room and equipment coolers had occurred and the licensee had not initiated quarterly testing of the room coolers as committe Deviation (g) was then issue There were four violations and three deviations identifie Severity Level IV violation for failure to conduct local leak rate tests on containment and drywell airlocks (416/85-33). Severity Level IV violation for failure to follow procedures in making changes in local leak rate test instructions (416/85-39).
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17 Severity Level IV violation for failure to follow procedures to close valves by normal means for local leak rate test (416/85-45). Severity Level IV violation for failure to follow procedures resulting in the initiation of an Emergency Core Cooling System and the improper legging of the restoration of electrical leads (416/86-04). Deviation for failure to issue a surveillance procedure when committed (416/85-28). Deviation for failure to periodically test Engineered Safety Features switchgear room coolers as stated in the Final Safety Analysis Report (416/85-45). Deviation for failure to test Engineered Safety Features switchgear room coolers quarterly as committed (416/86-26).
2. Conclusion Category: 2 3. Board Recommendations None E. Fire Protection Analysis During this assessment period, inspections were conducted by the regional and resident inspection staff The inspections included evaluations of the implementation of 10 CFR Appendix R safe shutdown and related fire protection feature The inspection of the implementation of the Appendix R post-fire safe shutdown and related fire protection features was conducted at the beginning of this assessment perio The operating license for Grand Gulf states that the plant is required to maintain the fire protection program to meet the " intent" of Appendix In 1984, following the issuance of a number of hRC Appendix R clarification documents and the NRC Appendix R licensee workshops, MP&L implemented an Appendix R re-analysis program to determine which plant fire areas met the requirements of Appendix The re-analysis identified a number of plant areas which did not meet these require-ments. Modifications were proposed for the more serious discrepancies and justifications were provided for the remaining items. These justifications were sent to the NRC/NRR for review and they received approval. All modifications are scheduled to be completed by the second quarter of 198 The failure to meet the Appendix R
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requirements is identified as an unresolved item pending resolution in
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accordance with Generic Letter 86-1 The Re;; ion II Appendix R inspection was based on MP&L's re-analysi This analysis indicated an understanding of the NRC requirements; however, plant management displayed limited knowledge of the shutdown analysis and had to request answers to question concerning the post-fire shutdown analysis from the contract design organization and
, reactor manufacturer. Apparently, the shutdown analysis was not l available either on site or at the MP&L corporate office. The safe l shutdown approach in the event of a fire at Grand Gulf utilizes the .
t automatic depressurization system and low pressure coolant injection )
without high pressure water level recover This approach is similar l to that used in several BWRs approved for use in Grand Gulf Unit 1 by NRC/NRR on August 27, 198 Region II will perform another Appendix R inspection to veri fy compliance to the NRC requirements when all the modifications have been completed and the license amended, in accordance with Generic Letter !
86-0 For the routine fire protection program, the licensee has issued procedures for the administrative control of fire hazards within the plant, surveillance and maintenance of the fire protection systems and equipment, and organization and training of a plant fire brigad These procedures were reviewed and found to meet the NRC requirements and guideline The staff inspections reviewed the licensee's implementation of the fire protection and administrative control General housekeeping and control of combustible and flammable materials were satisfactor The fire protection extinguishing systems, detection systems and fire barriers and fire barrier penetrations were found to be in service except for a number of fire protection system deficiencies such as open fire barrier penetrations and lack of Appendix R type cable raceway fire barriers. A roving fire watch was provided for these areas to meet the action statement of the Technical Specification However, the fire watch program was found to be deficient in that all areas were not being inspected hourly as required. This was identified as violation (a) belo Surveillance inspection and tests and maintenance of the fire protection systems and features were satisfactory except for one of the exterior fire hydrants noted in violation (b) belo Organization and staffing of the plant fire brigade appear to meet the NRC guideline Fire brigade training and drills met the frequency specified by the plant procedure The annual fire protection / prevention audit and 24 month QA fire protection program audit by offsite organizations and the triennial audit by an outside fire protection organization required by the Technical Specifications were reviewed. These audits were conducted
. . .
within the specified frequency and appear to cover all the essential elements of the fire protection program. The licensee. had implemented the corrective action on discrepancies identified by the audi The licensee identified, analyzed, and reported fire prevention events and discrepancies as required by license condition or Technical Speci-fications. These reports were reviewed and fo:,nd to be satisfactory except for the one inoperable fire hydrant identified on December 26, 1985, which was not reporte In general, the management involvement and control in assuring quality I in the fire protection program is evident due to the well developed, issued and implemented protection administrative procedure The licensee's approach to resolution of technical fire protection issues indicates an apparent understanding of issues, and is generally sound and timely. The responsiveness to NRC initiatives are generally timely and thorough. Fire protection related violations are rare. Moreover, when violations do occur, effective corrective action is promptly taken. Fire protection related events and discrepancies as identified by licensee are properly analyzed and promptly reported, and effective corrective actions are take Staffing for the fire protection program is adequate to accomplish the goals within normal work hours. Fire protection staff is identified and authorities and responsibilities are clearly define Personnel appear well qualified for their assigred duties.
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Two violations were identified:
l Severity Level IV violation involving the failure to provide an hourly fire watch program for plant areas having inoperative fire rated asseni'.ies separating safety related areas or separating portions of redundant shutdown systems or components (416/86-24). Severity Level V violation involving the failure to report an inoperative fire hydrant required to be operable by the Technical
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Specifications (416/86-24). Conclusion t
Category: 2 Board Recommendations None
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F. Emergency Preparedness Analysis During the assessment period, inspections were performed by the .
