ML20211P215
| ML20211P215 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie, Turkey Point, La Crosse, Big Rock Point, 05000000 |
| Issue date: | 12/16/1986 |
| From: | Grimsley D NRC OFFICE OF ADMINISTRATION (ADM) |
| To: | Graber L NUS CORP. |
| References | |
| FOIA-86-827 NUDOCS 8612190007 | |
| Download: ML20211P215 (3) | |
Text
U.S. NUCLEAR CE!ULATORY COMMISSIO
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) FOIA-86-827
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RESPONSE TO FREEDOM OF INFORMATION ACT (FOlA*. REQUEST N
...e ooan r.E.C.1.~6 1986 D
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REQUIS1ER Mr. Lyle Graber PART l.-RECOROS RELEASED OR NOT LOCATED (See checaed bonest No agency records subysct to the request have been located No additonal agency records subrect to the request have been located Igency socords subsect to the request that are identded e Appendia A
a,e al,ead, saawe to, pm,c in,pect,on and copvmg m tn. NRC Pubiic oocum.n: Room.
X 1717 H Street, N W., Wawngton, DC Agorcy records subrect to the request that are identded in Apperds _ E are bemg made available for pubhc inspection and copying in the NRC Pubhc Document X
Coorn,1717 H Street, N W., Washengton, DC, in a folder under the FOIA number and requester name.
The nonproprietary versson of the proposalts) that you agreed to accept in a telephone conversaton wrth a member of my staff is now be*ng reade avadable for pubhc inspection and coying at the NRC Public Document Room.1717 H Street. N W, Washmgton, DC. in a folder under the FOIA number and requester name.
Enclosed is mformaton on how you may obtam access to and the charges for copymg records placed m the NRC Pubhc Document Room.1717 H Street, N W., Washmgton. DC.
Ag.ncy records sod,ect to the re est are encioned Any applicabie charge for cop s of the recordi provided and paymoni procedures are noted iri ih. comments section.
Records subrect to the request have been referred to another Federal agencyhes) for revew and derect response to you-in vow of NRC s response to this request. no further action is being taken on appeal letter dated PART li A-INFORMATION WITHHELD FROM PUSLIC DISCLOSURE Certain mformaron in the requested records es being withhead from pubhc disclosure pursuant to the FOIA exemrtons describad 6n and for the reasons stated in Part 11. sec.
ions s. C, and o Any,.i.ned portons of ih. docum.nts for which oney part of the record a bema wi*heid are b no made avaaabie for pubi.c inspection and copyms in the NRC Public Document Room,1717 H Street. N W., Washmgton, DC, m a folder under tNa FOi A number and requester name Comments 8612190007 861216 PDR FOIA GRADER 86-027 PDR s e tymt.DielCt0A DW '
08 e IS.AND RECORQS (v h').*All
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C*C FOIM 464 ireet si is esi
Re:
FOIA. 36/827 APPEN01X A
RECORDS MAINTAINED AMONG PDR FILES NUMBER DATE DESCRIPTION 1.
6/30/86 Enclosure to La Crosse letter dated 8/27/86-transmitting Semiannual Effluent Report.
Accession No. 8609100205 (18pages) 2.
6/30/86 Enclosure to Big Rock Point letter dated 8/28/36 transmitting Semiannual Radioactive Effluent Release Report.
Accession fio. 8609090516 (11pages) 4
Re:
F0IA.86-827 APPENDIX B
RECORDS MAINTAINED IN THE PDR UNDIR THE ABOVE REQUEST NUMBER NUMBER DATE DESCRIPTION 1.
11/1/84-4/30/86 Enclosure to the Turkey Point and St. Lucie SALP Report dated 8/21/86.
(139pages) l r
I
ENCLOSURE 1 SALP BOARD REPORT U. S. NUCLEAR REGULATORY COMMISSION REGICN II SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE i
INSPECTION REPORT NUMEERS 50-250.'96-27 AND 50-251/86-27 FLORIDA POWER AND LIGHT CCMPANY TURKEY POINT UNITS 3 and 4 NOVEMBER 1, 1934 THROUGH APRIL 30, 1986 O
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I.
Introduction The Systematic Assessment of Licersee Performance (SALP) program is an integrated NRC staff effort to collect available observations and data on a periodic basis and to evaluate licensee performance based upon this information.
The SALP program is 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 p'. ant construction and operation.
An NRC SALP Board, composed of the staff members listed below, met on July 16, 1986, to review the collection of perforrance observations and data to assess licensee performance in accordance with guidance in NRC Manual Chapter 0516, " Systematic Assessment of Licensee Perfo ance." A summary of the guidance and evaluation criteria is provided in Section II of this report.
This report is the SALP Board's assessment of the licensee's sa fety performance at Turkey Point Units ? and 4 for the period No,erber 1,1984, through April 30, 1986.
SALP Board for Turkey Point Units 3 and 4 L. A. Reyes, Acting Director, Division of Reactor Projects (DRP), RI! (Chairman)
J. P. Stche, Director, Division of Radiation Safety and Safeguards (DRSS), Rll V. W. Panciera, Acting Director, Division of Reactor i
Safety (ORS), RII D. M. Verre111, Chief, Reactor Projects Branch 2, DRP, RI!
L. S. Rubenstein, Director, PWR Project Directorate 2, 1
Division of PWR Licensing - A, NRR l
D. G. Mcdonald, Project Manager, PWR Project Dire: tora:e 2 Division of PWR Licensing - A, NRR D. R. Brewer, Senior Resident Inspector, Turkey Point, DRP, R:I Attendees at SALP Board Meeting:
S. A. Elrod, Chief, Reactor Projects Section 2C (RP2C) ORP, R!!
R. V. Celenjak, Senior Resident inspector, St. Lu:'e, CRP, Rl!
l K. D. Landis, Chief, Technical Support Staf f (TS$ f, ORD, RIl J. K. Rausch, Reactor Engineer, TSS, DRP, RI!
T. C. MacArthur, Radiation Specialist, TSS, DRP, R!!
l S. Guenther, Project Engineer, RP2C, ORP, R!!
I I
2 II.
Criteria Licensee performance is assessed in selected functional areas depending on whether the facility has been ir the construction, preoperational, or operating phase during the SALP review period.
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 observations.
Special areas may be added to highlight significant observations.
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.
A.
Management involvement in assuring quality B.
Approach to the resolution of technical issues from a safety standpoint C.
Responsiveness to NRC initiatives D.
Enforcement History E.
Operational and construction events (including response to, anaiysis
.of, and corrective actions for) s F.
Staffing (including management)
G.
Training and qualification effectiveness Based upon the SALP Board assessment, each functienal area evaluated is classified into one of three performance categories.
The definitions of these performance categories are:
Cate. gory 1:
Reduced NRC attention may be appropriate.
License management attention and involvement are aggressive and oriented toward nuclear safety; license resources are ample and ef fectively used su(h that a high level of performance with respect to operational safety or construction quality is being achieved.
Ca_tegory 2:
NRC attention should be maintairad at normal levels.
Licensee management attention and involvement are evident and are concerned with nuclear safety; licensee resources are adequate and are reasonably of fective such that satisfactory performance with respect to operational safety or construction quality is being achieved.
Ca_t egoryj:
Both NRC and licensee attention should be increased.
(.icensee management attention or involvement is acceptable and considers nuclear
- safety, but weaknesses are evident; licensee resources appear to be strained or not effectively used such that minimally satisfactory performance with respect to operational safety or construction quality is being achieved.
f
3 The functional area being evaluated may have some attributes that would place the evaluation in Category 1, and others that would place it in either Category 2 or 3.
The final rating for each functional area is a composite of the attributes tempered with the judgement of NRC canagement as to the significance of individual items.
The SALP Board may also include an appraisal of the performance trend of a functional area.
This performance trend will cnly be used when both a definite trend of performance within the evaluat'on period is discernible 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
B ose of the assessment period.
Declining:
Licensee performance was determined to be declining near the Rose of the assessment period.
III. Summary of Results A.
'Overall Facility Evaluation i
Weakness in facility performance have been rated in the plant operations area; the maintenance area; the m ality Drograms and admini-strative controls affecting quality area and the training qualification l
effectiveness area. The emergency preparedress area was improved to a major strength area.
Management attention to the facility has been intense during this assessment period.
Tne various areas of the Performance Enhancement Program (PEP) have been p rsued vigorously as j
have other initiatives to improve performance. While the general trend is improving and the plant and its staff is in better condition than at the beginning of the period, a number of incividual significant events and inspection findings caused by licensee weaknesses have precluded higher ratings at this time.
Two especially significant licensee initiatives were commenced during this perioc; reccnstitution of safety l
system design basis and and change over to r:dified Standard Technical Specifications (TS).
These initiatives are of far greater magnitude and scope than any simila'r initiatives at other utilities.
These initiatives are very closely managed and are schedaled to be completed during the next SALP period.
We believe that they are the keys to l
improved performance, e
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4 B.
The performance categories for the current and previous SALP period in each functional area are as follows:
July 1, 1983 -
November 1, 1984 Functional Area October 31, 1984 April 30,1986 Plant Operations 3
3 Radiological Controls 2
2 Maintenance 3
3 l
Surveillance 2
2 Fire Protection 2
2 i
1 Security and Safeguards 2
2
' Outages tht Rated 2
Quality Programs and Administrative 3
3 I
Controls Affecting Quality Licensing Activities 1
2 Training and Qualification Not Rated 3
Effectiveness IV.
Performance Analysis A.
Plant Operations 1.
Analysis During the evaluation period, inspections of plant cperations were performed by the regicnal and resident inspection staffs. The major activities at Turkey Point included routine commercial operation for Units 3 and 4 with maintenance outages conducted on both units.
Turkey Point Unit 4 shut down in January 1986 for refueling and Appendix R modifications has remained in cold shut down pending resolutten of emergency diesel generator loading issues. Turkey Point Unit 3 refueled between April and June 1985.
The licensee's general performance in the plant operations area remained weak throughout a significant portion of th4 SALP period; a number of operations problems were identified by both the NRC and the licensee and are discussed below.
The flicensee has
5 established programs to address these problems and appears to be taking appropriate corrective actions toward their resolution.
Some improvement in plant operations was evident during the later part of the SALP period: the licensees improvement programs and their results are also discussed below.
Several significant operational problems were identified which reflected the need for increased supervisory involvement in the operation (and maintenance) of the plant.
Plant operations and performance were often adversely affected by the licensee's unaggressive approach to the resolution of maintenance problems.
The plant staf f has tried to operate areund maintenance problems, often with less than satisfactory results.
Maintenance items, which should have been immediately addressed, were delayed while special procedures were implemented to compensate for the problem.
Decisions to change administrativa policy have been made at a relatively low level by processing on-the spot changes to procedures.
Changes were routinely made which were shortsighted, in that their real purpose was to allow the plant to coexist with a maintenance problem, rather than to perform a task mos correctly and with greater precision.
The Operations Ocpartment of ten did not question engineering and maintenance solutions to problems until they adversely affecte; plant performance.
This resulted in a number of poor practices and regulatory violations.
In May 1985, the Unit 3 Spent Fuel Pool (SFP) transfer canal had to be drained, but the normal method was impossible because of a stuck open valve in a SFP recirculation flowpath.
The licensee chose to drain the canal by lowering the reactor cavity level via the Residual Heat Removal (RHR) system without initiating repair ef forts on the stuck valve.
In trying to compensate for the valve maintenance problem, the licensee lowered the water level to less than 23 feet above the reactor vessel flange, while only one of two required RHR loops was operable, thereby inadvertently entering a TS limiting condition for operation.
In June 1985, the licensee was unable to pressurize the Unit 3 accumulators with nitrogen due to a leaking supply line.
Opera-tions procedures were modified to allow boron sarrpling af ter the accumulators were operational instead of requiring sampling prior to plant coolant temperatures exceedi *g ?00 degrees Fahrenheit (F) as required by the TS.
(Violation d re*.rs.)
The low head accumulators were operated in a manner not addressed in the accident analysis section of the FSAR.
The. deci sion to change the reactor startup procedure such that the[ accumulators were not placed in service at 1000 psi and the decision to operate u
6 at hot standby for several days without the accumulators available was not reviewed by the Plant Nuclear Safety Committee (PNSC) prior to implementation.
(Violation g refers.)
During several days in July 1985, Unit 4 was operated at full power with both source range nuclear instru ents out of service due to calibration deficiencies.
The Maintenance Department did not place the appropriate priority on the repair effort until the NRC asked the licensee to justify the delays. The Operations and Quality Control (0C) staffs had tolerated this condition for at least four days prior to initiating corrective maintenance.
In July 1985, the Unit 3 axial flux deviation alarms were declared out-of-service because the computer which processes the axial flux signals had not been updated with the appropriate alarm setpoints, which had been available for over six weeks. The Operations staff had to compensate for the deficient annunciators by taking manual axial flux readings per the TS.
For approximately three days, the Operations staf f worked around a proble n that a reactor engineer later corrected in less than an hour.
i On November 29, 1985, the licensee reported that portions of the Unit 3 and 4 cold leg accumulator fill lines were not seismically qualified.
Isolation valves in the a;cumulator fill lines were not
- shut, however, until eight days after an engineering evaluation determined that they should be.
On February 13, 1986, Power Plant Engineering informed the Turkey Point Staf f that an intake cooling water (ICW) valve was single failure prone and could defeat the entire accident heat removal system.
The licensee failed to take appropriate compensatory action, until required by NRC Region !!.
Proposed enforcement action is pending.
The licensee's approach to the resolution of technical issues, an area identified as inadequate in the previcus SALP, has remained inadequate.
The licensee has not expeditiously identified the safety significance of operational problems known to exist in several safety-related systems.
For example, a 10 CFR 21 evalua-tion on main steam isolation valve (MSIV) failure modes was delayed for nine months and a similar evaluation on ICW control valves was delayed for 18 months.
Both issues were eventually determined to have safety significance.
Correction of Component Cooling Water (CCW) piping discrepancies for two high head safety injection pumps was delayed for several years duririg which the potential for single failure was not correctly evaluated.
Enforcement action was talen subsequent to the SALi[ period.
The spent fuol pool was operated in a cooling configurat<on that could have drained the pool and was outside of the saf'uty analysis.
7 System realignment was delayed for several months subsequent to NRC identification of the problem.
The Auxiliary Feed Water (AFW) system nitrogen supply was not adequately tested following the establishment of redundant trains.
The AFW system flow control valve trim was not properly adjusted for several years, preventing stable system operation in the automatic mode.
The instrument air system was operated without regard for the functionality of
- heaters, dryers and moisture separators, resulting in water entering the system and adversely affecting the operability of the AFW flow control valves.
Operation of the two units was severely impacted by the repetitive failure of the instrument bus static inverters.
Unreliable operation had been experienced for several years, and inverter failures were responsible for several reactor trips during the summer of 1985.
Despite the repetitive inverter failures, the licensee failed to develop adequate Off Normal Operating procedures (ONOPs) for loss of 120 volt vital instrument panels.
The procedures failed to address methods of restoring system operability; consequently, the units were subjected to transient,y of a larger and more severe nature than was necessary.
All l'2 static inverters were replaced between July and September 1985.
In June 1985, the Unit 4 reactor tripped due to the loss of the 4C inverter and instrument panel 4P06.
Numerous vital control and indication circuits remained de-energized for approximately 50 minutes resulting in a significant decreasing pressure transient.
The pressure transient appeared to be aggravated by excessive pressurizer spray bypass flow, but the licensee did not pursue that possibility in a timely fashion.
The licensee subsequently confirred that the bypass valves were 1/2 turn open instead of the required 1/8 turn open.
Procedural compliance, an area which has received significant management attention, has improved but remains a problem as indicated by the numerous Technical Specification 6.8.1 violations in the areas of operations, maintenance and surveillance. Manage-ment's requirement for verbatim compliance has been amply promulgated via inter-of fice correspondence and lecture ppsenta-tions. The Procedure Upgrade Program (PUP) has improved 'the form and content of many procedures thereby reducing misinterpretations and personnel errors. A total of 740 raocedures will be revised in the areas of normal and emergency o*. ration, surveillance, and maintenance. The program remains on schedule and is approximately 85 percent complete.
Procedures generated by the PUP are clearly written and give due regard to human factors cencerns.
The pre-implementation review process each procedureIreceives is extensive and includes input f rom knowledgeable staf members.
A generalwillingnessexiststocorrectproceduraldis{crepanciesby submitting procedure change requests when necessary.
Never-the-less, procedural noncompliances continue to occur, usually as the result of inattentiveness during implementation.
8 Personnel errors during 1985 and the first quarter of 1986 resulted in 13 Unit 3 and 11 Unit 4 inadvertent actuations (partial or complete) of the Engineered Safety Features (ESF) circuitry.
Of these actuations, four resulted in Unit 3 reactor trips and three resulted in Unit 4 reactor trips.
The licensee has developed a program to protect sensitive relays from jarring by installing protective covers and barriers. Considerable effort has been expended to minimi:e inadvertent ESF actuations.
However, during the first four months of 1986, six actuations occurred, two on Unit 3 and four on Unit 4.
During this SALP period the Turkey Point Plant reported 109 non-security events to the NRC Operations Center as required by 10 CFR 50.72.
Of these events, 40 percent were due to equipment failures and 19 percent were due to operator errors.
A large number of the operator error events were due to inadvertent operation of equipment caused by personnel accidentally bumping relays, shorting contacts, etc., while performing maintenance or troubleshooting.
It appears that these types of errors could be due to inadequate training or procedures.
i Of the 109 reportable events, 13 were of suf ficient interest to result in operating reactor event briefings to NRC management.
This is a relatively high number compared to other operating plants.
The number of trips at Turkey Point was slightly less than the industry average and the availability factor for Unit 4 was significantly higher than the national average.
A strong program requiring independent verification exits.
The program has assisted in reducing personnel errors and has the full support of plant management.
The program is effectively implemented, primarily through the clearance tag process and by incorporation into operations, maintenance and surveillance p roCeriu re s.
The staffing of the Operations Department is currently adequate to meet management objectives.
The staf fing level has increased from 85 in January 1984 to 136 as of June 1986.
The Operations Department had hoped to implement a program to place an additional sentor reactor operator (SRO) on each shif t as an assistant to the Plant Supervisor-Nuclear, but the passing rate for SR0s on NRC licensing examinations has not yielded a sufficient number of extra operators to support that objective.
This augmentation was further delayed by a poor pass rate on NRC requalif.ication exams but is expected to necur in the fall of 1986.
(Sed the Training Analysis for additional discussion.)
The on-shift administrative burden of the Shift Supervisors has, however, 'been greatly alleviated by the addition of administrative technicians.
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Activities associated with the Performance Enhancement Program (PEP) were closely monitored. The PEP, which was confirmed by an NRC Order dated July 13,
- 1984, is intended to address NRC concerns, improve regulator,s compliance and implement regulatory corrective actions, and is scheduled to continue into 1987.
The PEP has coordinated improvements in the following areas:
organizational structure and personnel, Quality Assurance (QA) program, upgrade of the Technical Specifications (TS), establish-ment of safety engineering groups, allocation of additional resources and upgrade of facilities, operations enhancement, procedures upgrade. improvement of the plant configuration control program, and training and improvements in maintenance management.
A Program for Improved Operation (PIO) was added to the PEP by a Confirmation of Concurrence letter on October 11,
- 1984, and includes reviewing the Final Safety Analysis Report (FSAR) to assure plant operation within the safety analysis, identification and correction of surveillance program deficiencies, and increased management awareness and overview of operations.
Improvements under the PEP /PIO are discussed in this and other functional are.a analyses, as appropriate.
I In general, the implementation of the PEP /PIO has shown successes in that adequate corporate attention and resources have been focused on identified problem areas.
Adherence to established schedules and regional briefings have been satisfactory in most areas.
Upper management's commitment to excellence is apparent not only in the Turkey Point PEP but also in other corporate quality improvement programs.
Licensee management has continued to implement and to support PEP and has expanded the program to include areas not originally addressed.
Of the original 190 tasks,156 were completed prior to March 1986. Approximately 148 new tasks were added in January 1996 to reconstitute selected system design bases, improve maintenance and enhance design control.
On-site managenent involvement and control has been improved by modifying the Nuclear Energy Department organization.
The Site Vice President has assumed overall management responsibility for the nuclear facility.
This has allowed better control and allocation of on-site resources and has improved the control of construction activities, especially during the on going fire protection modifications.
Corporate e",ineering has become more responsive to the plant since the addition of on-site engineerirg representatives, in February 1986, a Site Engineering Manager (SEM)hposition was established at the Turkey Point Site.
This enhanced engineering function should provide faster resolution of mai'ntenance and
mw-10 engineering issues (as discussed later in the Maintenance Analysis) and have a concurrent positive impact on operaticns. A Safety Engineering Group -(SEG), which reports - to the Site Vice President, was also established to provide an overview of nuclear safety issues. Duties include procedure reviews, system walkdowns and review of operating and 'maintenancei practices.
Their expertise was utilized in an initial review and verification of system design bases and will be utilized to review the completed _
design basis documents.
The thrust of the QA program was changed to be more operationally oriented, additional personnel have been added to the staffs and training has been and is being provided.
Some personnel are receiving operations training similar to that of licensed operators. A period of continuous on-shif t QA coverage early in the SALP period helped improve licensed operator procedural compliance.