resident and regional staff The inspections included two routine emergency planning inspections, one full participation emergency exercise, and one limited emergency exercise. The limited emergency exercise was conducted by the licensee to demonstrate the adequacy of actions taken to correct weaknesses observed in the radiological assessment area of the full participation exercis The routine inspections disclosed that the licensee had an adequate emergency preparedness program for emergency identification and classification, protective actions decision making, notifications and communications, making changes to the emergency preparedness program and licensee audit The full scale emergency exercise conducted in December 1985, showed that the licensee had an adequate emergency preparedness organization and staffing at both the plant and corporate leve The exercise demonstrated weaknesses i t other key areas, however. The licensee failed to provide timely followup notification to the State and county offices resulting in delayed transmission of radiological data. This led to confusion on the part of the States as to the current status of the plant and reduced the States' abilities to independently evaluate the licensee's protective action recommendations. The licensee failed to determine the habitability of the Emergency Operations Facility (EOF) as required by procedure, in that constant airborne monitoring was not performed. This monitoring is particularly important at this licensee's EOF since it is less than one mile from the plant. The dose assassment group failed to make timely and consistent dose assessment projections. This lead to the reporting of inconsistent results to the States and confusion on the part of the States as to the safety of the public near the plant. The offsite monitoring / survey teams failed to demonstrate proficiency in collecting air samples and HP practice The ability to clasi fy the emergency, to make initial offsite notifications, and to make protective action recommendations was demonstrate As a result of the exercise weaknesses noted, the licensee initiated comprehensive corrective actions. A high level of corporate mana" .nt became actively and directly involved in improving emergency prepared-ness activitie Significant resources were brought to bear on the problems. The licensee changed the method of staffing the emergency response organization to assign plant staff, rather than corporate staff, to key emergency response positions. Additional pcsitions were added to the EOF radiological assessment staff to provide better direction of assessments and better interaction with States. Compre-hensive retraining and several practice drills were held to provide
training for emergency response staff. A drill was conducted approxi-mately five months after the full scale exercise to demonstrate the effectiveness of the change This drill, which concentrated on radiological assessment, demonstrated that the licensee had taken adequate corrective action Subsequent to the SALP, the licensee demonstrated these changes as integrated into their emergency response actions as part of the December 1986 exercise. The licensee has actively pursued resolution of this and other FEMA exercise findings by making improvements in equipment and procedures and by participating in remedial exercises with the Stat One violation was identified:
Severity Level IV violation for failure to provide training for the agreement fire department in accordance with the requirements of 10 CFR 50.47(b)(15) (416/85-15). Conclusion Category: 2 Trend: Improving Board Recommendations None G. Security Analysis During this assessment period, inspections were conducted by resident and regional inspection staff The licensee continues to exhibit strong management support at both the corporate and site level The site security organization remains professional and aggressive in meeting regulatory requirements. The contract security force is well supervised, appropriately trained and equipped, and exhibits good job knowledge and performanc One special inspection was conducted in response to the licensee's investigation of drug abuse by its employees and contractor personne The licensee effort was extensive and timely, NRC was kept well informed, and corrective action was considered thoroug The licensee maintains an independent compliance section which monitors the day-to-day activities of the security force; this assures compliance on a routine basis. The security procedures have been well researched, are easily understood, and security force members are well versed on procedure requirement s a
4 The licensee continues its posture of eager responsiveness to NRC initiatives as is evident from the improvements made in the control of vehicles, issuance of badges and self-instituted measures as a result-of various NRC Circulars and Notice ~
Although the-licensee has completed some interim measures to upgrade the temporary barrier _ separating the operational side (Unit-1) from the construction side (Unit 2), it has yet to finalize its intentions to
' install a more permanent barrie From a licensing point of view, the two changes made this reporting period reflect that the licensee has met all the applicable require-ments relative to 10 CFR 50.54(p) changes to the Security and Contingency Plans. The licensee communicates its intentions well and has been responsive > to NRC ' comment Plan changes are generally complete, accurate and consistent with the regulatory provision Reports submitted under 10 CFR 73.71 are timely, accurate and reflective of a well managed security organizatio No violations were identifie . Conclusion Category: 1 Board Recommendations None Outages Analysis During this assessment period, inspections were performed by the resident and regional inspection staff Two major outages occurred during this SALP period. An equipment / modification outage occurred from October 13, 1985 through December 7, 1985 and the first refueling outage started September 6, 1986 and ended November 29, 198 The major tasks of the equipment modification outage starting October 13, 1985, were local leak rate tests, containment integreted leak rate tests, rework of feed water check valves, modification of the Division 2 StanJby Service Water system, modification of the horizontal fuel transfer mechanism, removal of existing fuel racks to install high density fuel racks and addition of part of the provisions for redundant scram discharge volume level switches. The outage was delayed from the original scheduled restart date of November 25, 1985, due to equipment problems. Startup was initiated on December 7,1985. The plant was shutdown again on December 19, 1985, due to main condenser tube
leakage. The leaking tubes were plugged and modifications made to prevent further steam impingemen Plant restart commenced on December 22, 1985.
On December 5, 1985, the licensee determined that several environ-mentally qualified (10 CFR 50.49) valves had limit switches that were unqualified. On December 7, 1985, it was determined that 13 limit switches were affected and these limit switches only provided indication or inputs to computer points and their failure could not affect the operation of their associated valves. .The plant was in cold shutdown at the time so the licensee replaced all unqualified limit switches with qualified limit switches prior to startup.
The first refueling outage started on September 6,1986. The major tasks were the rework of the cooling tower for increased efficiency, the replacement of 264 fuel bundles in the reactor core, the modifi-cation of the A SSW system for increased capacity, the disassembly, inspection and reassembly of the Division 2 diesel generator and the modifications associated with license condition The licensee is incorporating over 120 Design Change Packages during this outage. An extension to the original scheduled completion date of November 8, 1986, became necessary when the outage scope increased due to the discovery of problems with the high pressure turbine blades during the disassembly and inspection of the turbine.
As discussed in the QA Section, just prior to the planned refueling outage, on August 27, 1986, the licensee discovered the wrong flow coefficient had been used to calculate the SSW flow to the ESF switch-gear room coolers. During the refueling outage the SSW system piping to some ESF coolers were found to be plugged to where design flows could not be achieved. The SSW piping to some ESF equipment room coolers carries Plant Service Water (PSW) during normal operation and the poor quality of PSW is one source of the plugging of the ESF piping and heat exchanger Another source of the plugging was microbio-logically induced corrosion (MIC) which created increased pipe surface roughness and increased resistance to flo Flanges and valves have been added during the outage to permit hydrolazing of the affected piping for future cleanup as found necessary. The coolers cannot be hydrolazed and must be replaced if flushing or mechanical cleaning is inadequat Corrective actions including measurements of flows to assure they meet minimum required flows were completed prior to restart of the plan Management was heavily involved in the planning and scheduling of the refueling outages and in the day to day activities during the outage Management attention is evident from the assignment of key personnel to areas where unexpected delays and problems have occurred and to the expansion of the work scope where safety issues are involved. The high pressure turbine work and the SSW system modifications are two example !
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Licensee management demonstrated a high degree of involvement in the resolution of technical issues that arose during refuelin For example, significant foreign material problems occurred on September 28, -1986, when the refueling team noticed the presence of loose wire, wire clamps, and vibration sensors in the core area where they removed fuel assemblies that had been instrumented with vibration sensors during the past fuel cycle. It was determined that pulling the three assemblies out of the core past the upper core plate edges stripped varied amounts of this instrumentation. Surrounding fuel assemblies and control rods were removed and the reactor vessel lower plenum was searched to find this material. All of the sensors were recovered, but 19 to 37 of the wire clamps and possibly some short i pieces of wire remained unaccounted for. General Electric conducted a l loose parts analysis and determined that there was no safety concern associated with the remaining lost parts, and as such the presence of these loose parts in the core during operation does not constitute an unreviewed safety questio Plant management has been actively involved in plant activities on a i daily basis and was involved in ensuring operational decisions were made at the appropriate leve Plant management has been very responsive to NRC concerns and their actions have reflected a careful, conservative approach to safety and operational issues. Management's conservative approach has been emphasized during outage briefings by asking everyone to contribute to meeting the work schedule but not at the expense of safety or quality. Management emphasized the importance of people taking the time to do the job right the first tim The refueling floor activities were conducted in a controlled manne The actual fuel handling was accomplished by GE personnel with a MP&L Shift Superintendent (SRO) in charg The SR0 remained on the refueling bridge during actual core alterations conducted from the refueling bridge. The health physics controls were well prepared and enforced. This was evident from the refusal of the Chemistry / Radiation Controls Superintendent to allow a subcontractor to go back to work after possibly trying to bypass radiation control Subsequent to this SALP evaluation period, the licensee experienced an excessive number of inadvertent ESF actuations indicating a deficiency in Management Controls. The licensee took several initiatives ( Reducing the number of design changes being processed at one time and requiring another independent review of change packages for potential impact) which significantly reduced the number of inadvertent actuations. The licensee has been requested in Report 416/86-37 to address their plans to enhance management controls to improve the effectiveness of their progra One violation was identifie _ _ _ _ - _ _ _
Severity Level IV violation for two examples of inadequate procedures resulting in the inadvertent actuation of Engineered Safety Features and failure to follow procedures in modifying the refueling platform (416/86-32). Conclusions Category: 1 Board Recommendations None
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I. Licensing Activities Analysis The licensee's management showed consistent evidence of prior planning and assignment of priorities for the Fall 1985 outage and the first refueling outage which began on September 6, 1986. Several months l before the outages, the Vice President, Nuclear Operations and the Vice k
President Nuclear Engineering and Support met with the NRC staff and presented plans and schedules for the outages, including licensing activities needed to support the outages. Critical path networks were made to schedule and control the work activities. Changes to license conditions and Technical . Specifications were usually requested sufficiently in advance of their need that NRC staff could utilize normal resourcos to review the applications. For example, in the Fall 1985 outage, a temporary change in secondary containment boundary to I include the railroad bay area for moving high density spent fuel racks ( into the auxiliary building was submitted July 3,1985, and needed for use in October 1985. Another example of good planning for the Fall outage was the change to License Condition 2.C.(20) and Technical Specifications to allow modifications to be made to standby service water Loop "B" which was requested by application dated August 23, 1985 and needed for use October 15, 198 For the first refueling outage several inspections and modifications to equipment were required to be made by license conditions. The licensee's management identified those conditions for which deferral would be sought sufficiently before the outage that the staff's evaluation of the justification for deferral could be considered in the licensee's final requests for deferral. For example in the July 29 and 30, 1985 meeting, MP&L management identified nine items for which it was planned to request schedule extension Three of these items were included in requests for extensions and the others will be completed on schedul For those items in which schedule extensions were requested, the licensee adequately supported their requests in the applications and meeting For example, MP&L's top nuclear management participated in meetings to discuss schedule extensions for the low pressure turbine disc inspections and for the TDI emergency diesel generator DR/QR inspection _ _ _ _ _ _ _ _ _ _ . _ _ - _ _ .
Region II and NRR management met with MP&L management on February 20, 1986, to hear and discuss licensee's plans to improve performance in the functional areas of licensing and quality assurance. With respect to licensing, the licensee described their actions and plans to improve l commitment closure, make definite assignments of responsibility for !
completion of licensing activities, and establish a review function within licensing to enhance qualit During this rating period, several emergency circumstances arose for which the licensee considered requesting relief from requirements in the license or Technical Specifications. In three of these instances, discussions between the NRR staff, Region II staff and the licensee resulted in clarification of the requirements which eliminated the need for emergency licensing actions. However, ir two instances, emergency actions were taken by the staff. A temporary change to the Technical Specifications was issued in October 1986 to allow work activities requiring a breach of secondary containment to continue while control rods were removed from defueled control cells. In its initial contacts with NRC staff on this request, it was evident that the MP&L licensing staff was not adequately prepared and plant staff was not adequately involve However, the need for the emergency change to the TS was justifie During a surveillance test in March 1985, the licensee identified a potential problem with the standby gas treatment system (SGTS) heaters meeting TS requirements. The original heaters were 50 kilowatts (kW) but environmentally qualified replacement heaters were installed in March 1985, that were rated at 48kW. Calculations were made that showed that the replacement heaters were adequate. Although the potential problem was known for some time the licensee failed to submit a TS change to match the TS requirements for installed heater characteristics and on February 15, 1986, the licensee requested to continue operation when the surveillance test of the heater showed that the minimum required heat dissipation was not achieved (44.9 was measured and 45.0 was required). Region II allowed the exceptio Generally reviews were timely, thorough and technically sound; examples include the Exxon reload application and the request for a schedule extension for completion of the DR/QR inspection for the Division II die >el generato However, some reviews were not timely, thorough or technically sound. In the review of high density spent fuel assembly storage racks, although the application for the license amendment was made in May 1985, the thermal and hydraulic aspects and occupational dose aspects were not adequately resolved until August 198 In the review of the proposed Technical Specifications for the scram discharge volume vent and drain valves, management did not get involved until late in the review to resolve an outstanding issue regarding system test The licensee's understanding of technical issues was generally apparent. Proposed changes to Technical Specifications and resolution of technical problems were usually sound and adequately justified. In some instances, such as the main steam turbine inspection program and
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the fuel reload application, the licensee demonstrated a clear understanding of the safety issues. In other instances, the licensee chose to meet minimum requirements, rather than to select viable and more conservative solutions. For example, in the resolution of the control room leak rate issue, the licensee chose to run tests to demonstrate the adequacy of the meteorological model rather than to decrease leakage into the control room thus providing more conservatis In the resolution of qualification of ADS accumulators, the licensee-initially proposed a manual connection of a backup air supply for the ADS accumulators in an area having an unacceptably high calculated post accider,t dose rat However, for the majority of the proposed licensing actions, understanding of issues was good and adequate conservatism was exhibited and technical approaches to resolutions were soun A licensing action that indicated a lack of management attention was the updating program of the FSAR. 10 CFR 50.71(e), periodic updating i
of Final Safety Analysis Reports, and Generic Letter 81-06, provide the
regulations and guidance for updating the FSAR. The GGNS updated FSAR contained the following problems:
l l (1) Contrary to the guidance given in the Generic Letter 81-06, the level of detail of the original FSAR was not always maintained in the updated FSA (2) Although 10 CFR 50.71(e) allows the UFSAR to include all changes
made based on safety evaluations performed by the licensee, apparently many changes did not have a safety evaluation performed as required by 10 CFR 50.59.
l (3) Changes in the UFSAR to reflect the as built configuration of the plant were not submitted to, or approved by the NRC nor were 10 CFR 50.59 safe evaluations performed.