The existing TS are being modified to make the format and contents more explicit and consistent with Standard Technical Specifica-tions (STS).
The submittal is now scheduled for September 1986.
Reviews of the TS and FSAR were performed to identify. systems and components which were not receiving comprehensive operability testing.
Numerous discrepancies were. identified and "are being corrected. The results of these reviews are being included in the TS rewrite and in the surveillance program.
The licensee is further pursuing retrieval of design basis documents to assist in the correction of potential discrepancies.
The improvements to the site facilities include new buildings for health physics, admini stra tion, training and the simulator, and maintenance.
The progress on the buildings has been on schedule and the evident commitment to upg'rade the facilities and the expenditure of funds has aidsd plant staff morale. Consolidation of the nuclear plant staff should improve management effectiveness and overall efficiency.
The plant ~ specific simulator is expected to enhance operator training.
The health physics and administra-tion buildings are occupied and the improvements in communications and morale are impressive.
Operations improvements have been made in several areas. A valve tagging program has greatly reduced those va'ves in safety-related systems which were not labeled.
A program exists to replace aluminum tags with larger, more legible, fiberglass, color-coded tags. An equipment stenciling project has improved. component and area identification.
Major components, systemsg rooms and s
buildings are clearly marked.
Separation of Unit 3 and 4 equip-ment is emphasized by color-coding, with tan representing Unit 3, blue representing Unit 4, and orange representing common equipment.
1 m
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' Operations planning and integrated facility operation have been improved by implementation of a morning status meeting chaired by the Plant Supervisor - Nuclear (PSN).
The meeting is attended by all staff disciplines and provides an excellent forum for identifying potential conflicts between scheduled evolutions. The appointment of an-Operations / Maintenance Coordinator, who is responsible for integrating the activities of the two. departments, his been of particular benefit.
Ccmmunication between the two i
departments has improved dramatically.
Shift transition and information exchange has improved and is effective.
During the shift transition, control room access is limited to essential operations personnel.
Shift turnovers are formally conducted utilizing checklists and written status summaries.
The Shift Supervisor conducts a briefing of the relieving crew to maximize awareness of evolutions scheduled during the shift.
Cuntrol Room Operator awareness of alarms, annunciators and equipment discrepancies has improved and is satisfactory. Work orders are promptly generated for any equip-ment failure in the control room.
The status of the Plant Wor,k Order (PWO) backlog is discussed in the maintenance analysis. a major improvement has occurred in the identification of equipment malfunctions by plant personnel as they perform their routine duties.
Control room demeanor was satisfactory.
The relatively small, dual unit control room is susceptible to crowding and across-room discussions.
However, the Shift Supervisors actively maintain decorum and minimize visits by nonessential personnel during plant evolutions.
Each watchstander is readily identified by a posted nameplate at his duty location.
Continued management emphasis on housekeeping has improved plant cleanliness; housekeeping problems were uncommon, and general area cleanliness is fully satisfactory.
Work sites emphasize partial cleanup as the repair ef fort progresses, thereby minimizing the need for large-scale, post-maintenance cleanup.
Improved cleanliness in the auxiliary feedwater pump area, the Unit 4 containment, the residual heat removal pump area and the auxiliary building have been particularly noteworthy.
The license has also initiated a progra:a to reduce the amount of floor space which is radiologically contaminated thereby enhancing the ease of operations.
Significant progress haf been made in reducing contaminated floor space in the radiological waste building, the auxiliary building, the Unit 4 containment building, and the spent fuel storage area.
(This topic is further discussed in the Radiological Controls analysis.)
{
e 7
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12 Fourteen violations were identified:
a.
Severity Level III violation (with a S100,000 civil penalty) for failure to operate the spent fuel pool cooling system as described in the Final Safety Analysis Report and not performing the requisite safety evaluation per 10 CFR 50.59.
(85-23) b.
Severity Level IV violation for failure to maintain the minimum degree of redundancy for the overpower and over-temperature delta-T protection circuits. (250/84-39) c.
Severity Level IV violation for failure of an off normal operating procedure (4-0NDP-003.6) to address all failures which could occur when vital instrument panel 4P06 was lost.
(85-20) d.
Severity Level IV violation for failure to perform a Unit 3 accumulator - boron concentration analysis prior to heatup above 200 degrees F, contrary to the TS.
(250/85-24) i e.
Severity Level IV violation for three examples of failure to follow procedures -(independent verification prior to RHR periodic
- test, instrument air dryer operation, use of temporary system alterations).
(85-30) f.
Severity level IV violation for taking a Unit 3 source range nuclear instrument out of service without placing the level trip switch in bypass, and for failure to establish the i r,i ti al conditions for a feedwater pump start per procedure 3-0P-074.
(250/85-42) g.
Severity Level IV violation for procedural inadequacies allowing heatup and pressurization of the RCS without the cold leg accumulators in service and EDG maintenance without restoration of the normal valve lineup.
(85-44) h.
Severity Level IV violation for failure to comply with the AFW Technical Specification 3.8.4.B.
(251/84-40) 1.
Severity Level IV violation for failure to comply with TS 3.5 by manually blocking the high steam flow safety injection signal when average coolant temperature was above 543 degrees F.
(251/85-24) j.
Severity Level IV violation for failure to comply with TS 3.3.3, in that a Unit 4 steam generator blow @wn isolation valve was made incapable of automatic closure by an inappro-priate temporary system alteration.
(251/85-307 l
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k.
Severity Level IV violation for failure to meet the TS operability requirements for the EDGs. (85-13) 1.
Severity Level IV violation for three examples of failure to properly establish and implement procedures.
(86-10) 4 m.
Severity Level IV violation for two-examples of failure to properly implement procedures.
(250/86-17) n.
Severity Level V violation for failure to properly implement a
Preoperational Procedure 0800.55, Diesel Generator A Breaker 4AA20 Control Rerouted Cable Preoperational Test.
(85-20)
Violation (c) listed in the Maintenance analysis also cited a failure to establish abnormal operating procedures for a loss of the 4A motor control center.
Violation (d) listed in the Maintenance analysis included a i
failure to properly secure the "A"
and "C". AFW pumps following operation.
This failure to follow procedure resulted in the i
subsequent mechanical overspeed of both punps when called upon t o operate.
J 2.
Conclusion Category:
3 4
Trend:
Improving 3.
Board Recommendations The Board recognized the fact that licensee management has expended significant effort to improve performance in the operations area.
B.
Radiological Controls 3
1.
Analysis During the assessment period, inspections were conducted by the resident and regional inspection staffs. The regional inspection effort included three routine radiological controls inspections and one reactive inspection involving
- a potential overexposure incident.
1 During the assessment period, the licensee's health physics staffing level appeared to be adequate and radiatiEn protection staff turnover was generally low.
Contract health physics technicians were used to supplement normal health ph/ sics staffing levels which permitted the licensee to provide adequate health physic coverage for routine and outage operations.
, > - -, - ~ - - -
e
,___n
14 Facility management support and involvement in the radiation protection program appeared adequate. Quality assurance audits of the radiation protection program appeared to be adequate in scope, but lacking in depth, possibly due to the minimal health physics experience of the quality assurance auditors. Licensee management has committed to provide additional health physics training for the quality assurance personnel who perform audits of the radiation protection program. The corporate health physics staff also performs audits of the plant's radiation protection programs.
Due to corporate office concerns, the licensee is evaluating the effectiveness of the corporate health physics group's audits of the site's radiation protection program.
Guidance provided by the corporate health physics group to the licensee's two sites was inconsistent in that it recommended the implementation of an alpha ' radioactivity survey program at the St. Lucie facility, but did not evaluate the need for a similar program at the Turkey Point plant.
IE Inspection Report Number 50-250, 251/86-12 identified the presence of measurable quantities
.of alpha emitting radionuclides in the Unit 4 containment.
Tbe licensee needs to consider applying program changes in this area to both its sites.
The licensee's responsiveness to NRC initiatives was generally adequate during this assessment period. Improvements were made or planned for NRC identified weaknesses concerning the alpha survey program and the internal exposure evaluation program.
In the area of radiological measurements, the licensee partici-pated in the NRC's spiked sample program. The licensee's results were in agreement with known concentrations of radioisotopes.
The licensee submitted the required effluent and radiological environmental reports.
There was one unplanned gaseous release from the chemical and volume control system during the report period.
The release was evaluated and it was determined that the maximum permissible concentration (MPC) limits for the site i
boundary had not been exceeded.
There were no unplanned liquid releases during the evaluation period.
Releases of liquid and gaseous effluents were lower than Regional averages and were within the prescribed limits of the Technical Specifications.
3,120 curies (Ci) of fission and activation gases and 0.015 Ci of iodine-131 were discharged to the atmosphere in gaseous effluents from both units in 1985.
The Region II averages for a two-unit site (based on 14 operating PWRs) were 13,140 Ci and 0.30 C1, respectively.
Liquid effluents contained 0.90 Ci of mixed fission and activation products and 385 Ci of tritium. The 1985 Region II averages were 1.9 Ci and 760 Ci, respectively.
i l
l
15 Offsite doses calculated for liquid and gaseous effluents were within 10 CFR Part 20 and 10 CFR Part 50, Appendix I, guidelines.
For 1985 releases, the maximum calculated doses to a member of the public were 0.0082 mrem from liquid effluents and 0.0796 mrad combined gamma and beta radiation dose from gaseous ef fluents.
The maximum calculated dose from gaseous iodine-131 releases, to the thyroid of a hypothetical infant was 0.25 mrem..These calculated doses represented 0.27 percent, 0.51 percent, and 1.6 percent of the prescribed limits for liquid and gaseous releases.
In the area of plant chemistry, the licensee experienced signiff-cant difficulty in controlling the secondary water chemistry of both units, and, to a lesser extent, the primary chemistry of Unit 3.
These difficulties were attributed to unstable plant operations, condenser tube leaks, turbine boot (vacuum) leaks and problems with the water treatment plant. The licensee has adopted the Steam Generator Owners' Group guidelines for secondary water chemistry control and was striving to develop the capabilities to implement the stringent requirements of the program. Significant progress was being made to upgrade the chemistry staff, however, the secondary laboratory and sampling facilities remais inadequate.
The laboratory is very small and the sampl i n'g facility is exposed to the environment in an open panel on the mezzanine deck.
Collective personnel exposure during 1985 was 600 inan-rem per reactor.
This was above the average (425 man-rem) for U. S.
pressurized water reactors (PWRs),
but is not considered significant in light of the extensive outage activity during this period.
During 1985, the licensee disposed of 10,220 cubic feet (ft ) of 3
solid radioactive waste containing approximately 748 curies of activity per reactor.
This was less than the average for U. S.
3 PWRs of 11,650 f t.
The radwaste goal for 1986 is 9,000 ft3 per reactor.
In 1986, the licensee began evaluating the effectiveness of the contamination control program by tracking the total area of the plant which is controlled because of radioactive contamination.
At that time, 28,727 square feet (44 percent of the plant) were being controlled. Although, as noted in the operations analysis, there appears to be progress in reducing some contaminated areas, it is too early to judge the overall ef-*:ctiveness of the program.
One significant enforcement issue during the assessment period involved the unauthorized entry of an Instrument and Control Technician into the traversing incore probe (TIP) I drive area.
Although the exposure received by the individual durjng the entry did not exceed the regulatory limit, a substantial potential for overexposure did exist.
Several procedural violations occurred before and during the worker's entry.
The violations included
16 failure to notify health physics persorr.el prior to operation of the incore detectors, performing work outside the scope of the Plant Work Order, failure to have two persons,present during the entry, and failure to keep the worker's exposure within the limits established by the Radiation Work Permit for the job.
Further-more, the worker's foreman failed to provide adequate instructions on the Plant Work Order for the maintenance tasks to be performed by the worker.
The worker also received inadequate training in the use of the radiation survey. instrument issued to him to control his exposure while inside the containment.
Consequently, he failed to recognize that the instrument malfunctioned when the radiation levels exceeded the upper limits of the instrument.
The licensee has responded to this violation and requested mitigation of both the severity level and the civil penalty; the NRC is evaluating the licensees response and request.
Three violations were identified:
a.
Proposed Severity Level III violation and $50,000 c i v.i l penalty for failure to adequately train personnel and failufe to follow procedures.
(86-04)
The licensee's request for mitigation is under review.
b.
Severity Level IV violation for shipment of a low specific activity burial box that failed to meet the strong, tight container requirements of 49 CFR 173.425(b).
(85-17) c.
Severity Level V violation for failure to perform a daily energy calibration on the health physics Germanium-lithium spectrometer (84-40/41).
Violation (b) listed in the %intenance Analysis also cited two examples of failures to comply with the protective clothing requirements of a Radiation Work Permit.
2.
Conclusion Category:
2 3.
Board Recommendations No changes in the NRC's inspection resources are recommended.
C.
Maintenance 1.
Analysis During the evaluation period, inspections were pefformed by the resident, regional and headquarters staffs.
Several maintenance-related problem areas representing fundamental deficiencies and
17 oversights were identified.
The areas of concern are related in that they require increased supervisory involvement in the operation and maintenance of the plant. A concern exists that the Turkey Point maintenance program may have been deficient to the extent that necessary plant repairs and enhancements were excessively delayed or omitted. This attitude was contrary to the
" preventive maintenance" philosophy generally credited with reducing significant maintenance-related events.
As mentioned in the previous SALP, management's approach to the resolution of technical issues has remained a concern.
Corrective i
actions were often not timely and failed to identi fy the root causes of problems. Some maintenance problems have existed for a long period of time.
While the problems may not have been ignored, the rate of progress toward resolution was excessively slow.
Maintenance repairs were occasionally terminated prior to determining the root cause problems.
There was a tendency to accept the first plausible explanation for a problem and a f
hesitancy to perform the type of detailed testing necessary to differentiate between two equally valid hypotheses.
Speci fi.c T
examples are itemized below.
During June and July
- 1985, the "B"
AFW pump tripped repeatedly on electronic overspeed because of an incorrectly adjusted trip setpoint.
Failure to resolve the root cause of the June overspeed event directly contributed to a repeat trip in July. Even following the July trip, the licensee did not seriously consider overspeed testing until NRC Region II management requested that action be taken.
During July
- 1985, numerous operating problems were experienced with the AFW flow control valves and main feedwater bypass valves. While repairing the valves, water was discovered in the instrument air lines for the valve actuators. The air lines were blown down until no additional water was observed, but the source of the water was not addressed.
In May 1984, the licensee first began to experience instru-ment inverter failures, with at least 14 separate losses occurring through August 1985.
The licensee initially maintained that the complete inverter changeout could not be accomplished until March 1986.
ffter additional inverter failures
- occurred, the licensee initiated a changeout schedule that replaced all inverters five months. ahead of the previous "best possible" schedule.
To the licnesee's credit the expedited inverter replacement was well c8ntrolled and was completed without incident while the units were operating.
18 The AFW pump turbine steam admission valves have been leaking excessively for years.
On one occasion, the pumps were improperly secured because the shutdown procedure was more complex than would otherwise be necessary to compensate for the leaking steam admission valves. This leakage also caused some AFW system steam admission stop check valves to fail in December 1985.
Repairs were made without identifying the root cause of the failures.
Consequently, corrective action was inadequate and some stop check valves failed again in January
- 1986, forcing a
reactor shutdown.
A regional inspection revealed inadequacies in management's involvement in assuring quality and its approach to the resolution of technical issues from a safety standpoint.
A surveillance (radiography) program had been initiated to detect additional stop check valve failures.
However, poor understanding of the procedures and policies established to ensure that proper actions were taken resulted in inadequate management involve-ment in evaluating the radiographs.
Management remained unaware of additional valve failures until they were identified by the NRC inspector.
The licensee's failure to adequately evaluate the operability of the AFW system and locate parts missing from the failed check valves was included in escalated enforcement action issued subsequent to the SALP period.
AFW system flow was known to oscillate when operated in the automatic mode with control room flow indication shifting rapidly from 0 to 300 gpm. The control room operators had to take manual control of the system shortly after automatic initiation to stabilize control room indications.
This was an APd flow control valve trim problem which existed for several years and was not corrected until March 1986.
The inadequacy of source and intermediate range nuclear instrument maintenance was discussed in the previous SALP.
Those instruments still suffer from inadequate maintenance.
It is not uncommon for at least one instrument to be out of service on each unit, and at times both source range instru-ments on a single unit have been inoperable at the same time.
The area radiation monitoring system and process radiation monitoring system frequently have numerous inoperable channels.
Cooling water piping to the high head safety injectic.; pumps was known to be improperly installed and corr.ective action was delayed until the significance of the di$crepancy was identified by the NRC.
Enforcement action is pending.
19 Many additional maintenance problems had not been expeditiously addressed as evidenced by the large accumulation of incomplete Plant Work Orders (PW0s) pri>r to 1986. The number of active PW0s has been reduced from almost 900 in the fall of 1985 to approxi-mately 450.in June 1986.
The goal is to reduce the outstanding PW0s to no more than 250, and to begin work on each PWO within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after issuing the maintenance request.
The staffing of the Maintenance Department is adequate to provide maintenance services during routine plant operation. However, the experience level of the Instrumentation and Control (I&C) tech-nicians is low, and contract I&C technicians have been employed to help reduce the PWO backlog to a more marageable level.
The problem has been acknowledged by the licensee and stems from excessive personnel turnover both through attrition and selection for licensed operator training.
Turnover rates of the mechanical maintenance staff were also high during the fall of 1985.
As mentioned previously, the management staff has, over the past two years, had difficulty enforcing their procedural complianc.e policy.
There have been several failures to comply with Admini'-
strative Procedure (AP) 0190.19,
" Control of Maintenance on Nuclear Safety Related and Fire Protection Systems", and repeated failures to implement AP 0190.10, " Cleaning of Nuclear Safety Related Systems and Components".
There have been two occasions where procedures have failed to prevent electrical connections from being removed and replaced without quality control verifica-tio1s.
In November 1984, an inspector folic up item was created to ascertain whether the licensee's progra1 for verifying the acceptability of hoisting and rigging e;uipment was being adequately implemented.
Since that time, three instances of hoisting and rigging noncompliances have been identified.
Recently, very severe administrative personrel actions have been pursued by the licensee against personnel w o fail to correctly h
implement procedures.
Lack of
- training, inexperienced personnel, and inadequate supervisory involvement also contributed to maintenance-related problems.
In May 1985, a technician pulled a fuse for a circuit other than the one he was assigned to work on. RHR cooling, which was being utilized at the time, was lost for three minutes due to lack of an available flow path.
In June 1955, a Unit 4 shutdown was required because both EDGs were ouf of service.
The problem occurred because Maintenance personnel, using high pressure water, sprayed the motor control certer (MCC) supplying power to "A" EDG auxiliary equipment. The workers were not aware that the MCC was important, so they took little care to prevent water ffrom entering the cabinets.
Recent improvements have been noted n the amount of direct foreman supervision at the job site, which;}should aid in reducing the frequency of maintenance - related problems.
20 The licensee has addressed several problem areas with both short-term and long-term corrective actions in the Instrumentation and Control (I&C), Mechanical and Electrical Maintenance Deparements.
The I&C staff had been increased and two engineers have been added to each department.
A response team concept is being used to evaluate significant equipment issues and plant transients in a effort to enhance root cause identification and corrective actions.
As discussed in the training analysis, maintenance training was suspended for a significant period of time, but in January 1986, training in systems and specfic equipment was resumed.
The Superintendent of Maintenance is effectively utilizing personnel, has established a permanent preventive maintenance staff, and is demanding procedural compliance.
In December
- 1985, following the identification of numerous concerns during an NRC Safety System Functional Inspection, the licensee determined that the PEP should be augmented in the areas of maintenance and design control.
The-maintenance effort addressed augmentation of maintenance procedures, including post-maintenance testing and independent verification; controls over plant work orders; training and experience of maintenante i
personnel; and updating the preventive maintenance program to incorporate predictive maintenance techniques.
A formal maintenance assessment using INP0 guidelines has been initiated.
Long-term corrective action for equipment failures is being pursued by developing an analytically based preventive maintenance (ABPM) program.
The program will cover selected safety-related systems and will take approximately two years to complete. The program will be extensive and has required significant resources, both personnel and monetary, to develop and implement.
The ABPM is designed to develop, through quantitative and qualitative analyses, those preventive maintenance (PM) tasks necessary to j
maintain component operability.
Specific procedures for the implementation of the ABPM are under development on a per-system 2
basis.
Procedures for PM of the auxiliary feedwater system were approved in June 1986.
A program was developed in late 1985 to enhance source range nuclear instrument (SRNI) operability through the combined efforts of management, a quality improvement team and manufacturer's technical representatives. Enhanced system operability has yet to be
- achieved, but necessary improvements, both physical and procedural, have been identified.
Management involvement in the resolution of maintenance issues improved significantly in February 1986 as a resultf of establish-ing a position of Site Engineering Manager (SEp).
The SEM supervises both construction and plant staff engineering activities. Strengthening the engineering supervisory function at i
1
..,------ _ _ - -------~- - -, -
21 c
the-plant instead of the corporate engineering office should provide faster resolution of engineering and maintenance issues.
In early 1986 a formalized review process was developed to facilitate the timely resolution of technical issues.
The numerous stages of engineering review, as well as greatly improved j
mechanisms for feedback and
- tracking, should preclude-the recurrence of maintenance and engineering problems similar to those experienced in 1985.