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The licensee failed to maintain the FSAR as required by regulations and also failed to take prompt corrective action when made awar? of the l
NRC's safety concerns. The lack of adequate safety evaluations for changes in the facility as described in the FSAR was of particular
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concern to the NRC. This resulted in violation (a), belo The licensee has generally provided timely responses to NRC initiatives. In the majority of the licensing actions, telephone calls i discussing the technical issues resulted in appropriate revisions to the submittals. Most of the license conditions requiring completion by the first refueling outage have been met. The licensee had a few long standing issue For example, in a letter dated May 14, 1985, l
regarding containment and drywell penetrations the licensee committed j to prepare an administrative 1y controlled list of drywell and l containment penetration barriers which includes isolation valves,
- appurtenances and other potential release paths associated with each l
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drywell and containment penetration. This list was not prepared and issued for use until February 19, 198 Two violations in the licensing functional area were identifie (a) Severity Level IV violation for changing the Final Safety Analysis Report without written safety evaluations (416/86-02).
(b) Severity Level V violation for failure to update the peak cladding temperature in the Final Safety Analysis Report. (416/86-01).
2. Conclusion Category: 2 Trend: Improving 3. Board Recommendations None J. Training Analysis l
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During this assessment period, inspections were conducted by the regional and resident inspection staffs. The effectiveness of the licensed operator and non-licensed staff training programs was evaluated by inspection of training methodology, materials and administrative controls; by observation of selected lectures and review of instructor qualifications; and, by evaluatior, of training as related to plant and industry events and routine plant operations and maintenanc Inspections of the training programs for licensed operators, senior licensed operators, shift technical advisors (STAS),
nonlicensed operators, maintenance personnel, general employees, plant engineers and health physics technicians were conducted.
l During the May 1986 training asses:. ment, several areas were noted for l
improvement. These included the need for administrative controls for identification and implementation of immediate training needs in the operations department such as training on procedure revisions, abnormal i operating configurations, design changes, etc., and the need for (
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improved procedural requirements for attendance and remedial training in the licensed operator requalification progra In addition, l development of learning objectives and evaluations of STAS during
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simulator training was recommended. Inspectors also noted during the inspection that the licensee had initiated improvements in licensed operator lesson plans, surveillance program training for maintenance technicians, enhancements of question banks for maintenance training courses and incorporation of generic and facility events in maintenance training courses, l
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Areas of noteworthy performance included the use of two simulator instructors during licensed operator simulator requalification training, attendance of STAS with their respective shifts in licensed operator simulator requalification, significant changes in General Employee Training (GET) materials and emphasis on senior personnel GET attendance, a high -level of qualifications among the engineering personnel and implementation of an organized and expeditious training section document review syste The staff noted in the maintenance training area that extensive efforts had been made by the maintenance training staff in the procurement and construction of various training aids and training laboratory equipmen The maintenance training staff exhibited positive attitudes toward development of maintenance training course During the May 1986 training assessment, a review nf maintenance training through the selection of three plant events involving maintenance personnel errors was conducted. Maintenance personnel were interviewed concerning the technical aspects of the events, previous and post-event training, the technician's perception of the maintenance training program and specific event feedback items included in the trainin No deficiencies were noted. Good maintenance training was observed during the NRC inspection of motor operated valves in response to IE Bulletin 86-03, Potential Deficiencies in the Environmental Qualification of Limitorque Motor Operated Valve Wiring. The maintenance personnel were well trained in what to inspect and had detailed instructions for determining the acceptability of the wirin The training group is a well qualified staf The Training Superintendent, although not presently licensed at GGNS was previously licensed as an SR0 for 12 years. The Operations Training Supervisor and five training instructors have SR0 license One training instructor is SR0 certified by having passed the NRC administered SR0 tes Two training instructors are presently in SRO class and two other training instructors have been previously license Management has also taken actions to strengthen the plant staff by sending five key personnel through Senior Reactor Operator trainin This involved the loss of these individuals to plant operation for approximately one yea The present Manager, Plant Operations, Manager, Plant Support; the Technical Superintendent; the Technical Assistant to the Manager, Plant Support; and the Reactor Engineering Supervisor, all successfully passed the SRO examinatian and became licensed SR0s. The licensee's goal is to send other key personnel through the same training which would further enhance the plant staff's qualification During the current SALP assessment period,15 senior reactor operator examinations, including two instructor certifications, were
administered. Fourteen of the 15 candidates passed these examinations.
Seventeen reactor operator examinations were administered. Ten of the 17 candidates passed these examinations. Thus, in a total of 32 license examinations administered, 24 resulted in a passing grade.
This passing rate (75 percent) is consistent with the industry average.
The latest Operator and Senior Operator examinations were conducted during the week of September 8,1986 and 100's of the SR0s (6 of 6) and 3 of 4 R0s were successful. The previous examination given during the weeks of-December 17, 1985 and January 10, 1986, resulted in 100% of the SR0s (4 of 4) and 100% of the R0s (5 of 5) successfully passing.
In response to NRC comments on training of QA personnel, the QA group sent one person through SRO training and two people through STA training. Although these people were not licensed / certified they are much more knowledgeable of the plant and its operation. QA currently has one person in STA training. This increased training should enhance the audit capabilities of QA and the ability to witness / review operational activities. Also, supervisors within the QA organization are being rotated temporarily for _ cross training purposes. Also NPE has one qualified SR0 and one certified STA. Presently, three NPE personnel are enrolled in STA training and a large number have attended selected BWR system courses to increase their knowledge of the plant.
One area of generic weakness was noted during administration of the examinations. The use of the Emergency Procedures (EPs) was minimally acceptable when multiple procedure use was required. Subsequent to the SALP period, the licensee implemented a new system of flow-charted symptom based EPs.
A review of the 1985 annual reactor and senior reactor operator requalification examinations indicated that the examinations were of sufficient difficulty to challenge the licensed operators and to provide an adequate evaluation of operator knowledg The average examination results for the 19 senior reactor operators administered the 1985 annual requalification examination was 86.2 percen The average for the 18 reactor operators was 83.6 percent.
In general, training shcwed continued improvement with an overall commitment of sufficient utility resources and management support to provide an effective training organization. The available training facilities enhanced the learning process and the delivery of training.
Comprehensive quality assurance audits of plant training programs were conducted periodically. Audit findings were promptly corrected by the training organization.
The licensee was aggressively pursuing INPO accreditation of major plant training program The licensed operator, licensed senior operator and non-licensed operator training programs received accreditation on April 30, 1986. The final self-evaluation reports for the maintenance (I&C, Electrical, and Mechanical), STA, chemistry
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technician, HP technician, technical staff and management training programs have been submitte The licensee has started a training program to enhance the qualifica-tions of licensing personnel. This program includes systems training and long-term rotation of licensing staff with the plant staff and other groups. Use of staff with operations experience for licensing j activities has resulted in improved understanding in several changes to Technical Specification For example, the processing of changes to the Technical Specifications regarding the drywell vacuum relief systems was enhanced by use of staff with operating experience. In the requalification training of licensed personnel, howe' er, the program is not adequately define Licensee is considering providing a more I definitive program in response to NRR staff question One violation was identifie Severity Level IV violation involving an operator removing a wrong fuse due to inadequate training resulting in an inadvertent ESF actuation (416/86-11). Conclusion Category. 2 Trend: Improving Board Recommendations
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None Quality Programs and Administrative Controls Affecting Quality 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, offsite support staff, offsite review committee, audit program implementation, procurement, receipt, storage and handling, and design changes and modification. A QA effectiveness inspection using a methodology based on selected licensee performance indicators was also conducted during this perio For the purposes of this assessment, this area is defined as the ability of the licensee to identify and correct their own problems. As such, it encompasses all plant activities, all plant personnel, as well as those corporate functions and personnel that provide services to the plant. The plant and corporate QA staff are part of the entity, and as such, they have responsibility for verifying quality. The rating in this area specifically denotes results for various groups in achieving quality as well as the QA staff in verifying that quality is achieve A review was performed on all sections of this SALP report in an attempt to capture apparent strengths and weaknesses related to management controls affecting qualit The following are some perceived strengths in management controls affecting quality:
- The formation of a scram reduction program in early 1985.
- Performance of a self assessment of the qualifications of the onsite HP staff which resulted in establishing job performance criteria and additional trainin Management support and involvement in matters related to radiation protection.
- Thoroughness and professionalism related to diesel generator repairs.
Management attention to correct weakness identified in an emer-gency preparedness exercise conducted in December 198 Management involvement in the planning and scheduling of the refueling outages and the resolution of technical issues that arose during refueling.
Improved training of maintenance personnel and strengthening plant staff qualifications by sending key personnel to SRO training.
The following are some perceived weakness in management controls affecting quality:
- Multiple examples of personnel failure to follow procedures.
- HP audits lacked ade quate scope, and depth to identify problems and utilized minimally experienced auditors.
Missed surveillances indicates more management attention is required for day-to- by operation NPE failure to fully evaluate some safety problems.
Lack of adequate corrective action based on selected performarce indicators.
On August 13, 1985, licensee management implemented changes to the Nuclear Production Department (NPD) organization. These organizational changes consolidated support activities and provided a more effective management chain of command for support functions within NPD. However, planning for ensuring a smooth transition was not apparent in that inconsistencies between the Technical Specification and the approved QA
- -__-_--
program description were identifie Numerous upper-tier program )
procedures that addressed plant activities within seven functional areas were identified as requiring revisio A merger of Plant Quality with the QA organization occurred during this assessment period. This merger realigned the reporting requirements of the Plant Quality group from the piant manager to the Director, QA, and established the independence required by this group for performance of quality verification functions. Management involvement was demonstrated by the comprehensive training program established for QC inspector A reorganization became effective in December 1985, that affected the Director, Quality As;urance who previously reported to the Senior Vice President, Nuclear who then reported to the President and Chief Operating Officer. The Director, Quality Assurance now reports to the Vice President, Nuclear Engineering and Support who reports to the President and Chief Operating Officer. This reorganization does not appear to have affected the independence or effectiveness of the Quality Assurance grou The licensee submitted a post warranty run operation readiness review report dated October 10, 1985, that documented the Safety Review Committee (SRC) special subcommittee review and evaluation of GGNS i
Unit 1 operational readiness following completion of the 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> warranty ru Recommendation (7) stated additional efforts should be undertaken to increare the plant system specific knowledge level of Nuclear Plant Engineering (NPE) which is considered part of the
- licensee's offsite support staff and QA personnel by sending selected l engineers through SRO or Shift Technical Advisor (STA) training.
l l Another area that the licensee has taken action to strengthen is the Quality Engineering group within NPE. A supervisor from the Quality Assurance organization with a design engineering background has been transferred to acting head of Quality Engineering within NP This will strengthen this organization in an area that has been weak in the pas Management initiated a program to conduct technical assessments of selected areas. These assessments reviewed the overall design process j and the end product for operational readiness considerations of selected system The first assessment was performed during the Decembe- 1985 thru January 1986 time fram The results were thoroughly reviewed and critiqued by other organizations and although there were deficiencies identified, the overall effectiveness was very positive. The licensee has modified their approach to conducting the technical assessments by bringing in highly qualified personnel from other sources to help in the review selected of technical areas. These assessments are much more comprehensive then those associated with the QA audits and are considered a very positive initiative that reflects management's commitment to improvemen . _ _ - _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ - .
Another positive initiative taken by QA is the Quality Assurance Trend Analysis Report which is issued quarterl This report identifies significant trends to management for evaluation to determine appropriate cause, impact and action. The report defines the areas reviewed and included in the report. Each area was reviewed and evaluated for trends having an impact on the quality of performance.
In addition to presenting tabulated data indicating the results of the analysis, a brief overall summary presents areas of concern requiring further management attention. This report is distributed to top management up to and including the President and Chief Operating Officer.
In addition to the event discussed in the Plant Operations section, dealing with an inadvertant rod withdrawal, another event occurred that indicates a failure to take prompt corrective actions on potential safety issues. On April 9,1984, NPE was made aware of the potential for the scram discharge volume vent and drain valves to be made inoperable by the positioning of their manual handwheels in the full *
open positio The position of the handwheels had not been procedurally controlle NPE failed to notify the plant General Manager until May 20, 1985, recommending corrective action. A change to the applicable operating instruction was issued on June 18, 1985.
This event resulted in violation (a) below and shows a need for more management involvement in day-to-day activities.
On August 23, 1985, the licensee identified a programmatic problem in that the potential effect of the removal of Unit 2 components upon the operability of Unit I components or systems was not being evaluated.
The licensee initiated a review and evaluation of administrative and procedural controls to place a program in effect to prevent future occurrences. Subsequently, it was discovered that the licensee still failed to have adequate controls to determine if changes initiated under Unit 2 cognizance involved an unreviewed safety question for Unit 1. This resulted in violation (c) below and showed a need for more management attention in the Unit 2/ Unit 1 interface area.
Additionally, LER 85-33 which discusses this event, has never been updated to define what final corrective actions were or will be taken to correct this problem or when final corrective action is due.