The licensee has expanded the PUP to include approximately 250 corrective maintenance procedures and 200 maintenance surveillance procedures.
This should correct the observed weaknesses in present procedures and preclude excessive reliance on " skill of the trade."
The licensee is in the process of implementing the Nuclear job i-Planning System (NJPS) as a work control system. The pilot system j
is operational and is being used for the preparation, processing 2
and tracking of Plant Work Orders. A formal implementation of the system will be completed during early 1938 and will satisfy ttje latest industry initiatives in the area of work planning and control.
The NJPS is being used to develop readily retrievable j
maintenance history records.
Approximately 90's of all new work i
orders are being processed by the NJPS system. Large scale use of 4
the pilot program is promoting the greath of an equipment data base which will be used to provide search and retrieval of equip-ment. hi story, trend analysis, cause analysis, tracking of long lead-time spare parts and surveillance test scheduling.
The initial results of the pilot program, which was begun in early 1986, are very favorable.
Tne licensee believes that additional uses for the system will became apparent.
Eight violations were ident'ified:
a.
Severity Level IV violation for failure to establish a procedure for instillation of a Unit 3 power range nuclear instrument drawer. (250/84-39) b.
Severity Level "olation for failure to implement procedures to protect safety-related components from contaminants auring maintenance and perform adequate housekeeping after maintenance (85-13). This violation also contained examples of failure to hmply with Radiation Work Permit requirements as discussed in the Radiological Controls
- analysis, c.
Severity Level IV violation for three examples f failure to properly establish / implement maintenance procedWres. (85-22)
Three additional procedural deficiencies contained in this violation are discussed in the Operations, Surveillance, and Outage analyses.
22 d.
Severity Level IV violation for three examples of failure to establish / implement adequate maintenance procedures (250/85-26).
This violation also contained an example of failure to properly secure the AFW pumps after operation as discussed in the Operations analysis, e.
. Severity Level IV violation for operating clearance tagged valves during maintenance without obtaining temporary lift authorization. (86-05) f.
Severity Level IV violation.for failure to implement adequate corrective action for AFW pump turbine electronic overspeed trips.
(85-30) g.
Severity Level IV violation for failure to implement an adequate corrective action program thereby incurring repetitive AFW flow control valve failures due to water in the instrument air lines.
(85-26) h.
Severity Level V violation for performing EDG maintenance reing a PWO which had not received the required QC review ahd approval. (85-02) 2.
Conclusion Category:
3 Trend:
Improving 3.
Eoard Recommendation The board recognized that the licensee management has expended a large effort to improve performance in the maintenance area.
D.
Surveillance 1.
Analysis During this evaluation period, inspections were performed by the resident and regional inspection staffs.
The regional inspection effort included the surveillance testing and calibration control program and the snubber surveillance program.
The quality of the surveillance area is not uniform.
There is a fairly large body of surveillance activities that appear to be handled well but there are important exceptions with a severe impact. During the latter part of this SALP period the licensee had taken bold wide-ranging steps to restore unifgrm quality to this area but it is too early to reach conclusions on the final results.
4 23 Surveillance scheduling and implementing procedures were generally effective. Several Technical Specification surveillances, a small fraction of the surveillance actions taken, were not implemented within the required periodicities.
The area affected included tritium sampling, gaseous effluent monitor sampling, snubber visual inspections, boron concentration, area radiation monitoring and fire protection systems.
The discrepancies were identified, reported and promptly corrected by the licensee.
These missed surveillances were not representative of a
programmatic deficiency.
Implementation of surveillance procedures by the I&C Department was very effective.
A reader worker routine was effectively utilized to control and verify implementation of procedural steps.
- Foremen, supervising the performance of safety-related surveillances in the control room, were effective in minimizing personnel errors and promoting quality work.
The snubber surveillance procedures were well-definad and stated for control of the snubber surveillance program. Decision makiqg was usually at a level that ensured adequate management reviek.
Records were complete, well maintained, legible and retrievable.
The resolution of technical snubber issues, such as functional test failures, was conservative, timely, technically sound and thorough.
Management control in assuring quality in the areas of Technical Specification surveillance remains a weakness, as in the last SALP evaluation.
Violations (b), (e), (f), (h), (k) and (1) occurred because surveillance tests did not address or evaluate all system capabilities important to the determination of Technical Specification Operability. The important systems affected include auxiliary feedwater (two examples), power range nuclear instrumen-tation, intake cooling water, low pressure accumulators and matn steam isolation valves.
Additionally, violation (a) in the fire 4
protection analysis documents the failure to test all required fire protection valves.
Inadequate testing of the auxiliary feedwater nitrogen system and the main steam isolation valves prevented the identification of j
significant systems deficiencies as describec below.
Prior to September 1985, the bott *ed nitrogen system was not periodically tested during auxiliary feedwater system operation (violation e). Therefore, the nitrogen consumption rate was not accurately known. The rate was use' in selecting the nitrogen bottle low pressure warning set /oint.
Subse-quent surveillance testing revealed that the ac,tual nitrogen pressure warning alarms were set so low that nitrogen depletion could have occurred prior to bottle replacement.
Corrective actions were promptly implemented to correct the alarm setpoints and schedule system testing.
i
24 Prior to January 1985, the main steam isolation valves were l
not periodically tested to verify that the valves failed closed on loss of instrument air pressure (violation 1).
Subsequent surveillance testing with the instrument air system isolated revealed that the main steam isolation valves would not remain closed as ' required for some accident scenarios.
The licensee determined that this situation created the possibility of a loss of the secondary heat sink j
and corrective actions were implemented.
Between August and November 1985, the licensee failed to conduct adequate monthly surveillance testing on the 125 volt station batteries as required by Technical Specifications.
Subsequent to the SALP period, escalated enforcement action was proposed for this violation.
The licensee has implemented improved battery surveillance procedures.
The approach to the resolution of technical surveillance issues from a safety standpoint was not always thorough or timely, particularly with respect to auxiliary feedwater system testing as described below.
A nitrogen system surveillance procedure, developed as a corrective action for violation (e), did not verify that the nitrogen system would function properly during actual auxiliary feedwater system operation.
A fully adequate nitrogen system surveillance procedure was not implemented until eight months after issuance of the original violation.
Failure to verify that cpen signals initiated at the auxiliary feedwater steam supply valves were received at each flow control valve resulted in violation (b).
A modified surveillance procedure improved, but did not completely correct the discrepancy.
A fully adequate surveillance procedure was not implemented until ten months after the initial violation was issued.
l l
There have been two instances when auxiliary feedwater system surveillance tests were considered satisfactory even though l
test requirements were not fully met (violations c and j).
f The discrepancies and the ineffective corrective actions initially l
implemented for violations (a) and (b) indicated that additional i
management involvement in the resolution of technical issues was warranted.
l The licensee has taken ef fective steps to preclude he occurrence l
of additional surveillance violations. A wide-rangigg program has been established to reconstitute the design basis for safety-related systems. The design basis documents will specify required 1
25 system capabilities facilitating operability determinations.
We believe the surveillance testing necessary to determine system operability will be more clearly' discernable.
Design basis documents are scheduled to be completed by November.1986.
An additional enhancement-in resolving technical surveillance issues is made possible by the consolidation of construction and plant staff engineering activities under a single Site Engineering Manager.
The centralization of the site engineering programs should improve communications and facilitate ' responsiveness to technical issues.
The Site Engineering Manager reports directly to the Site Vice President.
Creation of the position occurred in
-February 1986.
Consequently, the full program potential was not realized prior to the end of this SALP evaluation.
Twelve violations were identified:
a.
Severity Level IV violation for failure to document or evaluate protection channel periodic test results.
(84-35/36) b.
Severity Level IV violation for failure to perform required visual observations to verify proper AWF flow control valve operation.
(84-35/36) c.
Severity Level IV violation for considering the AWF system satisfactorily tested when the pump differential pressure cell was not operating properly. (84-39/40) d.
Severity Level IV violation for exceeding the allowed EBG voltage of 4784 volts during a surveillance.
(85-02)
The licensee denied this violation and the matter is being further reviewed by the NRC.
e.
Severity Level IV violation for failure to test all AWF system components (i.E., Nitrogen System).
(85-02) f.
Severity Level IV violation for an inadequate power range nuclear instrument calibration procedure.
(85-06) 9 Severity Level IV violation for an inadequate containment spray system surveillance procedure,.
(85-08) h.
Severity Level IV violation for failure to perform visual inspections for evidence of structural distress or corrosion during ICW inservice testing.
(85-13) l 1.
Severity Level IV violation for failure tp follow the procedure for calculation of Unit 3 shutdown: bank "A"
rod drop time measurements.
(250/85-24)
26 j.
Severity Level IV violation for making an improper temporary change to an AFW operability verification procedure.
(250/85-26) k.
Severity Level IV violation for failure to test fail-safe valves in accordance with the ASME Code (85-05).
Violation (c) listed in the Maintenance Analysis cited a failure
'to perform a calorimetric instrumentation calibration at the required frequency.
2.
Conclusion Category: 2 3.
Board Recommendations None E.
. Fire Protection 1.
Analysis During this assessment period, inspections of the licensee's fire protection and fire prevention program were conducted by the regional and resident inspection staffs.
In general, the management involvement and control in assuring quality in the fire protection program were adequate as evidenced by the issuance and implementation of fire protection procedures that meet the NRC requirements and guidelines.
The licensee's approach to resolution of technical fire protection issues indicated an apparent understanding of the
- issues, and was generally sound and timely.
The licensee's responses to NRC initiatives were generally timely and thorough.
Fire protection related violations periodicelly o: curred but did not indicate a programmatic breakdown. Corrective action was normally timely and effective. Licensee identified fire protection related events or discrepancies were properly analyzed, promptly reported and effectively corrected.
Fire protection staff positions are identified, authorities and responsibilities are clearly defined, and personnel appear qualified for their assigned duties.
However, the Site Fire Protection Supervisor's position was vacant for an extended period of time.
The licensee has issued procedures for the administ ative control of fire hazards within the plant, surveillance and gaintenance cf the fire protection systems and equipment, and organization and training of a plant fire brigade.
These procedures were reviewed and found to meet the NRC requirements and guidelines.
27 The staff. inspections reviewed the licensee's implementation of the fire protection and administrative controls.
General house-keeping and control of combustible and flammable materials were satisfactory.
The fire protection extinguishing
- systems, detection systems, fire barriers and barrier penetrations were found to be in service.
Surveillance inspections, tests and maintenance of the fire protection systems and features were generally satisfactory.
A citation was issued, however, for failure to perform the monthly fire protection surveillance in September 1985.
Organizatior and staffing of the plant fire brigade met the NRC guidelines.
The fire brigade training program is adequately defined and implemented. The training and drills for the brigade members generally met the frequency specified by the procedures I
and the NRC guidelines. However, a violation was issued when the I
time between a number of shift drills exceeded the maximum time of three months permitted by the licensee's procedures.
The annual fire protection / prevention audit, the 24 month QA fir.e protection program audit by off-site organizations and trie triennial audit by an outside fire protection organization required by the Technical Specifications were reviewed.
These audits were conducted within the specified frequency and appeared to cover all the essential elements of the fire protection program except that the annual fire protection and loss prevention inspection and audit by qualified fire protection personnel was not conducted in 1985 (violation b). The licensee has implemented corrective actions for discrepancies identified by the audits.
The licensee identified, analy:ed and reported fire prevention events and discrepancies as required by the license conditions and Technical Specifications.
These reports were reviewed and found to be satisfactory.
Four violations were identified:
a.
Severity Level IV violation for failure to cycle fire suppression system valves as required or verify valve positions.
(85-06) b.
Severity Level V violation for failure
+.o conduct thc annual independent fire protection and 'oss prevention audit and inspection by qualified fire protection personnel in 1985 as required by the Technical Specifications.
(86-09) konduct fire c.
Seve ri ty Level V violation for failure to brigade drills within the specified three months time interval between drills for all shift brigades a's required by the licensee's implementing procedures (86-09)
28 d.
Severity Level V violation involving the failure to conduct the monthly surveillance for the fire protection equipment in September 1985 as required by the Technical Specifications.
(86-09) 2.
Conclusion Category: 2 3.
Board Recommendations No change in the NRC's inspection resources were recommended.
F.
Analysis During the assessment period, inspections were performed by the regional and resident inspection staf f s.
These included observa-tion of two annual emergency preparedness exercises, and two routine inspections.
The routine inspections and exercise evaluations disclosed that the on-site emergency organization was capable of effectively managing simulated emergencies.
Adequate staffing of the emergency response facilities was demonstrated. Corporate manage-ment demonstrated a
commitment to maintaining an effective emergency res;]nse program.
Consistent with this commitment corporate management was directly involved in the annual exercises and critiques.
Personnel assigned to the emergency organizations were cognizant of their emergency response roles, and were adequately trained in required areas of emergency response.
The one area of emergency preparedness that has detracted from the otherwise exemplary performance is the condition of the announcing system. Several high noise areas do not have good audibility and two buildings were placed in service without the system installed at the time.
Though an improved surveillance and repair program has been implemented, a fully effective system has not resulted.
IE Bulletin 79-18 was not met.
Failures to respond to emergency drills have been caused by the mediocre announcing system.
The Emergency Response Organization's management and resolution of the postulated accident during the most recent full scale exercise demonstrated significantly improved emergency preparedness training.
Prompt activation and management ofThe}he emergency response facilities was particularly notable.
transfer of emergency management from the Technical Support Cepter (TSC) to the Emergency Operations Facility (ECF) was decisive and prompt.
o 29 The licensee effectively used emergency action level matrices in promptly declaring each emergency classification.
Protective action decision making was effectively implemented throughout the exercise.
State and local government representatives assigned to the ' EOF were consistently factored into the off-site protective action decision making process. Consistent and. effective communi-cations _ with off-site agencies were maintained throughout the exercise.
Additionally, public information was efficiently disseminated from the Emergency News Center.
During emergency. preparedness drills. and exercises the licensee identified weaknesses and required improvements; the NRC did not identi fy any additional weaknesses.
The licensee has also been responsive to NRC initiatives regarding correction of weaknesses and program improvements identified during routine inspections, drills, and exercises.
The following essential elements for emergency response were determined to be effectively implemented:
emergency classifica-tion; notification and communications; public information; shi f.t staffing and augmentation; emergency preparedness training; dofe projection and assessment; emergency worker protection; post accident measurements and instrumentation; changes to the emergency preparedness program; annual quality assurance audits of the plant and corporate emergency planning programs; and prompt revision of the Emergency Plan and procedures indicated by such audits.
The exercises demonstrated that the plan and procedures could be effectively implemented in the areas of communications, accident assessment, exposure control, and recovery and reentry.
No violations or deviations were issued for any actions during the
/
appraisal period.
2.
Conclusion Category:
1 3.
Board Recommendations No changes to the NRC's inspection resources was recommended.
G.
Security and Safeguards e
1.
Analysis Inspections were performed by the resident and regional staffs.
f During the previous SALP period a programmatic weakness was identified in the routine maintenance of the securit/ system. The licensee has addressed this weakness by expending additional
f 30
. resources in an effort to repair and maintain aging security system components.
These resources include several full-time employees dedicated to the upkeep of electronic systems and additional security measures required to compensate for failed mechanical and hardware components.
A Severity Level III violation issued during this SALP period is attributable to the aging equipment and the resulting need for compensatory measures.
Additionally, during this SALP period several Safeguards Event Reports were received from the licensee which reflected a repetitious failure of security hardware.
During the last inspection of this SALP period it was noted that the licensee's efforts in maintaining the security-related equipment in working order have been successful. The licensee now needs to address the reliability of its current equipment, especially in light of the proposed expansion of the facility's protected area perimeter.
There was evidence of management involvement and control of the security program.
Responses regarding safeguards matters were generally technically sound and consistent, demonstrating the existence of policies and procedures for control of ' security-related activities. Safeguards Event Reports submitted during tRe SALP period were timely and acc. urate.
The security staff is considered to be adequate to implement the physical protection program.
The guard force is also judged to be adequately trained and qualified.
A strength was identified in the licensee's security program in that the corporate quality assurance audit function is a continual effort throughout the year.
The licensee accomplishe' this continuous audit by using an independent auditor who is granted permanent unescorted vital area access and performs security audits while conducting various other ongoing audits.
Records reflect that six audit reports are generated annually and that an average audit period lasts several weeks.
Additionally, the security contractor rotates the Security Shift Supervisors through a three-month assignment as the Quality Assurance Captain.
This results in an experienced and independent audit of random shifts to ensure regulatory compliance and procedural adherence.
The security contractor also has a Compliance Records Clerk who verifies daily documentation of all required security duties and responsibilities.
Two violations were identified:
a.
Severity Level III violation for failure to take effective and timely compensatory measures during a computer outage.
(85-21)
[
b.
Severity Level IV violation for failure to positively control access to a vital area (inadequate compensatory measures).
(84-38/39)
4 31 2.
Conclusion Category: 2 3.
Board Recommendations No changes in the NRC's inspection resources were recommended.
H.
Outages 1.
Analysis During this evaluation period, inspections of refueling activi-i ties, outage management, major plant modifications and post-outage startup testing were performed by the regional and resident inspection staffs.
The design change program, inservice inspec-tion and test (ISI/IST) programs, measuring and test equipment (M&TE) program, and containment integrated leaks rate testing were also reviewed by the regional staff.
Staffing, throughout refueling, met or exceeded the Technical Specification (TS) requirements.
The training and qualification program contributes to an adequate understanding of the refueling process and adherence to procedures with a minimal number of personnel errors.
Defueling was performed in accordance with procedures; defueling operations were witnessed from the control room, refueling floor and spent fuel pool area.
In January 1986, during preparations for the Unit 4 defueling, the licensee discovered that the cavity seal ring did not provide a double seal as described in FPL's response to Inspection and Enforcement Bulletin (IEB) 84-03.
This unexpectedly delayed th%
Unit 4 refueling schedule by about ten days while a temporary seal modification was fabricated.
The licensee's initial resoonse to IEB 84-03 described the reactor cavity seal configuration at Turkey Point and concluded that a catastrophic failure was not a credible event. However, it failed to adequately consider all the physical constraints of the seal configuration. After completing additional engineering reviews, FPL decided to install a backup seal for additional leakage protect *on.
A supplemental IEB response was submitted in March 1986 f fe review by the Region 11 staff.
The licensee was responsive to the NRC's request for additional information, and the modified seal design-was found to be acceptable for preventing catastrophic failure. fPL plans to implement a permanent reactor cavity seal modificatibn during the next refueling outage.
.-,.v..-_,_-,...
32 The Unit 4 refueling and Appendix R modification outage was greatly extended when it was discovered that the emergency diesel generators (EDGs) were susceptible to overloading.
The full extent of the overload condition was not identified until Fei ruary 1986, after Unit 4 was shutdown for a scheduled outage.
The licensee determined that continued Unit 3 operation could be justified provided Unit 4 remained in cold shutdown.
Conse-quently, the Unit 4 outage, originally scheduled to end in May 1986, has been extended until August 1986 to allow electrical load modifications which, when complete, will preclude EDG overload even while both units are operating. A number of administrative electrical load controls have also been required on Unit 4 to keen from exceeding the EDG load limit.
These controls were the subject of a Confirmation of Action Letter (CAL 250, 251-86-01) issued on April 2, 1986.
A subsequent regional inspection determined that these administrative controls, as implemented, were not totally effective in ensuring that EDG load limits would not be exceeded.
Subsequent to the SALP period escalated enforcement action was proposed regarding these issues.
One violation (g) was identified during the Unit 3 refueling outage.
It involved failure to control the li_f ting / handling of hafnium burnable poison assemblies in such a manner to provent damage.
The regional inspection staff reviewed the licensee's measuring and test equipment (M&TE) program and found that M&TE activities were procedurally delineated for instrumentation and control (I&C) personnel. The I&C Department has also implemented a comprehen-sive training program. The Electrical Department performs limited M&TE activities; the bulk of this function for the Electrichl Department is performed by off-site contractor services.
One problem area was identified (violation e) relative to instrumen-tation exceeding calibration dates.
The design change and modification program was found to contain numerous problem areas including failures to (1) identify the major off-site organizations participating in the
- program, (2) procedurally delineate activities of the drawing update group (3) procedurally delineate the plant change audit program, and (4) define external organization interfaces.
The licensee had identified these problems during a QA audit and corrective actions were ongoing.
The licensee has recently implemented a program to reconstitute the design basis for selected safety-related systemy. The program will verify system performance and ensure consistency between the new design basis, licensing commitments and analysed and as-built drawings. The new draft design bases for all the selected systems are scheduled for issuance late in 1986. They should enhance the licensee's design change program by improving the licensee's understanding of design requirements.
a
- - - - ~ _
33 Violation'(f) identified several examples where nuclear safety-related system temporary modifications were initiated prior to review by the Plant Nuclear Safety Committee (PNSC).
Violation (c) in the Maintenance analysis section identified an additional example of failure to comply with temporary system alteration procedures.
During the 1985 Unit 3 refueling outage, a Plant Change / Modification (PC/M) involving the installation of environmentally qualified neutron flux detectors was not fully implemented.
Unit 3 was started up before the flux detectors were fully operable as required by a Commission Order.
Escalated enforcement action and a proposed civil penalty were issued af ter the end of the SALP period.
These violations indicate a weakness 1
in management control and involvement in the design change process.