NPE has failed to fully evaluate some safety problems. In one example, NPE was requested to provide information concerning low SSW flow to ESF switchgear room coolers due to plugging which was recognized during flow balance testing of the B SSW loop. The A SSW loop flow balance was a future outage task. NPE's initial response was that the A SSW train coolers were available as an alternate to the B SSW train cooler Also, NPE stated that if a cooler loses its cooling capability resulting in a loss of operation of electrical switchgear in that room, the alternate ESF electrical switchgear located in other rooms is available for operatio NPE's review was evidently cursory in that the root cause of the plugging of the B SSW loop would also make the A SSW loop suspect for operation. Since all electrical
i
switchgear rooms were potentially affected, the statement that other ESF electrical switchgear located in other rooms is available for operation was unacceptabl 'Another example which resulted in violation (a), in the Surveillance
,
Section was the non performance of 10 CFR 50, Appendix J and Technical
! Specification (TS) required leak rate testing of several test flanges located on the outside of containment and drywell personnel airlock The first time anyone recognized that if the replacement flanges and isolation valves required leak rate testing then the presently
! installed test flanges should be leak checked was when the PSRC was presented the TS change request for review in June of 1985. The PSRC l
requested the flanges be tested and NPE was requested to perform an I evaluation to determine whether or not they were required to be leak
,
tested. NPE's evaluation determined that these test flanges were indeed containment and drywell penetration isolations and must be leak checked in accordance with TSs and 10 CFR 50, Appendix J. This event i further illustrates the problem with inadequate evaluations being performed by both NPE and the Licensing Group.
As noted in the Operations Section, there were numerous discrepancies noted between the Piping and Instrument Diagrams (P& ids) and the actual plant configuration. Additionally, the P& ids were almost illegible at times due to their poor quality. The licensee has initiated several program improvement In 1986, the licensee implemented a Computer Aided Drafting (CAD) system that will significantly improve the i legibility of the drawings and the timeliness of as-built updating of l
drawing The current as-built discrepancies against those drawings L that are being tracked by open MNCRs is scheduled to be completed by l the end of the refueling outage (November 1986). The licensee has also i initiated selected field walkdowns as a further review of the overall
- as-built drawing progra This program also reflects management's commitment to improvemen Another event that requires management attention concerns the FSAR l update program discussed under Licensing Activities. In the review of l change notices for the FSAR update program QA identified some changes l that they (QA) felt required a 10 CFR 50.59 review. This comment was evaluated by licensing and they resolved the issue with QA by l
explaining that the particular issue was recognized by MP&L prior to issuance of the operating license. Since this response is obviously flawed, it appears QA was too easily convinced that they did not have a valid issu Strengths were identified with the activities of the Safety Review Committee (SRC) in that they had established as part of their function, the responsibility to ensure that a closed loop management control system exists for the identification and correction of problem Continuous oversight of the corrective action program implementation for identified problems is provided in documented report by SRC standing subcommittees to the SRC during SRC full committee meetings.
,
c , .-,_ ,.- , . _ - . . -, -._.~s,__. - . _ . . _ - - - . - - - , _ , - . ~ _ - . -
- - - . . - _ . . - - - _ _ , , - - - , , - --.._., ._ ____.--- -
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. _ _
However, the identification, documentation, and back implementation of corrective . action appears to be ineffective in ensuring prompt correction of identified problems. This situation is related to the adequacy of the operational QA program, and its implementation by the line organization, including their involvement in assuming direct responsibility for qualit Concerns related to this issue were expressed by the NRC in a previous SAL A QA effectiveness inspection was conducted using the performance indicators as the basis for a broad based assessment across various performance areas. The premise of this inspection was that the overall intent of QA is to ensure safe and reliable plant operation; and the ultimate effectiveness of the licensee program to ensure overall quality can be measured objectively by examining various operational performance indicator Licensee management has established a Management Information Program System (MIPS) that provides a monthly report to senior management concerning the status of 37 licensee selected performance indicator Accordingly,15 of the 37 performance indicators were examined for absolute value, significant trends, and relationship to licensee goal The use of these reports by senior management demonstrated their involvement in all activities that impact plant operation and their commitment to ensure quality performance of these activitie QA effectiveness was assessed effective if the intent of licensee 1 performance objective was reasonably achieved despite minor problems
! encountered. QA effectiveness was assessed as highly effective if the
~l performance indicator exceeded the performance goal / objective, and/or little or no problems were encountered in achieving the intent of the
. performance objective. Finally, QA effectiveness was assessed as ineffective if a major breakdown of the corrective action program for
'
monitored activities occurred, thus preventing achievement of perfor-mance objective inten Licensee's QA effectiveness was assessed as
,
follows for each performance indicator investigated.
'
Performance Indicator QA Effectiveness Forced Outage Rate Effective Unplanned Reactor Trips while critical Pending-awaiting data Unplanned Safety System Challenges Highly Effective (ECCS and Emergency AC Power Systems)
Safety System Unavailability Effective (ECCS and Emergency AC Power Systems)
Licensee Event Reports Effective
- Collective Radiation Exposure Pending-awaiting data
_ _ _ _ _ ._.._ _ _ _ _ . _ _
._ - ___ _ ___ __._____ _
,
Performance Indicator QA Effectiveness (Continued)
Status of Licensing Commitments Effective Maintenance Work Orders Effective Temporary Modification Status Effective Personnel Error Incident Report Ineffective Spare Parts Availability Highly Effective Design Change Status Ineffective Material Nonconformance Report Ineffective Status (MNCRs)
QA Nonconformance Perfnrmance Ineffective Indicator (CARS)
Design Document As-Built Status Ineffective The Design Change Status performance indicator does not directly monitor deficiencies within the engineering design performance area.
This function is performed by the quarterly QA trend report which monitors problems within engineering design activities as a function of the number of change notices (CNs) generated per design change package (DCP). This report revealed numerous problems in engineering-design activities performed by Nuclear Plant Engineering (NPE). As part of the corrective action plan developed, NPE is presently implementing a pilot program to monitor their activities using a methodology similar to that employed by the QA organization.
Licensee management has demonstrated its capability in identifying and performing root-cause analysis for problems revealed by adverse tre .ds of the above indicator Generic failure of the corrective action program to promptly solve identified problems for material non-conformance reports (MNCRs) and corrective action requests (CARS)
were identified as program deficiencies. Changes to the program have been made to correct these deficiencies for MNCRs and will also be instituted for CARS. The establishment of a Management Review group to evaluate each incident associated with a personnel error will ensure a closed loop for problem identification and corrective action necessary to maintain quality operations.
Management meetings were held on February 20, 1986, and May 12, 1986, between licensee senior management and NRC staff to discuss the QA Program area of the SALP which received category three rating for two consecutive year Licensee management at these meetings stated that
)
following corrective actions plans were in progress: increased personnel training; expansion and implementation of detailed nonconformance trending; increased effort on root-cause determination; and expanded specific trend reports in functional areas with weekly reports to executive management. Developmental areas were said to include operability functional assessments of systems and increased QA involvement in design, hardware, and operational area The broad based assessment of QA effectiveness across various performance areas verified licensee statements regarding developed corrective action plan Licensee's QA program effectiveness at ensuring quality (all inclusive quality assurance) was assessed as average to goo This assessment was based on licensee management's commitment to quality as demonstrated by the capability to identify problems of safety significance at Grand Gulf Nuclear Statio Developed corrective action plans, of necessity, require time to be properly implemente Given the current positive attitude towards quality and the programs in place, it can reasonably be expected that full implementation of these program: will result in improving trerds of the indicators assessed as being ineffectiv Four violations were identified. Violations occurred in performance areas of engineerir.g-design, corrective action program and plant operations. These findings may be viewed as symptomatic of the lack of QA effectiveness as revealed by the respective performance indicato Severity Level IV Violatio Failure to initiate prompt corrective action for identified safety problems (416/85-22). Severity Level IV Violatio Failure to submit an LER within 30 days (416/85-33). Severity Level IV violation for failure to have management controls for making a determination that changes to Unit 2 could involve an unreviewed safety question that could impact Unit 1 (416/86-17), Severity Level V violation for failure to take prompt corrective action on non-seismic qualified relay (416/86-04). Conclusion Category: 2 Board Recommendations None l
- -A
39 SUPPORTING DATA AND SUMMARIES Licensee Activities During this assessment period the licensee completed the start-up test program, the first fuel cycle and had two major outages - a fall 1985 maintenance outage and initiation of the first refueling outage in September 198 This performance assessment is based on the evaluation of the licensee's performance in support of licensing actions for Unit I which had a significant level of activity during the evaluation perio (Licensing activities for Unit 2 were minimal). These actions included the licensee requests for license amendments, responses to generic letters and various submittals of information for multi plant and NUREG-0737' actions. Completed actions during this period are listed belo Plant specific actions completed:
Preservice inspection relief requests
ISI 10 year program and relief requests
Certificate for polution control
High ground water level
Reactor internals test results-LC2.C.(9)
Soil-structure interaction-LC2.C.(6)
Masonry wall design-LC2.C.(8)
Containment structural integrity test
- Inplant SRV tests-LC2.C.(31)
Service water pump tests-LC2.C.(10)(b)
Control room inleakage rate
- ODCM revisions through Rev. 6
Drywell vacuum breaker position indication LC2.C.(35)
Surveillance of fuses used as containment penetration
,
overcurrent protective devices
Shift advisors with BWR experience-LC2.C.(29)
FSAR amendment Section 13.2 Training and Appendix 98 Fire Protection Program
Deletion of automatic load follow startup test
Changed reactor isolation startup test
Dynamic qualification of refueling equipment-LC2.C.(10)
Commission Meetings None Schedule Extensions Granted
- Increased inspection interval of low pressure main steam turbine discs from one fuel cycle to 50,000 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> . - .
.= . _ _
Extended date for submittal of final analysis of hydrogen control system from first refueling outage completion to June 30, 1987.
Extended date for installation of isolation valves in MSIV-LCS instrument lines from the first refueling outage to the second refueling outage.
- Extended date for completion of DR/QR inspection of a TDI diesel generator from the first refueling outage to the second refueling outage.
Reliefs Granted
Preservice inspection reliefs (three)
Inservice inspection reliefs (thirteen).
Exemptions Granted None.
License Amendments Issued No. 3 Reorganization of personnel department.
No. 4 Add temporary license condition changing secondary contain-ment boundary and change Technical Specifications (TSs) for equipment changes: fire detection instruments, horizontal fuel transfer system and ECCS return lines to wetwell.
No. 5 Changed license condition 2.C.(20) and TSs to allow modifications to be made to standby service water (SSW) Loop B.
No. 6 Changed TSs regarding radiation control supervision, control rod scram accumulator low pressure alarm setpoint and for equipment changes: improved ventilation at reactor water sample station, additional smoke detectors, and diesel generator protective trips.
No. 7 Changed TSs to make names of certain valves consistent with plant nomenclature and to designate a more accessible valve in the RHR system as an isolation valve.
No. 8 Changed TSs to permit exception to examination prerequisites for two candidates for SRO licenses.
No. 9 Changed TSs to allow one time exception to Renulatory Guide 1.8 regarding qualifications of radiation protection manager No. 10 Changed license condition 2.C.(28) to allow credit for new management having nuclear puwer plant management experience and changed TSs to reflect Nuclear Production Department organizational changes.
No. 11 Changed TS surveillance requirement for standby gas treatment system heate . - - .- - -. - - - - _ _ - - .
License Amendments Issued (Continued)
No. 12 Changed license condition 2.C.(26) by increasing the inspection interval of low pressure main steam turbine discs.
No. 13 Changed License condition 2.C.(33)(d)(2) to make hydrogen control analysis schedular requirements consistent with 10 CFR 50.44.
No. 14 Changed TSs to reflect changes in Unit 1 operating organization.
No. 15 Changed TSs to change maximum closing time of isolation valve based on tests and add an automatic sprinkler system.
No. 16 Changed TSs to allow plant operation with one operable recirculation loop, with increased power at reduced flow rates and with recirculation flow rates up to 105% of rated.
No. 17 Changed TSs to allow use of high density spent fuel racks.
No. 18 Changed TSs for ' equipment modifications: diesel generator protective devices and emergency override of test mode, changed license condition 2.C.(20) and TSs to allow modifications of SSW Loop A, clarified TS surveillance tests of EOC-RPT breakers, changed TSs to allow additional loads to be placed on batteries.
No. 19 Changed TSs to add a control room-to-remote shut down panel isolation switch, to correct an error in the RCIC steam line high flow trip setpoint, and to correct addministrative errors.
No. 20 Changed TSs to reflect equipment modifications: interlocks for ECCS injection valves, logic for the ADS, installation of strong motion seismic accelerometer.
No. 21 Changed TSs to reflect name changes in drywell chilled water system, clari fy record retention, correct reference in radiological monitoring TS, allow inoperability of certain HPCS actuation signals, and to reflect equipment modifica-tions: position indicators on drywell vacuum breakers, SDV level instrumentation and valves, and ADS accumulator pressure instrumentatio In addition, license condition 2.C.(33)(b) was changed to make it consistent with present staff requirements for TMI Action Plan Item I.G.1, special low power testin No. 22 Temporary change to TSs governing secondary containment to allow outage work to continue while control rods were moved in defueled control cell No. 23 Changed TSs to reflect second fuel cycle operation with new Exxon fuel replacing spent GE fue Emergency Technical Specifications Granted License Amendment No. 22 provided temporary relief from secondary containment integrity requirement Orders Issued None
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_. -
Gaseous Effluents (Ci per Unit)
RII Avg BWR* 1985 First half 1986 Fission and Activation Gases 12040 151 90 Iodine .01 .00027 .00006 Particulate .07 .00054 .00014 Tritium 1 .11 1.53 Liquid Effluents (Ci per Unit)
RII 1985 First half 1986 Fission Activation .21 .21 .024 Products Tritium 1 .17 6.07
- Excludes release for Browns Ferry and Grand Gulf B B. Inspection Activities During this assessment period, routine inspections were performed at the facility and corporate office by the resident and regional inspection staffs. A special Quality Assurance team assessment was conducted during the period, the results of which are discussed in Section IV.K, above. A full scale emergency preparedness exercise was conducted which involved full NRC participatio Results of this exercise are documented in Section IV.F.