P Management involvement in assuring quality in the areas of ISI*,
IST and IE Bulletins 79-02, 79-14 and 83-06 was generally adequate.
Policies were adequately. stated and understood, decision making was usually at a level that ensured adequate management review,. records were complete, well maintained and available, and procedures and policies were rarely violated. Th'e inspections disclosed 1 weakness, however, in the licensee's
- ~
responsiveness to NRC initiatives.
Deadlines were sometimes missed and extensions were frequently necessary, but not always requested 1
(e.g., IE Bulletin 83-06).
4 Containment integrated leak rate tests on Unit 3 (June 1985) and Unit 4 (March 1986) were witnessed by regional inspectors. Local leak rate test procedures and results were also reviewed.
The inspector noted that the leak rate test program was conducted in"a controlled and acceptable manner but identified some weaknesses i~n the integrated and local leak rate test procedures. However, no test problems were identified as a result of these weaknesses,.
i During the Unit 3 and 4 refueling outages the licensee, together with the reactor vendor (Westinghouse) changed out all 102 control rod guide tube split pins. The decision to replace the split pins was based on Westinghouse concerns that the pins would develop cracks such as were found at other operating reactors.
The replacement was performed completely under water in each unit's refueling cavity.
One cracked pin was found during the replacement.
J FPL originally scheduled 27 days for the Unit 3 split pin j
replacement but the task was completed in 23 days, primarily due a Quality to efficient management and scheduling.
FPL formjd effort and identi fy Improvement Team to critique the Unit 3 additional improvements prior to beginning the Unit,,4 refueling.
l 1
-wy_
-.-. -..,.-. p..,,. _,
,,,...,,..-p.m.
w
-_.,_m_,-..,_,-,w_,-..,m,,,.
.,.,,_,r.,,m~..v_.,_y,.
34 Enhancements recommended by the team included the use of an additional work station to allow alterations to continue without impacting pin installation, an improved method of maintaining water clarity, additional preplanning and preparation of work packages, and methods of reducing radiation exposure.
~
As a result of these efforts, the Unit 4 replacement was completed in only 18 days - without significant complications or difficul-ties.
The use of a second work station has been adopted for future Westinghouse split pin replacements for other utilities.
Total radiation exposure was reduced by 25*; during the Unit 4 replacement.
Seven violations were identified:
a.
Severity Level IV violation for failure to provide acceptance criteria for thread engagement.
(85-09) b.
Severity Level IV violation for failure to include accumulator pressure relief valves in the ASME Section (I pump and valve program.
(85-09) c.
Severity Level IV violation for failure to provide appropriate acceptance criteria for an inservice testing procedure.
(251/86-06)
The licensee has denied this violation and the NRC is evaluating the issue.
d.
Severity Level IV violation for two examples of improperly supported safety class piping.
(86-13) e.
Severity Level IV violation for failure to establish measures to remove uncalibrated M&TE from service.
(84-41/42) f.
Severity Level IV violation for installing numerous temporary nuclear safety-related system modifications prior to Plant Nuclear Safety Committee review.
(85-30) g.
Severity Level IV violation for failure to meet quality standards while lif ting hafnium burnable poison assemblies.
(85-13)
Violation (c) in the Maintenance Analysis se tion identified an additional example of a failure to comply with the temporary system alteration procedure.
An additional apparent Severity Level III viola $ ion, with a proposed $50,000 civil penalty, was issued af ter the closing date of this assessment period.
It involved a failure tp satisfy the
F 35 I'
requirements of a July 15, 1985 Order with regard to the instal-lation of neutron flux detectors under a
Plant Change /.
l Modification.
(250/85-43) 2.
Conclusion Category:
2 3.
Board Recommendations No changes in the NRCs inspection resources were recommended.
I.
Quality Programs and Administrative Controls Affecting Quality 1.
Analysis During this evaluation period, inspections were performed by the resident and regional inspection staffs. The following areas were reviewed by the regional inspection staff during this SALP period:
quality assurance (QA) program; audits; records; document contro};
procurement, receipt, storage and handling of materials; off-site support staff; and the Company Nuclear Review Board.
During 1985 the NRC identified significant weaknesses in the design control program which indicated that the licensee had not exercised adequate control to ensure that changes required as a result of system modifications were appropriately translated into operating procedures, drawings, system descriptions and design-basis documents.
Several escalated enforcement actions were proposed subsequent to the SALP period.
The AFW system and th'e AFW back-up nitrogen system were found, in an NRC Safety Systein Functional Inspection, to be susceptible to degradation and loss of safety system function.
The licensee has developed and is
~
implementing a corrective action program.
A significant weakness was noted in the implementation of the Plant Change / Modification (PC/M) program with respect to the installation and testing of new Unit 3 neutron flux monitors. The monitors were not made fully operable prior to the end of the last Unit 3 refueling outage as required by Commission Order.
Erroneous quality inspector certifications of completed system testing contributed to the problem. Additionally, a letter sent to the NRC contained inaccurate statemef.s with respect to the use of the monitors. A proposed Severity Level III violation (see the Outage Analysis) was issued subsequent to the end of the SALP period for discrepancies which occurred daring thej 1985 Unit 3
- efueling outage.
The licensee has respondeo-requesting mitigation of the severity level and penalty.
This request is under NRC review.
36 The quality program has not been effective in preventing an apparent breakdown in facility management controls in the areas of operations and maintenance problem identification.
The program did not adequately ensure that safety-related technical issues were promptly resolved. As mentioned in the Plant Operations and Maintenance Analyses of this assessment, significant unnecessary delays occurred prior to the resolution of several issues. Many of these issues required significant NRC involvement prior to the licensee implementing effective corrective measures.
The corrective measures were not initiated by the licensee's quality program.
The quality program did not ensure that chronic maintenance problems were addressed and expeditiously corrected.
Long term maintenance problems have existed in the area radiation monitoring sy s terr,
process radiation monitoring system and source range nuclear instrument systems.
The quality progran did not ensure that the root causes of various maintenance problems, as specified in the Maintenance Analysis of this assessment, were identified and corrected.
Root cauie evaluations were inadequately performed for AFW stop check valve failures, water entry into the instrument air system and overspeed tripping of the AFW pumps.
Consequently, corrective actions for these maintenance problems were not comprehensive in nature and the problems recurred.
Additionally, the root cause identifica-tion section of numerous Plant Work Orders were not required to be filled out during maintenance activities.
A Confirmatory Order issued to FPL in July 1984 reiterated the Performance Enhancement Program (PEP) commitments outlined in correspondence from FPL to the NRC in April 1984.
This program impacted existing QA activities.
The following changes were either completed or in process:
increased QA and QC staff size; realigned the QA and QC staff; increased QA personnel training; increased QA technical expertise (two recently hired QA employees were licensed operators);
improved communication between QA and site personnel; modification of the QA reporting structure; and expanded QA and QC surveillance programs.
The site and corporate auditing program activities have improved since the previous SALP period. QA audits and site,'surveillances generally demonstrated increased depth and morg substantial findings.
As noted in the Outages analysis, the licensee's QA audit program is credited with finding numerous problem areas in
37 the design change and modification program.
The audit depth weakness noted in the Health Physics area had been. identified by the licensee and corrective action appears to have commenced. QA procedures and site administrative procedures were being revised to clarify and add better definition to the program.
Closure of some major audit findings involving the QA records vault, snubber surveillances, and containment painting activities were lengthy and complex, but the resolutions appeared adequate.
The previous emphasis of site QA had been in the area of document review; however, the emphasis has shifted to actual work overview.
Although two operations oriented personnel had _been hired and training was ongoing, it was determined that additional field verification expertise would be appropriate.
The licensee has restructured their QA organization to include more field verif-ication inspectors.
The two interrelated programs, records and document control, appeared to meet regulatory requirements with one exception.
Violation (1) was issued for failure to retain operating records the length of time required by the Technical Specifications.
The method of storage and the fact that many records, which may have to be utilized by the plant during operation, were stored off-site made record retrieval difficult. The site QA group displayed an interest in improving the records and document control programs; several nonroutine audits were scheduled for these programs.
There was a slight improvement in these programs over the previous SALP period, in that site personnel were more aware of the pertinent regulatory requirements.
Programmatic and implementing controls for procurement activities were adequate.
This was due, in part, to the overall strength of the FPL procurement effort, the standardization of procurement activities, and an active QA auditing program.
Several of the site's procedures have been rewritten in response to audit findings and corporate standardization.
The receipt, storage, and handing (RSH) program was generally identified adequate pending QA closure of some licensee problems. A site construction audit, which dealt with problems in relocation to a single warehouse from a two warehouse configu-ration, identified deficiencies in the storage and transfer of safety-related material s.
Another con.*.ruction audit dealt with the program for material control from receipt to installation.
The audit and corrective actions were not reviewed by the NRC prior to the end of the SALP period. Plant QC receipt inspection findings have increased dramatically since a reor(anization of that group.
e
b w
38
,, h, 1
Violations (b) and (c) involved failures to establ,ish specific criteria for hafnium poison insert receipt inspections and to review related nonconforming items for acceptance, rejection >
repair, or rework in accordance with documented procedures.
o The' off-site support staff was effective in providir!g site s
s support. 'The : training of personnel appeared ' adequate tohensure technical competence.
Interface with' the on-site staff was good.
Greater efficiency in providing sup' port services was achieved by assigning off site organizational staff to the site.
The Company Nuclear Review Board ('o"tf-site teview committee) was adequate in fulfilling the function of its c,harter. -
The licensee appeared responsive t'o NRC concerns, in that previously identified NRC. problem areas were able to be closed upon reinspection.
Four violations were identified:
a.
Severity Level IV violation for failure to perform _rdquir5d '
triennial vendor audit's.
(85-34) b.
Severity Level IV violation for' failure to process nonconforming items in accordance with documented procedures (AP190.13).
(85-13) s Severity Level IV violation for an inadequate hafnium, poison c.
insert receipt inspection.
(85-13) d.
Severity Level V violation for failure to retain operating records the length of time required'by the TS.
(251/84-36) 2.
Conclusion i
Category:
3 s
Trend:
Improving l
3.
Board Recommendations The board recognized the fact that licensee management has expended significant effort to improve performance in this area.
J.
Licensing Activities 1.
Analysis f
The licensee generally continues to exercise management control and overview in the licensing activity area.
As ' stated in the previous SALP, the licensee has frequent meetings, visits and
4 ;'
39 management discussions with the NRC staff.
These assist in providing a clear understanding of safety issues and the need for timely resolution.
There is a reasonable balance between the licensee's resources utilized to improve plant performance /
generation and the resources utilized in enhancement / improvement of' overall plant safety. The licensee has implemented a reorgani-
.zation, which includes a Site Vice President, increased the licensing staff and restructed the plant site engineering support staff to assure all' aspects of safety considerations are included in
'their licensing submittals and follow-up activities.
-Management involvement was demonstrated in the submittals provided to resolve the pressurized thermal shock (PTS) issue for the Turkey Point reactor vessels.
Although the licensee's management continues to be strong and aggressive, licensing initiatives and activities have not received the same level of attention as during the previous SALP period.
Although the decrease has been slight, it has affected the resolution of some issues such as the Technical Specifications for the reactor vessel level monitoring system and the reporting T
requirements per Generic Letter 83-43.
The licensee has increased the technical staff supporting the Turkey Point plant both in the engineering offices and at the plant site.
Consistently sound technical justification continues to be provided for deviations from staff guidance.
The enhancement of the licensee's overall technical capability is demonstrated by their activities in the fuels area.
Two Topical Reports, PWR Lattice Physics and RETRAN Code, have been submitted for NRC staff review and will be utilized at both the Turkey Point and St. Lucie facilities.
In general, the licensee's initial submittals and responses to the NRC staff's requests for information have met projected or agreed upon schedules. However, there have been some schedule slips, but in most cases, justification and revised schedules were provided.
The current effort to consolidate a majority of the nuclear engineering support staff in a central location should enhance the overall efficiency of the licensing
- process, including the timeliness of submittals and responses.
The overall response of the licensee t? NRC licensing initiatives continues to be prompt and generally complete.
The licensee worked with the NRC staff to resolve a number of multi plant and TMI items.
The licensee supported several generic studies including site visits for a maintenance /surveilla(ce study, a wrong train / wrong unit study and an Unresolved Safety Issue (USI A-451) relating to decay heat removal capability.
IE should also be noted that Unit 4 is included in the Interna'ional Atomic t
Energy Agency (IAEA) Inspection Program.
i i.
.40 The overall licensing staff is divided into three major elements.
The licensing staff in Juno Beach provides the overall support for NRR-licensing activities and the licensing staff in Miami provides overall support for Regional and IE activities. Both groups work closely with the ~ licensing and compliance staff located at the plant site. The assignment of a licensed senior reactor operator to assist in licensing activities has been of great assistance.
The licensing group participates in various corporate-wide training programs and provides specialized training for the licensing staff.
The licensee's overall licensing activities have been conducted in a professional and efficient manner. The effort is generally well managed and, for the most part, meets projected schedules and goals. There has been a slight overall decline in the licensing area.
The major problem appears to be the-extensive activities and resources necessary to respond to the problems identified in safety-related systems such as the auxiliary feedwater, component cooling water and intake ccoling water systems during the licensee's Select Safety System Review effort.
i However, the need for improvement has been discussed with the licensee and there appeared to be an improving trend toward the end of this SALP period.
2.
Conclusion Category:
2 3.
Board Recommendations
~
No changes in the NRC;s inspection resources were recommended.
K.
Training and Qualification Effectiveness 1.
Analysis During this SALP reporting period, several routine and reactive inspections were conducted in the area of training at the Turkey Point facility.
In addition, replacement and requalification examinations were conducted in February 1986.
The inspections noted deficiencies in various training programs; those programs and deficiencies are discussed below as well as in the other functional area analyses, if applicable.
The requalification examinations resulted in the determination that the licensed operator requalification training program was unsatisfactory.
f An inspection performed as a follow-up to the Safety System Functional Inspection revealed several deficiencies Pin the areas of operator and maintenance training.
Operator training on AFW flow balancing and operator knowledge of the Control Room
41 Inaccessibility Procedure were inadequate.
Formal maintenance training had been discontinued for approximately 1h years to support the INPO accreditation effort.
This contributed to inadequate training on motor operated valve (M0V) maintenance and the lack of qua_lification ' cards or on-the-job training (0JT) records for the _ Maintenance Department.
Full maintenance training, using a systematically developed approach, began in January 1986.
A routine maintenance inspection and a reactive inspection found a lack of training on newly revised procedures related to the loss of a 120 volt vital bus. The licensee committed to improve the training related to this problem through the use of on-shif t training, classroom retraining, and plant modification training.
A reactive training inspection conducted in March 1986 found that operators were unfamiliar with the E0Ps anu their attachments generated by a Justification for Continued Operation (JCO) for the emergency diesel generators. The training that had been conducted was of a static nature instead of a walkthrough-simulation o,f possible events. This resulted in uncertainty on the part of the operators as to entry and exit points in the revised procedures and attachments. Further, the operator training the licensee had committed to provide on the Gamma-Metrics neutron level instru-ments was still not being provided to new license candidates.
A routine inspection in the areas of operator license application review and licensed operator requalification program review identified weaknesses in the administration of the requalification programs.
During this period, operator licensing replacement examinations were administered on April 30, 1985, when one (of one) senior reactor operator (SRO) candidate passed an oral examination, and February 3-12,
- 1986, when 8
of 12 reactor operator (RO) candidates, 11 of 15 SRO candidates and 0 of 1 instructor certifi-cation (IC) candidates passed the combined written and oral examinations.
l Additionally, oral and written requalification examinations were given to approximately 25 percent of the licensed operators during the period of February 3-11, 1986.
Of the thirteen operators examined, 0 of 4 R0s and 4 of 9 SR0s $ssed the combined written and oral examinations, resulting in an unsati sfactory requalifi-cation training program evaluation.
All license renewal applications are being held in abeyance until each licensed operator can be administered an NRC requalificatiorg examination.
Subsequent requalification examinations were administered in April 1986 and an overall pass rate of approximately 60' percent was i
achieved.
Additional examinations are scheduled for August and l
42 December 1986, so that all licensed operators may be examined and
-a determination of the quality of the upgraded requalification
. training program can be made.
In summary, the training at the Turkey Point facility has had
-programmatic breakdowns.
These weaknesses are a
result of insufficient emphasis being placed on the training of ' operations and maintenance personnel even in view of commitments to the NRC for program improvements.
As discussed in the Operations analysis, a number of facility improvements are in progress at Turkey Point as part of the PEP.
. A new training building is currently under construction and a plant specific simulator is on order.
It is projected that the simulator will be operational during the latter half of 1987.
The health physics technician and nonlicensed operator training programs achieved INPO accreditation in the Spring of 1986. The licensee plans to submit other training programs for accreditation in the future.
i 2.
Conclusion Category: 3 3.
Board Recommendations A continuing commitment on the part of licensee management is needed to rectify the training situation and to ensure the proper qualification of plant personnel.
V.
Supporting Data and Summaries A.
Licensee Activities During the assessment period Unit. 3 was in routine commercial operations with a refueling outage from March 30 to July 17, 1985.
Other outages included those discussed under Item J - Reactor Trips and:
a maintenance outage from October 21 to November 6, 1985; 4
inspection of motor-operated valves from November 30 - December 4, 1985; repair of auxiliary feedwater steam valves from January 7-15, 1986; and an outage to resolve concerns that component cooling water was not adequately balanced from March 5, 1986 to April 8, 1986.
During the assessment period Unit 4 was in routine commercial operation with a refueling outage commencing January 10, 1986 and lasting through 4
the remaining portion of the evaluation period. Other oueges included those discussed under Item J - Reactor Trips and:
a shutdown from June 16-23, 1985 for Unit 3 engineered safety features testing; a shutdown from November 23 to December 1, 1985 to inspect motor-operated valves.
~. -. _ _, _
43 8.
Inspection Activities The routine inspection program was performed during this period, with special inspections conducted to augment the program as follows:
1.
May 15 - ' June 5, 1985, in the area of independent inspection regarding an _unreviewed safety question involving changes to both units' spent fuel pool cooling lineup.
2.
May 22-24 and June 4,
- 1985, involving a physical security inspection to review the facts and circumstances surrounding two physical security events reported by the licensee in accordance with the provisions of 10 CFR 73.71(c).
3.
August 1, 1985 - January 11, 1986, in the area of design changes and modifications involving the installation of environmentally qualified neutron detectors on Unit 3.
4.
August 19-21,
- 1985, in. the areas of emergency Preparedness, Emergency Response Facilities, NRC Response Team coordination, and NRC hurricane response equipment, coordination and procedures.
5.
August 26-30 and September 9-13, 1985, to assess the operational readiness of the auxiliary feedwater system.
This Safety System Functional Inspection (SSFI) covered maintenance, operations, surveillance, quality assurance, training, and design changes and modifications.
6.
September 9 - October 10, 1985, to assess the adequacy of 10 CFR 50.59 reviews dealing with the turbine runback system modifications.
7.
September 30 - October 4, 1985, in the areas of housekeeping, material identification and control and Gul f alloy supplied material.
8.
November 4-22, 1985, in the areas of operation and maintenance of the auxiliary feedwater (AFW) and associated systems.
This inspection was conducted as a follow-up to the Safety System Functional Inspection.
9.
January 6-10, 1986, to investigate repetitive failures of the stop check valves in the steam supply systef to the AFW pump turbines.
- 10. January 15-16 and 31,1986, in the area of external. exposure and management controls during work performed on the Unit 3 flux mapping system.
f
- 11. April 1-4, 1986, to review the Turkey Point / Florida Power and Light Company Fitness for Duty Program.
44 1
C.
Licensing Activities The basis for this appraisal was the licensee's performance in support of licensing actions that were either completed or had a significant level of activity-during the rating period. These actions consisted of
-amendment requests, exemption requests, responses to generic letters, TMI items and other actions.
The number of closed licensing actions can be summarized as follows:
Active actions at beginning of period (11/1/84) 66 Actions added during period 56-Total actions 122-Completed actions during period 64 Active actions at end of period (4/30/86) 58 The 64 actions completed during this SALP period can be divided into three major categories. The number of actions which were completed for each category are:
Plant specific actions 36 Multi plant actions 18 r
TMI actions 10 1.
Licensing Actions Completed During This SALP Period Spent Fuel Pool Expansion Item 4.3 Automatic Actuation of Shunt Trip Attachment Off-site Dose Calculation Manual Masonry Wall Design - Response To IE Bulletin 80-11 Schedule Exemption Request, Appendix R NUREG-0737, Item II.F.2.3, Inadequate Core Cooling Instrumen-tation ISI Relief Request Neutron Source Data-CY9 NUREG-0737, Item I.D.2, Safety Parameter Display System Effectiveness of LWR Regulatory Requirements ReactorPlantSurveillanceMaterialProgramTSh Items 4.2.1 and 4.2.2 - Preventive Maintenance Program
45 NUREG-0737,-Item III.D.3.4, Control Room Habitability Enriched Fissionable Material Limits and Surveillance
' Supplement To SE On New Data Transfer Procedure NUREG-0737, Item I.D.1.2, Detailed Control Room Design Review Summary Report Remove MOV 750 and 751 From Appendix "J" List NUREG-0737, Item II.K.3.30, Small Break LOCA Outline Item 1.1 - Post-Trip Review Program Description Safety Evaluation for Support of Proposed TS Changes l
l Moderator Temperature Coefficient TS Change Control of Heavy Loads - Phase II. (Followup of MPA #C-10p Modification of Commission Order Dated 2/23/84 Supplementary Confirmatory Order - RG 1.97 Schedules Modify Commission Order Dated February 23, 1984 - SPDS Item 3.1.3, Post-Maintenance Testing TS, RTS Components Item 3.2.3, Post-Maintenance Testing TS, All Safety-Related Components Item 1.2, Post-Trip Review Data and Information Capability Parameter Selection for SPDS Modification of Commission Order Emergency Preparedness Schedule Exemption Steam Generator (GL 85-02) Review Instruments To Follow The Course o# an Accident
46 2.
NRR-Licensee Meetings Subject Date Schedule Exemption Request December 10, 1984 (10 CFR 50.48) Appendix R Technical Specifications - Conversion February 4,-1985 Program Regulatory Requirements March 7, 1985 Technical Specifications - Conversion July 11, 1985 Program Integrated Living Schedules July 25, 1985-Detailed Control Room Design Review' August 1, 1985 Pressurized Thermal Shock October 3, 1985 Regulatory Requirements March 7, 1986 Technical Specifications - Conversion March 18, 1986 Program 3.
NRR Site Visits Discuss Licensing Schedules and Status January 29 -
of Ongoing Modifications February 1, 1985 SALP Meeting and Site Visit February 14-15, 1985 Performance Enhancement Program February 21-27, 198T Prehearing Conference and Site Visit March 25-28, 1985 SPDS Meeting and Implementation August 13-15, 1985 Auxiliary Feedwater Inspection August 26-30, 1985 Auxiliary Feedwater Exit Meeting September 12-13, 1985 Auxiliary Feedwater October 31 -
November 1, 1985 Wrong Train / Wrong Unit Novembe821-22,1985 Maintenance Survey Decembe/ 2-6, 1985 Site Visit and Status of Modifications March 11-13, 1986
47 4.
Commission Briefings None 5.
Schedule Extensions Granted Modification of Commission Order Dated July 15, 1985 February 23, 1984, Extension of Schedules for Completion of SPDS and RG 1.97 Modification of Commission Order Dated December 24, 1985 February 23, 1984, Extension of Schedule for completion of Emergency Operating Procedures 6.
Reliefs Granted Inservice Inspection Relief - Regenerative February 13, 1985 Heat Exchangers Inservice Inspection Relief - Main coolant April 23, 1985 i
piping welds and main steam reducer to nozzle piping welds 7.
Exemptions Granted Fire Protection - Schedule Requirements of January 4, 1985 10 CFR 50.48(c)(2), (c)(3) and (c)(4) 8.
License Amendments Issued Amendment Date No.
Subject November 21, 1984 111/105 Spent Fuel Pool Expansion April 22, 1985 112/106 Integrated ISI Program May 9, 1985 113/107 Deletion of Limits on Fissionable Material June 27, 1985 114/108 Allow Breaching of Containment for farveillance Testing June 27, 1985 115/109 Moderator Temperature Coefficient I
P
rs 48 9.
Hearings and Pre-Hearings Hearing - Operational Limits Amendments December 10-13, 1985 U.S. District Court House, Miami Prehearings - Spent Fuel Pool Rerack March 26-28, 1985 and Fuel Enrichment Amendments University of Miami Law School, Miami D.
Investigation and Allegation Review No major investigations were conducted at Turkey Point during this appraisal period.
E.
Escalated Enforcement Actions 1.
Civil Penalties a.
A Proposed Imposition of Civil Penalty (EA-83-138) for unauthorized entry into a locked high radiation area had been issued during the previous SALP period. On November 9, 1984, a conference was - held with FPL to discuss their corrective actions and possible mitigation of the $40,000 Civil Penalty.
The NRC concluded that the Severity Level III (Supplement IV) violation was valid, but that the licensee's extensive corrective actions justified complete mitigation of the associated Civil Penalty.
b.
A Notice of Violation (Severity Level III, Supplement I) and Proposed Imposition of Civii Penalty (EA-84-121) for $25,000 was issued on February 28, 1985, for failure to satisfy the Technical Specification Limiting Condition for Operation action statement for the Unit 4 intake cooling water system.
This violation, although issued during the current SALP period, was addressed in the previous SALP analysis.
c.
A Notice of Violation (Severity Level III, Supplement I) and Proposed Imposition of Civil Penalty (EA-85-80) for $100,000 was issued on August 20, 1985, for failure to determine whether a change to the facility's spent fuel pit cooling lineup created an unreviewed safety question.
FPL requested mitigation on September 19, 1985, however, an Order Imposing Civil Monetary Penalty in the amount of $100,000 was issued on January 14, 1986, d.
A Notice of Violation (Severity Level III, Supplement IV) and Proposed Imposition of Civil Penalty (EA-86-39h for $50,000 was issued on April 28, 1986, for radiation exposure control problems associated with maintenance activitiesPon the Unit 3 traversing incore probe system on January 8, 1986.
The licensee's request for mitigation of the Severity Level and Civil Penalty is being evaluated.
49 A proposed Severity ' Level III (Supplement I) violation, with e.
an associated $50,000 Civil Penalty, for inadequate testing and failing to satisfy an NRC Order regarding the operability of ~ a neutron flux detector system on Unit 3 was issued on June 25, 1986.
2.
Orders a.
An order imposing a civil monetary penalty was issued on January 14, 1986, as discussed in paragraph E.1.c above.
b.
An order updating the Performance Enhancement Program was issued on August 12, 1986 subsequent to the SALP period.
F.
Licensee Conferences Held During Appraisal Period Management meeting to discuss PEP 1.
November 2, 1984 progress Enforcement Conference to discuss
.2 ;
November 9, 1984 corrective actions related to an entr'y into a high radiation area Management meeting to discuss PEP 3.
December 7, 1984 progress 4.
December 18, 1984 Enforcement Conference to discuss an AFW pump failure Management meeting to review SALP 5.
February 15, 1985 report Management meeting to discuss a change 6.
February 20, 1985 to the Physical Security Plan Management meeting to discuss PEP 7.
February 22, 1985 progress Enforcement Conference to discuss the 8.
March 28, 1985 containment spray system Management meeting to discuss PEP 9.
April 12, 1985 progress Management meeting to discuss PEP
- 10. May 23, 1985 progress f
Enforcement Conference to di; cuss
- 11. June 4, 1985 radioactive waste transporta. tion, a security computer outage and spent fuel pool alterations
50 12.
August 30, 1985 Management meeting to discuss PEP progress and AFW system testing 13.
September 24, 1985 Management meeting to discuss PEP progress
- 14. October 9, 1985 Enforcement Conference to discuss turbine runback system
- 15. November 26, 1985 Man,gagement meeting to discuss PEP progress
- 16. January 8, 1986 Enforcement Conference to discuss maintenance issues and the Gamma-Metrics neutron detectors
- 17. January 31, 1986 Enforcement Conference to discuss AFW system stop check valves and the loss of high radiation area access control
'18.
F?bruary 25, 1986 Management meeting to discuss the FEL health physics program 19.
February 26, 1986 Management meeting to discuss the Select System Review Milestones 20.
March 7, 1986 Management meeting to discuss PEP progress 21.
March 21, 1986 Management meeting to discuss requalification examination results, CCW flow balancing, and intake cooling water flow concerns G.
Confirmation of Action Letters (CALs)
CAL 50-250, 251-86-01 was issued on April 2, 1986, to confirm Region II's understanding of what actions would be completed by FPL prior to restarting Units 3 and 4 to ensure that emergency diesel generator loads are maintained within allowable limits.
?
51 i
H.
Licensee Event Report Analysis During the assessment period, 51 LERs for Unit 3 and 30 LERs for Unit 4 were analyzed.
The distribution of these events by cause, as-l determined by the NRC staff, was as follows:
- LERs Cause Unit 3 Unit _4 Component Failure 18 15 i
Design 7
1 I
Construction, Fabrication, or 1
1 Installation 2
Personnel' Operating Activity 8
3 Maintenance Activity 4
3
. - Test / Calibration Activi.ty 9
2 Other 2
1 T
2 Out of Calibration i'
Other 2
2 TOTAL 51 30 l
I.
Enforcement Activity UNIT
SUMMARY
FUNCTIONAL NO. OF DEVIATIONS AND VIOLATIONS IN EACH i'
AREA SEVERITY LEVEL i
4 0
V IV III II I
UNIT NO.
3/4 3/4 3/4 3/4 3/4 3/4 l
Plant Operations 1/1 9/8 1/1 Radiological Controls 1/1 1/1 1/1 Maintenance 1/1 7/5 Surveillance 1/1 11/9 i
Fire Protection 3/3 1/1 Emergency Preparedness i
Security 1/1 1/1 I
i Outages 6/7 j
Quality Programs and Administrative Controls j
Affecting Quality 0/1 3/3 t
Licensing Activities i
Training TOTAL 7/8 39/35 3/3 I
I i
52 1
FACILITY
SUMMARY
FUNCTIONAL NO. OF DEVIATIONS AND VIOLATIONS IN EACH AREA SEVERITY LEVEL D
V IV III II I
Plant Operations 1
12 1
Radiological Controls 1
1 1
Maintenance 1
7 Surveillance 1
11 Fire Protection 3
1 Emergency Preparedness Security 1
1 Outages 7
Quality Programs and Administrative Controls Affecting Quality 1
3
. Licensing Activities i
' Training TOTAL 8
43 3
(*) An additional apparent violation was issued after the end of the SALP period as discussed in the Outages analysis.
J.
Reactor Trips Ten unplanned reactor trips and seven manual shutdowns occurred during this evaluation period for Unit 3.
Unit 4 sustained eleven unplanned trips and six manual shutdowns.
The unplanned trips are listed below.-
1.
Unit 3 a.
December 13, 1984 - The reactor tripped from 100 percent peser due to a turbine generator trip caused by a ground in the generator exciter. The unit was placed in cold shutdown to replace the exciter, which had 'suf fered some burned rotor windings.
b.
January 19, 1985 - A plant shutdown was in progress because of a condenser tube leak.
Reactor power had been decreased below 10 percent and the anticipautry reactor trip due to a turbine trip had been blocked (permissive P-7).
A slight power increase rearmed the P-7 permissive, so when the operators manually tripped the turbine a reactor trip l
resulted.
I e
53 c.
January 29, 1985 - A reactor trip resulted from the inadvettent trip of the rod drive MG sets due to a personnel error.
The turbine operator had been instructed to tag open the Unit 4 MG set output breakers, however, he entered the wrong room and opened the Unit 3 breakers instead.
d.
July 16,1985 - A subcritical reactor trip occurred due to the loss of the "3C" vital instrument bus inverter. The loss de-energized a source range nuclear instrument causing a spurious source range high flux trip.
A blown fuse was replaced and the inverter was returned to standby service.
The licensee was in the process of replacing all twelve inverters in an effort to improve reliability.
e.
July 21, 1985 - The reactor tripped from 100 percent power due to a spurious protection relay actuation attributed to a lighting strike near the Unit 3 turbine deck. The auxiliary and main feedwater systems did not respond properly during the transient and a short outage followed to effect repairs.
~
f.
July 29,1985 - The reactor tripped from 100 percent powef during the performance cf reactor protection system (RPS) testing.
The cause was suspected to have been dirty relay contacts in the RPS cabinets.
No specific dirty contact could be identified, but detailed system testing was satisfactorily completed prior to restarting the unit, g.
August 1,1985 - The reactor tripped from 32 percent power when an instrument inverter failure caused the "A" SG level to increase to the high-high level setpoint thereby tripping the main turbine and the reactor. The failed components were replaced and the inverter was returned to service.
h.
October 15, 1985 - The reactor tripped from 100 percent power when a construction worker in the cable spreading room inadvertently jarred the main transformer differential relay causing the turbine generator and, in turn, the reactor to trip.
A reactor restart was delayed until auxiliary feed-water system Technical Specification operability requirements could be satisfied.
i.
November 30, 1985 - The RPS was actuated and the reactor trip breakers were opened but all the control rods had already been inserted. A source range nuclear instrument had failed to automatically energize during a piant shutdown, so the instrument fuses were removed and reinstalled to determine whether improved fuse contact would restore insfrument power.
The instrument did energize and the resultant power surge caused a false high source range flux spike wHich actuated the RPS.
54 j.
March 5, 1986 - A reactor trip occurred due to a source range instrument spike while conducting a plant shutdown.
The shutdown was required because the component cooling water flow to the containment coolers could not be shown to meet design values.
2.
Unit 4 a.
November 24, 1984 - The reactor tripped from 100 percent power when the "4A" 4160 volt ac bus lost its power supply, resulting in a loss of power to the "4A" reactor coolant pump (RCP) and a loss of reactor coolant flow. The luss of power was caused by a phase-to ground fault in the "4A" RCP
- breaker, b.
February 6,1985 - The reactor tripped from 27 percent power durinc a startup tecause the "A" steam generator (SG) level was low coincident with a steam flow - feed flow mismatch for the same SG. A post-trip investigction found the steam flow channel to be reading high.
The post-trip review (erroneously) stated that the steam flow transmitter had beam corrected (more in the next paragraph) and the unit was restarted, c.
February 7, 1985 - The reactor tripped from 100 percent power when the "4B" main feedwater pump de-energized due to a loss of power to the "4C" bus.
The power loss resulted from protective relay action in response to an electrical fault on the "A" phase of the 240 kv switchgear.
A safety injection signal was initiated during the transient as a result of a low-low reactor coolant system average temperature coincident with high steam flow indication in two channels. One channel failed high due to a blown fuse, but the second channel actuated because of a zero off set which had not been corrected after the trip discussed in the previous paragraph.
No actual steam flow existed because the main steam line isolation valves had been closed earlier in the transient.
d.
May 15, 1985 - A reactor trip occurred when a coristruction worker bumped a relay in the safeguards relay rack while preparing to pull a cable in the area.
The relay actuation initiated a turbine trip on high-bigh level in the "C"
SG, which tripped both main feedwater /tmps and isolated the SG.
All systems responded normally and the unit was returned to operation later the same day.
e.
May 17, 1985 - Thereactortrippedwhenthe"C"hGregistered a low level in coincidence with a feed flow - steam flow
- mismatch, lhe transient resulted from a loss tf of f-site power caused by brush fires north of Miami that affected the 500 kv transmission lines.
l 55 f.
May 30, 1985 - The reactor tripped on a low SG level coinci-dent with a feed flow - steam flow mismatch. The transient was caused by the loss of a vital instrument inverter which j
resulted in a turbine runback. A blown fuse was replaced in the "4A" inverter but troubleshooting failed to reveal any other problems.
g.
June 6,1985 - The reactor tripped as the result of a main turbir.e trip on high SG water level. A ground in a nuclear instrument channel caused a fuse in the "4C" inverter to blow resulting in a loss of automatic feedwater control.
The faulty circuits were repaired and the unit was returned to power operation.
I h.
June 21, 1985 - A subcritical reactor trip occurred due to the loss of the "4C" vital bus inverter.
The loss de-energized one source range and one intermediate range nuclear instrument, each generating a reactor trip signal.
The evaluation of this and previous inverter failures ultimately resulted in the licensee's decision to replace al-1 the inverters.
i.
July 17, 1985 - The reactor tripped from 100 percent power due to a loss of the "40" inverter, which caused a turbine runback and the resultant high pressurizer pressure signal.
The inverter failures were recognized as a repetitive problem and the licensee was expediting their replacement.
J.
August 20, 1985 - The reactor tripped from about 30 percent power due to a turbine trip caused by a SG high water level-condition. Power was initially lowered to 70 percent when a dropped rod caused a turbine runback.
After the unit stabilized, a second dropped rod caused another turbine runback and the resultant SG high level turbine trip.
k.
November 23, 198; - The reactor tripped f rom hot standby during shutdown due to a source range high flux trip when the source range nucle-instruments energized.
o P
l L
I ENCLOSURE 2 SALP BOARD REPORT U. S. NUCLEAR REGULATORY COMMISSION REGION 11 i
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE INSPECTION REPORT NUMBERS 50-335/86-13 and 50-389/86-12 FLORIDA POWER & LIGHT COMPANY ST. LUCIE UNITS 1 AND 2 NOVEMBER 1, 1984 THROUGH APRIL 30, 1986 5
b-/4(8h edY g/
~
W e
2 1.
Introduction The Systematic Assessment of Licensee Performance (SALP) program is an integrated NRC staff effort to collect available observations and data on a periodic basis and to evaluate licensee performance based upon this informa-tion.
The SALP program is 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 operation.
An NRC SALP Board, composed of the staff members listed below, met on July 15, 1986, to review the collection of performance observations and data to assess licensee performance in accordance with guidance in NRC Manual Chapter 0516, " Systematic Assessment of Licensee Performance." A summary of the guidance and evaluation criteria is provided in Section II of this report.
This, report is the SALP Board's assessment of the licensee's safety performance at St. Lucie Units 1 and 2 for the period November 1, 1984,T through April 30, 1986.
SALP Board for St. Lucie Units 1 and 2:
L. A. Reyes, Acting Director, Division of Reactor Projects (DRP), RII (Chairman)
J. P. Stohr, Director, Division of Radiation Safety and Safeguards, RII V. W. Panciera, Acting Director, Division of Reactor Safety, RII D. M. Verrelli, Chief, Reactor Projects Branch 2, DRP, RII A. C. Thadani, Director, PWR Project Directorate #8, Division of PWR Licensing-B, NRR E. Tourigny, Senior Project Manager - St. Lucie, PWR Project Directorate #8, NRR R. V. Crienjak, Senior Resident Inspector, St. Lucie, DRP, RII e
l I
l
3 Attendees at SALP Board Meeting:
S. A. Elrod, Chief, Reactor Projects Section 2C (RP2C), DRP, RII K. D. Landis, Chief, Technical Support Staff (TSS) DRP, RII T. C. MacArthur, Radiation Specialist, TSS, DRP, RII D. R. Brewer, Senior Resident Inspector, Turkey Point, DRP, RII S. Guenther, Project Engineer, RP2C, DRP, RII H. E. Bibb, Resident Inspector, St. Lucie, DRP, RII J. Rausch, Reactor Engineer, TSS, DRP, RII D. Sells, Senior Project Manager, PWR Project Directorate #S, NRR
?
l l
m
4 II. Criteria Licensee performance is assessed in selected functional areas depending on whether the facility has been in the construction, preoperational, or operating phase during the SALP review period.
Each functional area represents an area which is normally 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 observations.
Special areas may be added to highlight significant observations.
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 j
and others may have been used where appropriate.
A.
Management involvement in assuring quality f
i B.
Approach to the resolution of technical issues from a safety standpoint C.
Responsiveness to NRC initiatives D.
Enforcement history i
E.
Operational and construction events (including response to, analysis of, and corrective actions for)
F.
Staffing (including management)
G.
Training and qualification effectiveness Based upon the SALP Board assessment, each functional area evaluated is classified into one of three performance categories.
The definitions of these performance categories are:
Category 1:
Reduced NRC attention may be appropriate.
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 achieved, i
Category 2:
NRC attention should be maintainec at normal levels.
Licensee management attention and involvement are evident and are concerned with nuclear safety; licensee resources are adequate and are reasonably effective such that satisfactory performance with respect to operational safety or construction quality is being achieved.
Category 3:
Both NRC and licensee attention should be increased.
Licensee management attention or involvement is acceptable and considers nuclear safety, but weaknesses are evident; licensee resources appear to be strained or not effectively used such that minimally satisfactory perf ormance with respect to operational safety or construction quality is being achieved.
I The functional area being evaluated may have some attributes that would place the evaluation in Category 1, and others that would place it in either Category 2 or 3.
The final rating for each functional area is a composite of the attributes tempered with the judgement of NRC management as to the significance of individual items.
5 The SALP Board may also include an appraisal of the performance trend of a functional area.
This performance trend will only be used when both a definite trend of performance within the evaluation period is discernible and the Board believes that continuation of the trend may result in a change of performance level.
The trend, if used, is defined as:
Improving:
Licensee performance was determined to be improving near the close of the assessment period.
Declining:
Licensee performance was determined to be declining near the close of the assessment period.
III. Summary of Results A.
Overall Facility Evaluation St. Lucie continues to be a well-managed site, with a technically competent and professional staff. Major strengths were identified in the areas of plant ope *ations, maintenance, surveillance, licensing activities, and training.
No major weaknesses were identified. :
Management involvement at all levels has contributed to the high level' of plant performance during this assessment period. One weakness was noted to recur in both the Radiological Controls and Surveillance analyses, in that plant procedures were not always adequate to maintain the level of program performance during changes in staf f experience levels.
B.
The performance categories for the current and previous SALP periods in each functional area are as follows:
July 1, 1983 -
November 1, 1984 -
Functional Area October 31, 1984 April 30, 1986
~
Plant Operations 1
1 Radiological Controls 1
2 Maintenance 1
1 Surveillance 1
1 Fire Protection 2
2 o
2 Security and Safeguards 1
2j Outages Not Rated 2,
6 Quality Programs and 2
2 Administrative Controls Affecting Quality Licensing Activities 1
1 Training and Qualification Not Rated 1
Effectiveness IV.
Performance Analysis A.
Plant Operations 1.