C. Investigation and Allegation Review There were four allegation cases opened and no investigations conducted during the assessment period.
D. Escalated Enforcement Actions Civil Penalties On June 3, 1985, 5500,000 Civil Penalty (CP) was issued for one Severity Level I, four Severity Level IIs and one Severity Level I These events occurred in 1983. The licensee's response of 9/12/85 contested this action. NRC evaluation is in progres The $125,000 CP issued March 21, 1985, for five Severity Level IIIs was denied by the licensee on April 19, 1985. The NRC withdrew the CP and four of the five Severity Level IIIs on March 20, 198 A Severity Level III with no CP was issued on May 17, 1985, on Containment Penetratinos Material False Statement. This event occurred in 198 . Orders (Those reflected to enforcement)
None.
E. Licensee Conferences Held During Appraisal Period Enforcement conference was held in the Region II office on August 8, 1985 to discuss Appendix R and failure to perform a 50.59 review. The issue has been identified as an Unresolved Item (416/S5-16-03).
A management meeting was held in the Region II office on February 20, 1986, regarding improvement of Licensing and QA Category 3 SALP rating A management meeting was held at the site on May 12, 1986, regarding an update of the Category 3 SALP ratings and for J. N. Grace to issue operator license certificates.
F. Review of Licensee Event Reports and 10 CFR 21 Reports Submitted by the Licensee During this assessment period, there were 55 LERs reported. The distribution of these events by cause, as determined by the NRC staff, was as follows:
Cause Unit 1 Component Failure 11 Design 4 Construction, Fabrication, or 8 Personnel
- Operating Activity 3
- Maintenance Activity 4
- Test / Calibration 9
- Other 5 Quality Control 5 Out of Calibration 1 Other _5 TOTAL 55 l
l
,
. . . -. .
44 The number of LERs reported represents an average monthly reporting frequency of about four reports. When compared to the low power license SALP reporting period ending November 1,1984, the reporting frequency has decreased by about a factor of 2. Of the reportable events, 13 were scrams involving rod motion and one with no rod motio Twelve scrams were - valid automatic - protective actions, two were manually initiate During this rating period, the licensee has instituted several changes in staffing to enhance the licensing function. MP&L staff have been placed in licensing and safety positions formerly held by contractor personne A plant licensing section has been established to facilitate coordination between plant, engineering, and licensing on licensing matters. The staffing has been adequate to handle licensing matters during this rating period.
I. Enforcement Activity VIOLATION / DEVIATION SUMMARY FUNCTIONAL N0. OF DEVIATIONS AN9 VIOLATIONS IN EACH AREA SEVERITY LEVEL D V IV III II I Plant Operations 10 Radiological Controls 1 2 Maintenance 2 5 Surveillance 3 4 Fire Protection 1 1 Emergency Preparedness 1 Security Outages 1 Licensing 1 1 Training 1 Quality Programs and 1 3 Administrative Controls Affecting Quality TOTAL 3 6 29 J. Reactor Trips May 24, 1985 Scram from 74*J power due to a main turbine trip on low condenser vacuu This was caused by electricians performing tests on a breaker initiating an inadvertent opening and subsequent loss of circulating wate Root cause was inadequate instructions to the electrician __
-
A
June 4, 1985 Scram from 97% power due to low condenser vacuu .
This was caused by low steam flow through the steam jet air. ejector due to cycling of the steam jet air ejector suction valve. The root cause was plugging of the drain line from the steam jet air ejector steam supply moisture separator to the condense June 27, 1985 Scram from 98% power due to mode switch being'taken to shutdown. Operators anticipated a trip when the pump forward capacity of the heater drain pump system and all three condensate pumps tripped on low hotwell level. Initiating event was a switch failure causing isolation of the feedwater heate July 3, 1985 Scram from 99.9% power due to a main turbine trip on low condenser vacuum. Circulating water pump B tripped due to failed component in the trip circuit Rotor Cage Hi Temperature faulty thermocouple circuitr August 7, 1985 Scram from 91.7% power due to a main turbine tri A painter bumped a Electric Generator Protection Logic connector that was bad giving a false low flow signal to the logi September 16, 1985 Scram from 100% power due to main turbine trip on low condenser vacuu Both A and B circulating water pumps had tripped on low lube water flo Pointers had inadvertently tripped a breaker supplying power to the pumps supplying lube water to the circulating water pump December 31, 1985 Scram from 99% power on low reactor water level due to the loss of condensate and feedwater pumps. The 4 condensate pumps tripped from low condenser hot well leve Intermittent condenser hot well low level alarms had been received but Operations failed to react expeditiously to correct the proble January 1,1986 Scram from <1% power on low reactor water leve Operator raised the pressure setpoint to 600 psig ard continued to pull rods while monitoring vessel level recorder which was stuck. Feedwater pressure decreased below reactor pressure and water level started decreasing resulting in a scra January 22, 1986 Scram from 60.4% power due to a generator load reject. The load reject occurred when power grid breaker switching resulted in attempting to restore GGNS to the grid while out of phase with the gri . . . - . .
. . . .
"+
'4 February 12, 1986 Scram from 13*4 power while reducing power due to high unidentified leakage. The reactor feedwater pump discharge pressure was allowed to fall below reactor pressure causing a low flow condition to be sensed by the feedwater control logic initiating a 15 second timer which trips the feedwater pum The reactor scrammed on low water leve April 7, 1986 Manual scram from 61% powe The Shift Superintendent ordered a reactor scram when a safety relief valve failed to reclose after two minutes. I&C technicians were attempting to reset the 10-10 set trip units without written instruction July 25, 1986 Scram from 78*; power on high scram discharge volume water level. Electricians working in a switchgear room inadvertently opened a breaker causing loss of power to many systems including instrument ai Loss of instrument air resulted in control rod drive scram valves drifting open with rods drifting into the core and filling the scram discharge volum August 25, 1986 Scram from 78.8% power due to fast closure of main turbine control valves. An engineer retrieving a schematic from the load reject relay housing inadvertently closed the normally open contacts.
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