Analysis During the evaluation period, inspections were performed by the resident and regional inspection staffs.
Management involvement in daily operating activities continued at a high level and was augmented by the licensee's develcpment of a new management position titled Site Vice President.
This '
strengthened the local control of engineering and purchasing activities and enabled a more coordinated response to site needs.
The position was filled on March 1, 1985, by a strong manager who had previous experience as the St. Lucie Plant Manager during start-up and as the Site Vice President at another nuclear site.
Plant generation performance for both units continued to be well above average. Unit I was the lead plant in the western world for the second year in a row, having an annual load factor in excess of 100 percent for the period from September 1984 to September 1985.
It is not unusual for a plant to have a load factor in excess of 100 percent for short periods of time, however, this marked the first time a nuclear power plant had ever recorded an annual load factor in excess of 100 percent.
This was possible due to the continued high power operation of Unit 1 and the lower than predicted temperatures of the circulating water taken directly from the Atlantic Ocean.
Plant operations continued to be conducted in a professional manner with operators exhibiting a high degree of operating proficiency.
In general, the licensee's performance in the areas of procedural compliance and adequacy over the last SALP period and for most of this period was good to excellent. However, there have been some violations which indicate a slight decline in (his area.
Violations (c) and (e) listed below, coupled with a similar
7 violation (a) in the Outage analysis, could be indicative of a programmatic weakness.
These violations prompted additional licensee management attention to ensure the adequacy of procedures and procedure updates and the institution of measures to ensure that a major programmatic problem does not develop.
A site Procedures Department has been established to implement a procedure review program.
Administrative procedures have been developed to control the preparation, review, revision and approval of the upgraded procedures and to provide guidelines for the writing of procedures.
Emergency procedures have been rewritten utilizing the appropriate guides.
Off-normal and annunciator response procedures were being upgraded at the end of the SALP period. All operating procedures have been scheduled for upgrading af ter the completion of the of f-normal procedures. The upgrading process includes detailed operating and multi-discipline reviews, Facility Review Group (FRG) review and Plant Manager approval.
Several changes have also been incorporated into the design control process to ensure that potential problems dealing with procedure updates, as they relate to Plant Changes /
3 Modifications (PC/Ms), are adequately addressed.
A special inspection was conducted to assess the licensee's compliance with Generic Letter 83-28, Required Actions Based on Generic Implications of Salem ATWS Events.
Several deficiencies were identified in the post-trip review procedure implementation, indicating a possible lack of supervisory involvement in the post-trip review process.
The licensee had identified several other deficiencies and had revised the procedure to improve its effectiveness. The revised procedure, if properly implemented, should resolve the program deficiencies.
1 For Unit 1, there were three reactor trips and there were three actuations of the engineered safety features (ESF); two of the l
l trips were at power levels greater than 85 percent.
Unit l's -
reactor trip frequency of 0.26/1000 hours of operation compares very favorably to the current national average frequency of 1.1 trips /1000 hours of operation.
(See Section V.J for a further discussion of reactor trips.)
For Unit 2, there were sixteen reactor trips, six of which were at power levels greater than 85 percent; there were six ESF actuations. Unit 2's reactor trip frequency of 1.54/1000 hours of operation was higher than the current nf ional average frequency.
Both units had an availability factor of over 78 percent with Unit l's over 86 percent. As discussed earlier, Unit l's annual load factor was in excess of 100 percent for the feriod from September 1984 to September 1985.
e 8
Management's responsiveness to NRC and other initiatives was expeditious and thorough.
The previous SALP noted weaknesses associated with the adequacy of information reported in Licensee Event Reports (LERs). After consulting with NRC Headquarters and NRC' Region II, the licensee successfully altered its methods of
- presenting information in LERs. Since implementing these changes early in this SALP period, LER descriptions and cause analyses have shown dramatic improvement.
Events at St. Lucie are generally reported within the required time period following the occurrence. There were 43 LERs submitted during the evaluation period for both units.
Near the end of this evaluation period (April 28, 1986), a brief (one day) strike by the iron workers' union caused a shortage of plant operations personnel because some operators would not cross l.
the picket line. Licensee management took prompt, positive action to assure adequate staffing of critical positions.
The licensee has maintained a clean and efficient plant. During the period, added emphasis has been placed on plant cleanliness and a repainting program was initiated to improve plant preservation and appearance.
Plant tour observations have consistently found housekeeping to be above average, even during periods of high outage-related activity.
Housekeeping has been excellent during the latter part of the SALP period.
Conduct of operations in the control room was generally excellent.
Plant management is quite sensitive to control room demeanor and quick to correct lapses.
The NRC's questions were always addressed in a prompt and courteous manner.
Observations have shown that shift turnovers were adequate, with the relieving shift being properly briefed with information which cculd impact plant safety. Operators could almost always respond to inquiries about annunciators, plant or system status and lineups.
Procedures for various annunciator responses and Technical Specification requirements for LCOs were consistently followed.
The control rooms were always adequately staffed with an appropriate mix of talent and experience.
The senior operators, Nuclear Plant Supervisors (NPSs) and their assistant ANPSs, are given an appropriate level of responsibility within the FPL structure, which, when combined with their experience, results in certain operational issues and management decisions being made at somewhat lower levels than normally encountered.
This has had a positive effect on operator morale and has improved management efficiency in operations. Another contributor to management efficiency has been the use of the morning meeting, which is chairqp by the NPS.
Plant status for both units is reviewed, and plannbd evolutions and new problems are discussed.
Additional meetig,gs are then scheduled to address, in greater detail, particular problems and
9 their solutions.
Because all departments participate in these morning meetings, which are conducted by Operations, there is an atmosphere within the plant organization of supporting the plant's operation.
This has resulted in other departments, such as Maintenance, being more readily available to respond to and support the needs of the Operations Department.
Five violations were identified:
a.
Severity Level IV violation for an inoperable containment isolation valve.
(335/85-07) i b.
Severity Level IV violation for failure to properly align the instrument air supply to a main feedwater regulating valve after testing.
(389/85-10) e c.
Severity Level IV violation for failure to adequately establish plant procedures which reflect the operating characteristics of the main steam isolation valve air supply solenoid valve logic control circuit.
(389/85-20) p d.
Severity Level IV violation for failure to maintain two operable shutdown cooling loops during cold shutdown operations with the reactor coolant loops not filled.
(335/85-36)
Severity Level V violation for an inadequate procedure update e.
after a plant modification. (389/85-17) 2.
Conclusion Category:
1 Trend: Declining 3.
Board Recommendations The board noted that Unit I was a superior performer and met the criteria for a Category 1 rating, however, Unit 2's performance was determined to fit the Category 2 rating. Based on the strong management involvement, an overall rating of I was deemed appropriate.
B.
Radiological Controls f
1.
Analysis I
During the evaluation period, routine radiologicpl controls inspections were performed by the regional and resident inspection staffs.
The regional staff also performed a routine secondary
w f:.
,y Si 10 s
Ma s 3C chemistry inspection, a special inspection involving.a potential JLV overexposure-incident, and a confirmatory measurements inspection
,f/?
using the kRC. Region II mobile laboratory.
7 The licensee's health physics staffing level appeared adequate to support ~ routine operations.
Additional contract health physics technicians were utilized to supplement the permanent staff during refueling outages. Health physics staff turnover was low during
- the' evaluation period. The licensee maintained a small technical staff on-site, with'much of the health physics technical expertise c
J' in dosimetry processing, solid radioactive waste classification and audits residing in the corporate health physics group.
The audit program was, duo to corporate office concerns, under review by the licensee at the end of the assessment period.
During 1985, the licensee developed a formal training and y
qualification program for health physics technicians.
The licensee has submitted the program to the Institute of Nuclear Power Operations and anticipates that accreditation will be achieved in the fall of 1986.
1 r
The licensee submitted the required effluent and radiological environmental reports. There were no unplanned radioactive liquid 1
or ' gaseous releases during 1985.
Releases, while higher than T
regional averages for gaseous effluents, were within the prescribed limits of the Technical Specifications. 60,340 curies 3
(Ci) of fission and activation gases and 0.98 Ci of iodine-131
.. ~
were discharged to the atmosphere in gaseous effluents from both
/
units in 1985.
The 1985 Region II averages for a two unit site (based on 12 cperating PWRs) were 5260 Ci and 0.023 C1, s,
respectively. Liquid effluents contained 5.5 Ci of mixed fission and activation products and 650 Ci of tritium. The 1985 Region II averages were 1.3 Ci and 780 Ci, respectively.
Off-site doses calculated for liquid and gaseous effluents were within 10 CFR Part 20 and 10 CFR Part 50, Appendix I guidelines, j
For 1985 releases, the maximum calculated doses to a member of the public were 0.4 mrem from liquid effluents and 2 mrad combined gamma and beta dose from gaseous effluents.
These calculated l
doses represented 8 percent of the 10 CFR Part 50 Appendix I limits for liquid releases and 7 percent of the limits for gaseous releases.
The consistently high gaseous effluent releases over a period of i
several years were caused by a higher than expected rate of fuel cladding perforation in both units.
In 1985 and at present, most of the gaseous radioactivity has been from Unit 1. (The licensee s
has utilized the Unit 1 gaseous waste decay tanks to full capacity and has been able to achieve holdup times on the order of 21 to 28 V
- j r._
I 11
(
days in an effort to employ available design features to minimize releases. It was also noted that the licensee has a formal leak reduction program which enabled the detection of leakage problems with the waste gas decay tank system.
A deviation from the Final Safety Analysis Report (FSAR) design criteria / objectives was identified during the evaluation period.
Several reactor auxiliary building (RAB) doors were blocked open and-the.RAB ventilation system was improperly aligned, allowing unfiltered air to flow out of the RAD. The flow of air from areas of high potential radioactivity to ones of low potential radioactivity was possible. The corrective action taken by the licensee was effective in preventing a recurrence.
The licensee's post-accident sampling systems (PASS) were evaluated during the SALP period. Since the PASS installations in Units 1 and 2 were supplied by dif ferent vendors, the plant operators are required to be separately trained and qualified for each installation.
The evaluation found the PASS installations operable for both units, and training and procedures were :
determined to be adequate.
A special NRC inspection reviewed the circumstances surrounding an inadvertent personnel exposure while conducting sludge lancing operations in a Unit I steam generator.
It disclosed a weakness in the licensee's radiation protection program, in that informal memoranda and the experience level of the health physics technicians, rather than approved procedures, were relied upon to specify radiological protection requirements fnr maintenance activities which had high exposure potential.
This dependency-was, in large part, responsible for a Severity Level III viciation involving an overexposure to the upper arm of the whole body of a worker performing those sludge lancing operations.
The licensee denied this violation, however, on July 11, 1986, the NRC rejected the bases for the licensee's denial.
Both the on-site and the corporate health physics staffs were involved in the resolution of the technical issues surrounding the overexposure incident. investigation and assessment was deficient in that it failed to adequately address the placement of dosimetry on the arm and the dose gradient in the steam' generator handhole.
The respiratory protection and Radiat tn Work Permit programs appeared adequate; however, one proposed violation was identified in that respiratory protection equipment issuance records were not addressed procedurally as required by regulatiqn s,
and consequently, none were maintained. This proposed d'olation was issued af ter the end of the SALP period and.has no) yet been respended to by the licensee.
12 Collective personnel exposure during 1985 was approximately 637 man-rem per reactor, which was somewhat above average (425 man-rem) for U.S. pressurized water reactors (PWRs), but is not considered significant in. light of the extensive outage activity during the period. The projected collective dose for the facility in 1986 is approximately 300 man-rem per reactor.
From October 20 to December 31, 1985, 461 skin and clothing contamination events occurred.
The number of skin and clothing contamination events was noted to decrease to 64 between January 1 and April 17, 1986.
Tracking of contamination control program effectiveness was begun by the licensee during the evaluation period. On February 1, 1986, the licensee had 46,565 square feet, or 35 percent of the radiation controlled area of the plant, controlled as contaminated.
On March 31, 1986, the area controlled as contaminated increased to 51,042, or 38 percent of the plant.
It is too early to judge the effectiveness of the licensee's program for reducing the plant's contaminated area.
During 1985, the licensee disposed of 14,590 cubic feet of solid radioactive waste containing 796 curies of activity per unit.'
This represented a significant decrease when compared to the 1984 figure of 21,625 cubic feet, which was unusually large due to the disposal of the Unit 1 reactor thermal shield.
Packaging and preparation of radioactive material for transport off-site was generally adequate. However, two apparent violations of Department of Transportation (DOT) regulations were identified.
The licensee failed to package radioactive material in a strong, tight container and the radiation levels on the external surfaces of two packages in a shipment exceeded the regulatory limit.
' These violations may have been caused, in part, by a temporary reduction in health physics staff experience level brought about by personnel reassignments. The second violation was determined to be a Severity Level III violation, however, no civil penalty was assessed. These proposed violations were issued after the end of the SAtP period and have not yet been responded to by the licensee.
l The quality control program for radiological measurements met the general guidance of NRC Regulatory Guide 4.15.
Some procedural deficiencies were identified
- however, in that detailed intralaboratory and interlaboratory crosscheck implementing procedures were not formalized. The results of the 1984 and 1985 NRC spiked sample crosscheck program for iron-55 were in Generally, enforcement action is considered after disagreement.
three consecutive sample crosscheck disagreements. I Measurement discrepancies were also noted in various liquid, media for 4
13 manganese-54 and iodine-131.
In the spiked particulate filter, cobalt 57 was in disagreement, and all nuclides for the filter geometry exhibited a consistently high bias.
These results demonstrated the need for increased management involvement in the radiological measurements quality control program, to _ ensure the validity of measurements for quantifying plant effluents.
Both units operated in a very stable manner during the evaluation period, enabling the control of secondary chemistry to a standard higher than the guidelines recommended by the Steam Generator Owners Group.
Implementation of an aggressive water chemistry program was a noted strength.
The licensee was actively attempting to resolve an air ejector design problem which caused the concentration of air in the condenser hotwell to remain higher than desired.
One violation and one deviation were identified:
a.
Severity Level III violation for failure to establish radiological control procedures for steam generator work and failure to perform adequate surveys (evaluations) of individual exposure such that one worker received an overexposure of the whole body.
(335/86-01) b.
Deviation from FSAR design criteria / objectives in that RAB doors were blocked open.
(389/86-01)
Three additional proposed violations were identified during the SALP period. These violations were not issued until after the end of the SALP period and the licensee has not yet responded to the-citations.
Proposed Severity Level IV violation for inadequate procedures addressing the maintenance of respiratory -
protection equipment issuance records.
(335/86-09)
Proposed Severity Level III (with no civil penalty) violation for failure to maintain radwaste shipment external radiation levels within limits.
(335/86-09)
Proposed Severity Level IV violation for failure to package radioactive material in a strong, tight shipping container.
(335/86-09) 2.
Conclusion h
Category:
2 e
14 3.
Board Recommendations The Board noted a decrease in +.5e effectiveness of the licensee's program for the transportation of radioactive material, which may have been caused, in part, by personnel changes which reduced the experience level of the health physics staff ar.d by the lack of detail in transportation procedures.
The licensee should give increased attention to this area, and the NF.C should increase its inspection activity.
J C.
Maintenance 1.
Analysis During the evaluation period, inspecticns were performed by the resident and regional inspection staffs.
Licensee management continued to seek improvements in the maintenance program, and emphasized adherence to procedural and regulatory requirements.
This resulted in a decrease in the -
number of violations identified during the SALP period.
The excellent Unit 1 performance record since ccepleting the repairs to the core support barrel and removing the thermal shield is another indication of the quality of maintenance activities.
Maintenance staffing and training were adequate.
The plant work order (PWO) backlog at St. Lucie appears to be under control.
The licensee subscribes to the Institute of Nuclear Power Operations guideline that no more than 50 percent 6f the outstanding PW0s be greater than three months old.
In ~
comformance with that guideline, the number of PW3s more than three months delinquent was noted to drop significantly.
The licensee's routine maintenance program utilizes a number of techniques to monitor equipment performance and analyze failures.
The program uses vibration analyses on mechanical equipment, infrared analyses on electrical equipment, oil analyses on selected components (e.g., emergency diesel generators), and the Motor Operated Valve Analysis and Testing System (MOVATS) to determine the operability of motor operated valves.
These techniques have enabled the licensee to detect degrading trends in equipment performance and effect repairs before failures occur.
Management responsiveness to NRC initiatives remained at the previously established high levels discussed in th;e last SALP report and was evidenced by the continuation of the operating experience feedback program. Additionally, the licensee, on its own initiative, has established a Quality Improveinent Program
IS (QlP) which encourages the direct involvement of craf tsmen and technicians in achieving, maintaining and improving quality. The participation of these working level individuals has had a positive effect because they can make inputs to management and observe improvements brought about by their efforts.
Maintenance activities involving the reactor coolant pump oil seals and anti-reverse rotation devices (ARRD) were also reviewed.
The degradation of these components were quickly identified and proper corrective action was promptly initiated. Site management readily committed to formal reports to the NRC as investigation and assessment results were compiled.
A special inspection to assess the licensee's compliance with Generic Letter 83-28 raised concerns regarding the preparation, review, approval, and implementation of reactor trip breaker maintenance procedures.
The licensee's proposed corrective measures for these c6ncerns were judged to be adequate.
The licensee's programs for reactor trip system post-maintenance testing and equipment classification were found to meet the.
requirements of the Generic Letter.
No violations were identified during the assessment period.
2.
Conclusion Category:
1 3.
Board Recommendations The board noted that the Category I rating was based on a limited inspection effort which failed to reveal any significant deficiencies.
D.
Surveillance 1.
Analysis During the evaluation period, inspections were performed by the resident, regicnal and headquarters inspection staffs.
The regional staff performed in:pections of the surveillance testing, calibration control and snt.bber surveillance programs, and the headquarters staff performed a special !.ivironmental qualification program inspection.
The surveillance testing programs appeared effective. Technical Specification survetilances were almost always co41eted in a timely manner.
No instances of using out-of-date, surveillance procedures were identified during the evaluation period.
Management involvement in staffing and training for operational surveillances continued to be adequate.
16 Though surveillance scheduling and implementing procedures were generally effective, four cases of missed surveillances, which occurred near the end of the evaluation period, indicated a program weakness in the scheduling of plant surveillances during the reassignment of plant personnel.
The licensee identified these cases and has vigorously implemented measures to correct the missed surveillance problem.
Plant Quality Centrol (QC) audited the departments responsible for conducting surveillances to ensure that an adequate and timely method of verifyir; the completion of surveillances existed within the responsible departments.
This review determined that three of the nine depa-tments involved ir.
the performance of TS surveillances lacked seneduling procedures and two lacked an individual directly responsible to oversee or review the conduct of_surveillances..The licensee has implemented three new scheduling procedures, and the two deficient procedures have been revised to include sign-offs for internal, departmental reviews. While the results cannot be judged at this time, it is expected that this added visibility and the delineation of responsibility will improve the conduct of surveillance testing.
A special inspection to assess the licensee's compliance with Generic Letter (GL) 83-28 found that trip system reliability testing met the intent of the GL. The licensee's trending program for critical reactor trip breaker parameters was found not to include all the parameters reconmended by NRR, and their response to a request from NRR for more information on their trending program was not timely.
The calibration program was effective in raintaining current instrument calibrations.
Problems were identified, however, irt that gauges required for inservice inspectior (ISI) calibrations were not included in the calibration program and the ISI vibration monitoring program was inconsistent.
The remaining areas of this-program appeared effective.
Snubber surveillance program planning was evident in the well-defined and written procedures.
Policies were adequately stated and understood, and reviews were timely, thorough and technically sound.
Records of snubber inspection results were complete, legible and readily retrievable on a personal computer system.
The resolution of problems encountered during snubber surveillance inspections (functional test failures) were conservative, timely, technically sound and thorough.
- Staffing, training and qualification of personnel involved in snubber surveillance were adequate.
A special inspection determined that the licensee ha implemented a program to establish and maintain the environmentgl qualifica-tion of equipment within the scope of 10 CFR 50.49.
Although there were some potential problem areas in procurement and
17 maintenance, there were no findings affecting the safe operation of the plant.
The findings were typical of findings during similar inspections at other Region II facilities.
Two violations were identified:
a.
Severity Level IV violation for missed surveillances (four examples).
(86-07/06) b.
Severity Level IV violation for failure to correct battery specific gravity for electrolyte level. (85-08) 2.
Conclusion Category:
1 Trend: Declining 3.
Board Recommendations The Board expressed a concern regarding the decrease in surveillance program effectiveness during a period of personnel The same problem was noted to have occured in the transition.
radioactive waste transportation program and indicates a need for increased management oversight during future staff changes.
E.
Fire Protection 7
1.
Analysis this assessment period, inspections of the licensee's During routine fire protection and prevention program were conducted by the regional and resident inspection staffs.
In addition, a special Unit 2 inspection was conducted by the regional staff to assess the status of the licensee's implementation of the requirements of 10 CFR 50, Appendix R.
The licensee's routine fire protection and fire prevention program was found to be satisfactory. The licensee has issued procedures for the administrative control of fire hazards within the plant.
From a fire protection standpoint, housekeeping and control of flammable materials were satisfactory.
The fire protection extinguishing systems, detection sy st *;ns, fire barriers and barrier penetrations were found to be in service.
Procedures for the surveillance inspection, testijg and main-tenance of the plant's fire protection systems and equipment have been established and implemented.
The fire, protection features have been satisfactorily tested and maintained.
18 The licensee has also established procedures governing the organization and training of the fire protection staff and the fire brigade. The fire brigade training program was well defined and fully implenented.
The training and drills for the fire brigade members met the frequency specified by the licensee's procedures and the NRC's guidelines.
The licensee -has established an on-site fire brigade training facility, which presently consists of flammable liquid burn pits utilized for portable fire extinguisher and small fire attack hose line training operations.
It is the licensee's intent to expand this facility in the future to include structural power plant firefighting tnd self-contained breathing apparatus training operations.
Fire protection staffing was adequate to accomplish the goals of the licensee's program.
The fire protection staff positions are identified, and authorities and responsibilities are clearly defined.
The personnel assigned to these positions are well
(
qualified for their assigned duties.
The crganization and,
staffing of the plant fire brigade met NRC guidelines.
T The inspectors reviewed the annual fire protection / prevention audit, the 24 month QA fire protection program audit by of f-site organizations and the triennial audit by an outside fire protection organization required by the Technical Specifications.
These audits were conducted within the specified frequency and appeared to cover all the essential elements of the fire protection program.
The licensee had implemented appropriate corrective actions for discrepancies identified by these audits.-
During a routine inspection, the licensee's QA staff found that an hourly fire watch required by the Technical Specifications had not been performed for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during the bargaining unit walkout on-April 28,1986.
The incident was reported as required, and the applicable procedures were revised to preclude recurrence.
In preparation for the special Appendix R inspection the licensee identified, analyzed, and reported the Appendix R,Section III.G discrepancies as required by Unit 2 operating license condition l
2.c.13.
In these reports the licensee stated that the require-I ments of Appendix R,Section III.G.2, had not been met in the Unit 2, Train "B" switchgear room and cable loft.
The NRC reviewed these reports and determined that the licensee-identified Appendix R discrepancies were significant with respect maintaining one train of safe shutdown capability free from fire. damage. The licensee's compensatory actions and approach to re@lving these discrepancies were, however, found to be satisfactory.
19 In addition, the NRC's Appendix R ' inspection found that the licensee's alternative shutdown procedure for fire in either the control room or the cable spreading room was in error. The two procedural errors could have affected the safe implementation of alternative shutdown capabilities on Unit 2.
The licensee also failed to fully implement the control / cable spreading room alternative shutdown procedure required by license condition 2.C.13.
The licensee demonstrated a clear understanding of the Appendix R alternative shutdown procedure issues, and their approach to resolving these issues was technically sound, timely and responsive to NRC requirements.
In general, management involvement and control in assuring quality in the routine fire protection program was adequate as evidenced by the issuance and implementation of fire protection procedures that met the NRC's requirements and guidelines.
The licensee's approach to the resolution of routine technical fire protection J
issues indicated a clear understanding of the issues, and'was practically always technically sound and timely.
Responsiveness to NRC initiatives was technically sound and thorough in almost, all cases.
In addition, violations against the routine fire 7 protection and prevention program are rare.
Three Appendix R related violations were identified:
a.
Severity Level III violation for failure to provide adequate fire protection features for a safe shutdown system necessary to achieve and maintain hot standby.
(389/85-06) b.
Severity Level IV violation for procedure errors which could affect the safe implementation of alternative shutdown capabilities.
(389/85-06) c.
Severity Level IV violation for failure to fully implement.
Appendix R. as required by license condition 2.c.13.
(389/85-06) 2.
Conclusion Category: 2 Trend:
Improving 3.
Board Recommendations No changes in the NRC's inspection resources are recammended.
I P
y y-wy w
e
20' F.
Analysis During the. assessment period inspections were performed by the regional and resident-inspection staffs.
This included one routine inspection and the observation of two annual emergency preparedness exercises.
The routine inspection found that the essential elements for emergency response were adequately implemented.
Walk-throughs conducted with plant staff members assigned positions of responsibility in an emergency showed that they were able to recognize emergency action levels, correctly classify events, develop correct protective action recommendations, and that they were knowledgeable of off-site notification methods.
A communication system that would allow prompt notifications and communications to off-site agencies was in place and operable.
The public information program appeared to provide necessary information to the public in the form of brochures and through, speaking engagements.
An adequate system for shif t staffing anB augmentation was provided through a duty officer / roster system.
Walk-throughs of dose projection and assessment problems demonstrated the licensee's ability to prcmptly obtain acceptable results.
Although no violations, deviations, or significant negative findings were identified during the routine inspection, the licensee's demonstration of its ability to adequately implement the emergency plan and procedures during the annual emergency-exercises showed a basic flaw in command and control.
The 1985 emergency exercise identified procedural conflicts in that the Emergency Plan and implementing procedures would not allow the Emergency Coordinator to delegate the responsibility for emergenc-y declaration, off-site notifications, protective action recommendations, and radiological dose assessment, while other documents permitted such delegation.
The licensee was informed that these inconsistencies in the assignment of responsibility could potentially lead to confusion, duplication of effort, or non performance of certain functions.
The licensee did not correct this potential problem after the 1985 exercise.
The 1986 emergency exercise confirmed that these inconsistencies remained.
This resulted in actual fragmentation of command and control and contributed to the following problems:
a failure to notify the NRC Operations Center ok the General Emergency classification; P
21 4
4 less.than full involvement of the Technical Support Center (TSC) staff in accident mitigation; 4
poor information flow to the Recovery Manager, including a delay of 45 minutes in informing Lthe Recovery Manager that the core was uncovered; and a delay in the flow of information to the Emergency i
Operations Facility (E0F).
These difficulties developed during an exercise with a scenario i
that was not particularly taxing. The licensee acknowledged these findings during the NRC critique following the exercise.
During subsequent discussions, the licensee's corporate emergency planning staff proposed corrective actions, including procedural revisions and special emphasis on communications training, which, if properly implemented, should resolve the exercise problems.
No violations were identified during the assessment period.
.2.
Conclusion Category: 2 3.
Board Recommendations Additional licensee management attention is necessary to ensure that the problems associated with the delegation of authority are j
resolved and do not recur during future exercises.
G.
Se:urity and Safeguards 1.
Analysis Inspections during this evaluation period were performed by the resident and regional inspection staffs.
There was evidence of management involvement and control of the security program.
Managerial interest and response to security-related issues and problems were generally technically sound and consistent, demonstrating the existence of policies and procedures for control of security-related activities.
The licensee's security organization consists of a security management function and a contract guard force.
The security staff manning and performance capa ility i s considered adequate to implement the physical protection program as committed to in the Physical Security Plan despite a slightly y
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22 higher than normal turnover rate. The training and qualification of the guard force to perform routine security as defined in the training and qualification plan is also judged to be adequate.
The contract guard force training officer is also utilized in a compliance verification role.
Two apparent violations demonstrated the need for more security awareness on the part of the technical and operational staffs.
One violation, involving the failure to control access to vital equipment was initially identified by the NRC during the SALP period.
AS a corrective action for this violation the licensee initiated a survey to revalidate all identified vital equipment.
This survey, which was in progress at the end of the SALP evaluation period, led to the discovery of two instances in which equipment identified as vital in the Physical Security Plan was not enclosed within a vital area. This resulted in an additional apparent violation.
The licensee's failure to detect these violations resulted from a lack of communication between the plant operating staff and security personnel, and inadequate procedureg and training of security force members to recognize and respond appropriately to vital area barrier degradations.
These violations could have been avoided with better interfacing and cross-training between security and non-security organizations.
Both violations are under consideration for escalated enforcement action.
Safeguards event reports were timely and accurate and adequately addressed appropriate corrective actions, the implementation of which account for the absence of repetitive incidents.
Changes to the Physical Security Plan were submitted within the time frames specified in 10 CFR 50.54(p), and the licensee was responsive to NRC Region II comments on those Plan revisions.
The licensee's independent security program quality assurance auditors are permanently assigned unescorted vital area access and are aware of security requirements while conducting other audits.
One violation was identified:
Severity Level IV violation for failure to secure an unattended vehicle.
(85-01) 2.
Conclusion Category:
2 h
3.
Board Recommendations No changes in the NRC's inspection resources are recommended.
.-.-n-.-
,-----g w-
23 H.
-Outages 1.
Analysis During this evaluation period routine inspections were performed by the resident and regional inspecticn staffs.
Refueling was performed on both units.
The regional inspection effort focused on Unit I refueling activities and re,iews of the licensee's inservice inspection (ISI), inservice test (IST) and measuring and test equipment (M&TE) programs.
Routine inspections by the resident inspectors addressed the areas of preparation for refueling, receipt and handling of new fuel, Unit 1 core support barrel inspection, steam generator eddy current testing, in-core instrument. replacement, reactor cavity seal ring design and testing and refueling activities. All activities appeared to be well managed.
During this evaluation period, licensee management has continued to focus attention on preventive measares and planning in an effort to anticipate occurrences.
For example, the licensee is.
continually planning for unscheduled shutdowns and outages.
AT current list of action items requiring a mode of operation other than power operation is maintained, work packages are prepared and parts are ordered in advance.
When forced into an unplanned shutdown, there is little time wasted in planning and scheduling this contingency work. This allows a clearer focus on correction of the cause of the forced shutdown ard minimizes the facility's backlog of " shutdown items."
Plant safety and reliability are enhanced and the length of scheduled octages is shortened.
The licensee has been very successful in planning and implementing scheduled outages. Outages have usually been completed within a few days of the schedule.
Even when unexpected problems have occurred the licensee has demonstrated the necessary flexibility to make schedule changes and still co plete the outage within a reasonable time span.
This was particularly apparent during the Unit 1 outage in the fall of 1985 wher problems were encountered in lifting the upper guide structure. The licensee took actions to minimize the incidents impact on the critical path of the outage.
The Unit 1 core suppo*t barrel inspection revealed no degradation in the repairs implemented during the p#evious refueling outage.
Fif teen damaged Unit I fuel pins were removed and replaced with solid, unfueled pins.
Additional fuel failures have been experienced since the unit was restabted in Decembbr 1985 and indicate a possible inadequacy in the licensee's failure analysis.
4 l
5I i
24 The licensee did not search for debris in the lower fuel assembly grids until af ter the damaged pins were removed. This may have obscured any indications of potential debris-induced fretting in that area.
The licensee should implement a more detailed and disciplined search for fuel failure mechanisms during the next refueling outage.
While removing the Unit I core internals upper guide structure (UGS) in preparation for defueling, one of three lif ting rig attachments gave way. This placed the UGS and lif ting rig in a tilted position suspended about eight feet above the irradiated fuel. The licensee declared an unusual event in accordance with plant emergency procedures. It is believed that this failure was caused by inadequate thread engagement on one of the three bolts which attaches the lifting rig to the UGS. The bolt was assumed to be fully engaged when the torque limit specified in the procedure was reached.
The procedure was inadequate (see violation (a)) in_ that no independent verification method was required to ensure that the bolt was not cross-threaded or otherwise bound, thereby creating a false seating indication.
,~
Management involvement was evident in the prompt and efficient mobilization and direction of appropriate resources in designing, manufacturing, testing and employing a temporary lif ting rig for removing the UGS.
These actons were taken in a tirrely manner to ensure that a potentially hazardous situation was corrected without unnecessary delay, while at all times maintaining controls to ensure that an already tenuous situation did not degrade further and cause additional damage.
A regional inspector witnessed Unit I defueling activities from the control room, refueling floor and spent fuel pool area, and found that defueling was performed in accordance with the controlling procedure.
Management involvement in refueling activities continued to be strong and effective, both during routine operations and during the unusual event described above. Total team refueling meetings were held twice daily and were effective in mairtaining control of critical path refueling activities. Staffing during refueling n.et or exceeded the Technical Specification requirements. The one-day strike on April 28, 1986, had little or no impact on the Unit 2 refueling progress because of prompt management control and placement of personnel.
Unit 2 completed its second refueling outage and returned to power on June 4,1986.
Violation (c)involvedafailuretoinstallsafety-rhlatedbattery racks in accordance with approved drawings. This was considered to represent an isolated instance of inadequate drawfng references in the Plant Change / Modification package and not a breakdown of
~
the design change program.
25 Licensee maragement involvement in inservice inspection (ISI) and inservice testing (IST) activities appeared to be adequate and decision m2 king was at a level that assured adequate management review. The ISI manual and implementir.g procedures continued to be upgraded by site and corporate management thereby improving control of the ISI program.
Because of a change in organization, the ISI Coordinator now reports to.the Technical Department rather than the Maintenance Department. The effect of this change on the ISI organization has not yet been evaluated.
Key positions within the organization were identified, and authorities and responsibilities were defined.
The ISI manual now defines responsibilities for ISI work.
The licensee's ISI/IST-program reviews were timely, thorough and technically sound.
Records were complete, well maintained and available.
A training program for all personnel involved in ISI was cefined, and implemented.
7 One minor IST procedural violation (d) was identified during the evaluation period. The violation was not repetitive and is not indicative of a programmatic breakdown.
The regional inspection of the M&TE program found it to be adequate overall.
Some inconsistencies in documentation were noted and a violation was identified for a failure to control the environmental conditions in the calibration laboratory.
Four violations were identified:
a.
Severity Level IV violation for inadequate procedure for -
removal of the upper guide structure.
(335/85-29) b.
Severity Level IV violation for failure to provide adequate measures for environmental conditions for calibration of M&TE.
(85-16) c.
Severi ty Level IV violation for failure to install safety-related batteries in accordance with applicable drawings.
(85-08) 1 d.
Severity Level V violation for failure to enter pump test status in control room " Pump and Valve Summary" book.
(85-04) l P
26
-2.
Conclusion Category:
2 3.
Board Recommendations No change in the NRC's inspection resources are recommended.
I.
Quality Programs and Administrative Controls Affecting Quality Analysis During this evaluation period, inspecticns were performed by the resident and regional inspection staf fs. The following areas were
. reviewed by the regional inspection staff: _ quality assurance (QA) program review, audits, records, document control, QA/ quality control (QC) administration, off-site support staff, and off-site review committee (Company Nuclear Review Board).
The licensee has instituted a Commitment to Excellence Program.
(CEP) which was a spin-off of the Performance Enhancement Program at Turkey Point.
The CEP included the following QA/QC enhancements:
increase QA staff size (four additional positions to be filled),
increased QA personnel training, increased QA technical expertise (one recently hired QA employee was a licensed operator),
improved communicaticn between QA and site personnel, trend analysis and reporting, performance monitoring to address plant systems / hardware and real time operating activities, expanded CA and QC surveillance programs, and QA audits to assure that CEP commitments are being met.
A number of QA implementing procedures have also been rewritten to more accurately reflect program requirements.
Site personnel 1
appeared knowledgeable about these program enhancements, f
The implementation, scope, and findings of QA audits were found to be adequate. A problem was identified which reflected that audits i
of surveillance activities were not performed to the depth
-e 27 necessary to assure calibration activities were being properly performed. This appeared to be an isolated example. Records and document control programs were assessed as adequate.
The QA/QC administration was determined to be adequate.
Closecut and I
corrective actions for NRC identified violations was timely.
The special inspection to assess compliance 'with GL 83-28 found licensee management to be actively involved in assuring quality and to be reasonably responsive to NRC initiatives regarding reactor trip system operation, maintenance,
- testing, and reliability.
Management involvement was evident in the development, review, and, in most cases, timely submittal of responses required by the GL.
The off-site support staff program met existing regulatory requirements. The training of personnel appeared adequate to ensure technical competence.
Interface between off-site and on-site staff appeared adequatt. Greater efficiency in providing support services was achieved by assigning off-site organizational staff to the site. The off-site review committee was adequate in, fulfilling the function of the committee charter.
T No violations were identified during the appraisal period.
2.
Conclusion Category: 2 3.
Board Recommendations No changes in the NRC's inspection resources are recommended.
J.
Licensing Activities 1.
Analysis During the SALP evaluation period, the licensee continued to show significant management overview in the area of licensing activities.
The licensee consistently balances the desire to maintain or improve plant productivity with the need to protect the health and safety of the public.
The majority of the licensing actions completed during the SALP period were resolved by the licensing group. In the few ins *nces where matters needed to be referred to upper management, the managers involved proved to be well-informed and helpful in resolving questions.
Upper management has also become deeply involved in improving the quality of the work done at the plant by actively pari.icipating in the development of a quality improvement program. The licensee's management has continued to pursue a program that i's aimed at
~
improving and increasing the technical capability of the staff.
^
1-28
, ~-
?The licensee's submittals are most often timely and of high quality.
In particular, the licensee's treatment of the no significant hazards standards of 10 CFR 50.92 have shown a steady and marked improvement during the reporting period.
-There were some instances during the period when submittals were not made in a timely manner.
This occurred most frequently on requests for action on items required for restart after refueling outages.
The licensee needs to improve their performance in this crea.
The licensee also needs to improve in areas where information or action is required on matters that do not have an immediate impact on plant operation.
In particular, such areas include nonpriority items that are part of requirements generated by operating experience, Generic Letters, Information Notices, etc.
The need for changes in the diesel generator Technical Specifications is a prime example.
With few exceptions, the technical content of submittals made in support of, or in response to licensee or NRC initiated actions is complete and thorough.
Where additional information has been needed, it has been of a clarifying nature, for the most part, aid in many cases handled by phone with a confirmatory follow-up letter.
Few, if any, licensee responses to NRC requests for additional information require subsequent questions.
The licensee continues to maintain a significant technical capability in almost all engineering and scientific disciplines necessary tu resolve items of concern to the NRC.
During the report period, the licensee has expanded the staff at the plant site as well as the main office in Miami and the subsidiary office in Juno Beach.
The licensee has also utilized the services of nuclear support groups to assist in the resolution of technical problems or to utilize both new and proven techniques that will enhance the operation and safety of the plant.
During this period, the licensee has decided to consolidate the majority of its nuclear engineering support staff into a single office complex in Juno Beach.
This consolidation should improve the support capability provided to the St. Lucie plant, particularly in the reduction in response time required to resolve technical issues.
Licensee management supported a number of NRC initiatives, most notably a site visit dealing with a residual heat removal generic issue.
During the period, the licensee worked with the NRC in resolving a number of multi plant and TMI items.
In each case, gjestion and the licensee carefully evaluated the action in provided meaningful input to the NRC staff. Where differences of opinion have occurred, the licensee has negotiated, changes in requirements to insure that the results (Technical Specifications, for example) reflect the plant design.
29 The licensing group holds informal training sessions on topics of current and future interest.
The group also participates in corporate-wide training programs such as, " Supervisor Training for Quality". The training program, measured by results, has been very effective during this rating period. and is about to be evaluated by INPO for program accreditation.
2.
Conclusion Cate' gory:
1 3.
Board Recommendations No changes in the NRC's inspection resources are recommended.
K.
Training and Qualification Effectiveness 1.
Analysis No formal inspections of the St. Lucie training program were -
conducted during this SALP period.
Routine inspections by the' regional staff did, however, touch on training of personnel in several specific areas, including health physics, fire brigade, security, ISI technicians, quality assurance staff, maintenance, and licensing. These inspections did not note any deficiencies in the areas reviewed.
Two sets of replacement operator licensing exams were administered.
Four of five senior reactor operator (SRO) candidates and five of five reactor operator (RO) candidates -
passed the oral and written examinations administered in February - March 1985.
The oral and written examinations administered in December 1985 resulted in six of seven SRO candidates and ten of ten RO candidates passing. The SR0 and R0-passing rates of 83'4 and 100*;, respectively, were above the industry average, and provide evidence of management's involvement in the training process and in the screening of prospective license examination candidates.
Six new Shift Technical Advisors (STAS) were qualified during the evaluation period, and there are presently four new STAS in the qualification program.
A training simulator has been ordered and is scheduled to be installed by late 1986 in a new training facility which is currently under construction at the site.
f No violations were identified during the appraisal peyiod.
2.
Conclusion Category:
1
30 3.
Board Recommendations
-No changes in the NRC's inspection resources are recommended.
V.
Supporting' Data and Summaries A.
Licensee Activities The scope of major outage work at St. Lucie was as follows:
Unit 1 10/20/85 - 12/25/85 Scheduled refueling / maintenance, inspection of core support barrel Unit 2 10/12/84 - 11/19/84 Scheduled refueling / maintenance 11/21/84 - 11/29/84 Turbine bearing problems 12/19/84 - 12/27/84 Condenser air leak 08/08/85 - 09/07/85 RCP seals, high vibration & oil leaks 09/09/85 and 09/22/85 04/05/86 - 06/04/86 Scheduled refueling / maintenance i
i B.
Inspection Activities The routine inspection program was performed during this period, with special inspections conducted to augment the program as follows:
1.
February 25 - March 5,1985, in the areas of liquid and gaseous radwaste management, environmental programs, and evaluation of NUREG-0737, Item II.B.3, Post-Accident Sampling System (PASS).
2.
February 25 - March 1,1985, in the areas of fire protection and the licensee's actions regarding the implementation of the requirements of 10 CFR 50, Appendix R, Se:tions III.G, III.J,.
III.L and 111.0.
3.
July 8-12, 1985, concerning FPL's response to Generic Letter 83-28, Required Actions Based on General Implications of Salem Anticipated Transient Without Scram (ATWS) Events.
Areas i
inspected included:
post-trip reviews, equipment classification, vendor interface and manual controls, post-maintenance testing, and reactor trip system reliability.
4.
August 19-21, 1985, on-site and in the General Office in the areas of emergency preparedness, emergency response facilities, NRC response team coordination, and NRC hurricane response equipment, coordination and procedures.
[
t l
l
- -... - ~.
4 31 5.
January 8-9, 1986, in reaction to a potential whole body radiation exposure in excess of 10 CFR 20 limits.
6.
January 21-22, 1986, to follow-up on previously identified findings in-the area of fire protection.
7.
March 31 - April 4,1986, in the area of equipment environmental qualifications.
C.
Licensing Activities The basis for this appraisal was the licensee's performance in support of. licensing actions that were completed during the current rating period.
These actions consisted of amendment requests, exemption requests, responses' to Ger.eric Letters, TMI items and other actions, as shown below.
1.
Licensing Activities Completed During the SALP Period License Condition Compliance Concerning Heavy Loads (St.
Lucie 2)
T l
Purge and Vent Valve Operability (St. Lucie 1) 1 Environmental Qualification of Electrical Equipment (St.
Lucie 1) i EXXON Nuclear Creep Collapse Methodology (St. Lucie 1)
Control of Heavy Loads, Phase I (St. Lucie 1)
Axial Growth of Fuel Rods (St. Lucie 2)
PASS Core Damage Assessment Procedure (St. Lucie 2)
Control of Heavy Loads, Phase I (St. Lucie 2)
Underground Cable Insulation (St. Lucie 1)
Safety Parameter Display System (St. Lucie 1 & 2)
Inadequate Core Cooling Instrumentation (St. Lucie 1 & 2)
NUREG-0737, Generic Letter (GL) 83-37 (St. Lucie 1 & 2) 4 Code Error in EXXON Analysis (St. Lucie 1)
I LOCA Outline, Compliance with 10 CFR 50.46 (St. Lucie 1 & 2)
32 Masonry Wall Design (St. Lucie 1)
Control of Heavy Loads, Phase II (St. Lucie.1 & 2)
GL 83-28, Items 3.1.3 and 3.2.3 (St..Lucie 1 & 2)
Use of Instrumented Inspection Technique (St. Lucie 1)
ASME Code Update (St. Lucie 1 & 2), 10 year Inspection Interval (St. Lucie 1)
Steam Generators GL 85-02 (St. Lucie 1 & 2) 4 GL 83-28, Items 3.1.1, 3.2.1, 3.2.2, 4.1 and 4.5.1 (St. Lucie 1 & 2)
GL 83-28, Item 1.1 (St. Lucie 1 & 2) 15 Percent Steam Generator Tube Plugging (St. Lucie 1)
}
GL 83-28, Item 1.2 (St. Lucie 1 & 2)
I-GL 83-28, Item 3.1.2 (St. Lucie 1 & 2)
CE Large Break LOCA Analysis (St. Lucie 2) 2.
NRR - Licensee Meetings November 9, 1984 Cycle 2 Reload
~
June 4, 1985 Core Support Barrel Inspection Plan July 10, 1985 LOCA Error Septembe-11, 1985 Cycle 7 Reload September 24, 1985 Instrument Inspection Technique September 26, 1985 Security System October 22, 1985 Rod Swap and Cycle 7 Technical Specifications October 30, 1985 LOCA Error (follow-up to July 10)
December 18, 1985 Security System l
December 19, 1985 Detailed Control Room Design Review February 4,1986 CSB Inspection Results~
d
__.-_..,.._..___~.__.-_m.,
i 33 l
3 ~.
-NRR Site Visits November 1-2, 1984 Cycle 2 Outage Activities, St. Lucie 2.
November 12-14, 1984 Cycle 2 Startup Testing and Plant 4
Activities, St. Lucie 1 and 2
. December 10-13, 1984 Visit Concerning Generic Issue A-45 February 25-28, 1985 Fire Protection Audit April 10-15, 1985 Site-Visit Concerning Cycle 7 Planning, St. Lucie 1 4
June 19-20, 1985 Meeting with Region II to Discuss Licensing Actions October 6-11, 1985 Pilot Audit of St. Lucie SPDS November 17-22, 1985 Core Support Barrel Inspection and?
Cycle 7 Activities, St. Lucie 1 January 20-25, 1986 Appendix R and Generic Issue A-45 l
Reviews March 4-6, 1996 Security System April 20-23, 1986 Cycle 3 Outage Activities, St. Lucie 2 4
Commission Briefings 2
None 5.
Schedule Extensions Granted None 6.
Reliefs Granted April 2, 1985 IST of Pumps and Valves, St. Lucie 1 January 13, 1986 IST of Pumps and Valves, St. Lucie 2 7.
Exemptions Granted f
Februa ry 21, 1985 10 CFR 50 Appendix R - Fire Protection, I
i St. Lucie 1 1
4
_. -,,. ~.
34 8.
License Amendments Issued St. Lucie 1 December 6, 1985 License Amendment 69 - Changes required by 10 CFR 50.72 and 50.73 and miscellaneous changes in definitions and administrative controls December 12, 1985 License Amendment 70 - Change to linear heat generation, rate LCO from a constant value to an axially dependent limit January 15, 1986 License Amendment 71 - Allows continued operation at rated thermal power for a specific time following a dropped control assembly January 15, 1986 License Amendment 72 - Adds auxiliary feedwater actuation system instrumen-tation to the Technical Specification)
St. Lucie 2 November 9, 1984 License Amendment 8 - Technical Specifi-cation changes associated with Cycle 2 March 1, 1985 License Amendment 9 - Allowed power increase from 2560 MWt to 2700 MWt March 15, 1985 License Amendment 10 - Changed valve tag numbers in continuous purge and station air system October 17, 1985 License Amend ent 11 - Modified surveil!
lance requirements with regard to reconnection of pressurizer heaters to their respective buses November 14, 1985 License Amendment 12 - Limits the use of the 8-inch containment purge system December 6, 1985 License Amendment 13 - Changes required by 10 CFR 50.72 and 50.73 and miscel-laneous changes in definitions and administrative controls April 28, 1986 License Amendment 14 - Chan es to moderator temperature coefficient to provide more operating flexibility and remove restrictive operational require-ments above 70 percent power 1
- - - - = -
...~
.~
9
-35 9.
Emergency Technical Specifications Issued None 10.
Orders Issued June'27, 1985 Order Modifying license ceii(irming-f additional licensee commitments on emergency response capability a
(Supplement 1 to NUREG-0737) 11.
Status of Licensing Backlog At the conclusion of the SALP period, the licensing backlog consisted of the following items:
St. Lucie 1 TMI Related 9
i MPA 11
?
Plant Specific 7
St. Lucie 2 TMI Related 6
MPA 10 Plant Specific 16 D.
Investigations and Allegation Review No significant investigations were conducted during this evaluation period.
E.
Escalated Enforcement Actions 1.
A Severity Level III (Supplement I) violation was issued on May 22, 1985, for f ailure to provide fire protection features to ensure that Unit 2 systems necessary to achieve and maintain hot shutdown conditions are maintained free from fire damage. A civil penalty was not imposed because FDL discovered the problem, recorted it promptly, and took decisive action to preclude its recurrence, e
1 2.
A Severity Level III (Supplement IV) violation was issued on April 24, 1986, for failures to establish radiological control procedures for steam generator work and to perform adequate individual exposure evaluations during that work. A(civil penalty imposed because of FPL's good prior performance in the was not area of concern.
f i
=.
d 36 3.
One order was issued as noted in paragraph V.C.10.
F.
Licensee Conferences Held During Appraisal Period 1.
January 22, 1985 -
Management meeting in preparation for the 10 CFR 50 Appendix R inspection Enforcement Conference regarding 2.
March 28, 1985 10 CFR 50, Appendix R violations and inoperable containment isolation valves 3.
February 26, 1986 -
Enforcement Conference to discuss a potential overexposure during steam generator sludge lancing G.
Confirmation of Action Letters CAL 50-335/85-01 was issued on September 4,1985, to document the NRC's concurrence with FPL's commitment to administratively restrict the
. Linear Heat Generation Rate to 14.0 kw/ft for the remainder of Cycle p 7
for St. Lucie Unit 1.
H.
Licensee Event Report Analysis During the assessment period, 15 LERs for Unit 1 and 21 LERs for Unit 2 were analyzed by the NRC staff to determine cause. The distribution of these events was as follows:
Number of LERs Cause Unit 1 Unit 2 Component Failure 2
9 Design 2
Construction, Fabrication, Installation 2
1 Personnel
- Operating Activity 2
3
- Maintenance Activity 3
4
- Test / Calibration Activity 3
2 1
- Other Activity Other 1
1 TOTAL 15 h 21
)
l e
i
..=. -
37 1
I.
Enforcement Activity Unit Summary FUNCTIONAL AREA NO. OF DEVIATIONS AND VIOLATIONS IN EACH SEVERITY LEVEL D
V IV III II I
4 UNIT NO.
1/2 1/2 1/2 1/2 1/2 1/2 l
Plant Operations 0/1 2/2 Radiological Controls (*).
0/1 1/0 5
Maintenance' s
Surveillance 2/2
,1 Fire Protection 0/2 0/1
. Emergency Preparedness Security 1/1 Outages 1/1 3/2 1
. Quality Programs and Administrative Controls T
Affecting Quality Licensing Activities-Training Total 0/1 1/2 8/9 1/1 Facility Summary FUNCTIONAL AREA NO. OF DEVIATIONS AND VIOLATIONS IN EACH SEVERITY LEVEL D
V IV III II I
Plant Operations 1
4 Radiological Controls (*)
1 1
Maintenance Surveillance 2
i Fire Protection 2
1 Emergency Preparedness Security 1
Outages 1
3 Quality Programs and Administrative Controls Affecting Quality Licensing Activities l
Training Total 1
2 12 2
(*) Additional apparent violations' were issued after the end of the i
SALP period as discussed in the Radiological Controls analysis.
l 4
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k
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38
- + ey
,9 yo J.
/a A
.Three unplanned reactor trips and two manual shutdowns occurred during y
rd this evaluation period for Unit 1.
Unit 2 sustained 16 unplanned trips 7
3 i
M-and seven manual shutdowns. The unplanned trips are listed below, 1.
Unit 1 c
g
/.-
,n a.
December 19, 1984 - The reactor tripped from 100 percent N
power on a low steam generator (SG) water level signal. The g;
./
"B" diesel generator breaker was being racked out for inspection when a failed relay actuated the breaker's closing
%f i
spring, closing the breaker and thereby motorizing the "L'
[7
- generator.
The ensuing electrical system realignment 4
resulted in the loss of a main feedwater pump and the low SG V e(.
level. The faulty relay was repaired prior to restarting the 4g 9
plant.
N b.
March 7, 1985 - The reactor tripped as a result of a suspected operator error while performing a routine reactor protection system logic matrix test. All systems functioneB r
normally and the plant was returned to service in about seven hours. The trip was subsequently found to have resulted from a faulty matrix relay trip select switch (see next paragraph),
i c.
February 6, 1986 - The reactor tripped from full power while operations personnel were performing the monthly reactor protection system logic matrix test. The trip was caused by a faulty matrix relay trip select switch.
The switch was-replaced and the logic matrix test was successfully completed prior to restart of the unit.
2.
Unit 2 a.
November 19, 1984 - The reactor was manually tripped from 20 percent power while conducting a plant startup. A condensate pump failure caused, a loss of a 4160 volt bus with numerous associated alarms and indications and the operator judged it
,j/
prudent to manually trip the reactor. All systems functioned normally and the reactor was promptly restarted while the condensate pump was inspected and repaired, e
b.
November 19, 1984 - While conducting a recovery from the previous trip, a second reactor trip occurred because of a spurious high startup rate (SUR) spike. A 1.0 decade per minute (DPM) SUR was being maintained when a inoise spike briefly increased the SUR above the 2.49 DPM trip setpoint.
The operators were subsequently cautioned to maintain the SUR at or below 0.5 DPM.
39 c.
November 21, 1984 - The reactor tripped from 68 pere,ent power because of a turbine trip caused by a 1 css of main generator excitation. The generator field was lost as the result of a f ailed pedestal bearing on the generator's exciter.
All systems functioned normally and the unit was returned to service after completion of exciter repairs.
d.
November 29, 1984 - The reactor tripped on a 5'G low water level signal caused by a closure of the "B." main steam isolation valves (MSIVs).
The MSIVs had received an isolation signal because of a biown fuse. on the "A"
safeguards channel, e.
December 18, 1984 - The reactor tripped.from 50 percent power on a SG low water level signal after an "A" main feedwater pump (MFP) trip on low suction pressure resulted in a total loss of feedwater flow.
The MFP trip was caused by improperly venting the "B" condensate pump while placing it in service. Attempts to restart the "A" MFP before reaching the low SG level trip were unsuccessful. The "B" MFP, which was not operating at the time, started automatically but ifs isolation valve breaker tripped on ; overcurrent before the valve stroked open.
f.
December 19, 1984 - The reactor tripped from about 25 percent power as the result of a turbine trip on low condenser A power reduction from 50 percent had been initiated vacuum.
to repair a cracked condensate pump recirculation line, but the line separated and vacuum was. lost before repairs could be effected.
The ensuing outage was extended to repair, reactor coolant pump seals and safety injection valves.
g.
April 8, 1985 - The reactor tripped from about 10 percent power while conducting a startup frem a SG maintenanca.
Improper operator control of feedwater flow caused a outage.
SG low water level trip. All systems functioned normally and the unit was promptly restarted, h.
April 8, 1985 - The r?h' tor tripped from 15 percent power while conducting a rec t.'ev ' tartup from the trip discussed
. main feedwater regulating valve above. Operating at, to was improperly aligned after performing (MFRV) post-maintenance testing on the valve, causing the valve to fail open when placed in service. SG level increased to the main turbine trip setpoint, which, in turn,. tripped the A citation was issued for the failure to properly reactor.
realign the system after testing.
(
e e
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e
?
40 I
L i.
April 17, 1985 - The reactor was manually tr'ipped from 99 percent power to prevent the loss of secondary system water a
inventory through open moisture separator reheater (MSR) atmospheric relief valves.
An electrical spike, which occurred during maintenance on the digital electro-hydraulic (DEH) control system, somehow (unexplained) caused a spurious closure of all four turbine intercept valves (IV) thereby causing the MSR relief valves to open.
The unit was restarted with the stipulation that future nonroutine DEH maintenance not be permitted at power.
The IV closure feature has since been removed from the DEH circuitry for s'
both St. Lucie units.
j.
April 17, 1985 - The reactor tripped from 20 percent power
.when improper manual control of SG water level during the recovery from the trip discussed in the previous paragraph resulted in a steam generator high water level turbine trip, which, in turn, tripped the reactor.
k.
July 18,1985 - The reactor tripped during performance of a ground isolation procedure at 100 percent power. An error in the operating procedure for DC grcund isolation directed the operators to remove the fuses for the MSIV closure logic circuitry causing the "A" MSIV to close and the reactor to trip on asymmetric SG pressure. A citation was issued for failure to adequately establish and maintain the Unit 2 DC ground isolation procedure.
1.
" August 8,1985 - The reactor tripped from full power when an incorrectly sized fuse in an electrical supply to the -
engineered safeguards actuation cabinet blew. This initiated a main steam isolation signal and a reactor trip on low SG water level.
The reactor coolant pump seals were damaged during the transient because a containment isolation had-interrupted component cooling water flow to the seals. The damaged seals were replaced during the ensuing outage, m.
September 9, 1985 - The reactor was manually tripped from full power when high vibrations occurred on reactor coolsnt pump (RCP) 2A2. RCP shaf t vibration had damaged internal components on the motor lower oil reservoir.
The oil seal had previously failed on August 22 while attempting to recover from the pump seal repair *autage; additional damage was incurred during a minor oil fire on August 24 Repairs had been completed and the unit was returned to service on September 7, only to suffer recurrent RCP high vibrations on September 9.
The oil seals and reservoirs werd subsequently modified as recommended by the vendor to preven,t recurrence.
i
)
41 n.
January 7,1986 - The reactor was manually tripped from full power when a turbine cooling water (TCW) leak developed in the main generator exciter housing.
The TCW leak was repaired and the unit was restarted.
o.
January 7,1986 - The reactor tripped from 12 percent power while conducting a recovery from the previous trip described above.
A power spike to above 15 percent occurred while synchronizing the turbine to the grid, causing the -local power density reactor trip circuitry.to automatically enable and trip the reactor.
Plant operating procedures were modified to caution operators to remain at low power until the axial shape index is favorable for power escalation.
p.
January 11, 1986 - The reactor was tripped from full power when an operator, who was conducting the weekly turbine overspeed trip mechanism test, erroneously operated the
" Trip" lever instead of the " Test" lever; the turbine trip, in turn, caused the reactor trip.
The operator was counselled concerning his inattention to detail and the-
" Trip" lever was painted red to distinguish it from the '
" Test" lever.
W e
f
a..
87 n
ENCLOSURE 2 SALP BOARD REPORT U. S. NUCLEAR REGULATORY COMMISSION REGION II SYSTEPATIC ASSESSMENT OF LICENSEE PERF INSPECTION REPORT NUMBERS 50-335/86-13 and 50-389/86-12 FLORIDA POWER & LIGHT COMPANY ST. LUCIE' UNITS 1 AND 2 NOVEMBER 1, 1984 THROUGH APRIL 30, 1986 ah[$hfh~NY
1 2
I.
Introduction The Systematic Assessment of Licensee Performance integrated NRC staff _ effort to collect available observatio periodic basis and to evaluate licensee performance based up a a on a tion.
The SALP program is supplemental to normal regulator s informa-to determine compliance with NRC rules and regulations intended. to be sufficiently diagnostic to provide a ratioThe SALP s used allocating NRC resources and to provide meaningful guida nal basis for management to promote quality and safety of plant constru censee operation.
July 15, 1986,An NRC SALP Board, composed of the staff me to assess licensee performance in accordance with g e ow, met on ons and data Chapter 0S16, " Systematic Assessment of Licensee Performan n e in NRC Manual the guidance and evaluation criteria is provided in S A summary of report.
ection II of this.
This report is the SALP Board's performance at St.
assessment of the licensee's safety Lucie Units 1 and 2 for the period November 1, through April 30, 1986.
- 1984, SALP Board for St. Lucie Units I and 2:
L. A. Reyes, Acting Director, Division of Reactor Projects (D (Chairman)
, RII J. P. Stohr, Director, Division of Radiation Safety and Safeg V. W. Panciera, Acting Director, Division of Reactor Safety uards, RII D. M. Verrelli, Chief, Reactor Projects Branch 2, DRP
, RII A. C. Thadant, Director, PWR Project Directorate #8
, RII Licensing-8, NRR
, Division of PWR E. Tourigny, Senior Project Manager - St.
Directorate #8, NRR Lucie, PWR Project R. V. Crienjak, Senior Resident Inspector, St.Lucie, DRP, RII e
n.
3 Attendees at SALP Board Meeting:
S. A. Elrod, Chief, Reactor _ Projects Section 2C (RP2C), DRP, RII K. D. Landis, Chief, Technical Support Staff (TSS) DRP, RII T. C. MacArthur, Radiation Specialist, TSS, DRP, RII D. R. Brewer, Senior Resident Inspector, Turkey Point, DRP, RII S. Guenther, Project Engineer, RP2C, DRP, RII H. E. Bibb, Resident Inspector, St. Lucie, DRP, RII J. Rausch, Reactor Engineer, TSS, DRP, RII D. Sells, Senior Project Manager, PWR Project Directorate #8, NRR
~ ~ ~ " " ' ' ' ' ' ' ~ ~ ~ ~ ~ ~ ~
4 II. Criteria whether the facility has beenLicensee performance is assesse in the construction, preoperational, g on ependin operating phase during the SALP review period.
Each functional or environment and which is a normal programmatic ar area y and the may not be assessed because of little or no licensee activitySome meaningful NRC observations.
Special areas may be added to highlight significant observations.
or lack of One or more of the following evaluation criteria was used to a functional area; however, and others may have been used where appropriate.the SALP Boar ssess each A.
Management involvement in assuring quality B.
Approach to the resolution of technical issues from a safet C.
Responsiveness to NRC initiatives y standpoint D.
Enforcement history E.
Operational and construction events (including response to analysis of, and corrective actions for)
F.
Staffing (including management)
G.
Training and qualification effectiveness Based upon the SALP Board assessment, these performance categories are: classified into one of three The definitions of
_ Category 1:
Reduced NRC attention may be appropriate. Licensee management attention and involvement are aggressive and orie nuclear safety; licensee resources are ample and effectively u oward that a high level of performance with respect to operatio such construction quality is being achieved.
nal safety or Category 2:
NRC attention Licensee management should be maintained at normal levels.
attention and involvement concerned with nuclear safety; licensee resources are adequat are evident and are reasonably effective such that satisfactory performance with operational safety or construction quality is being achieved e to Category 3:
Both NRC Licensee ~ management and licensee attention should be increased.
attention or involvement is acceptable and considers nuclear safety, but weaknesses are evident; licensee resources appear to be strained or not effectively used such that minimally satisfactory performance with respect to operationa or construction quality is being achieved.
ey The functional area being evaluated may have some attributes th place the evaluation in Category 1, and others that would place it at would Category 2 or 3.
of the attributes tempered with the judgement of NRC n either significance of individual items.
s to the
5 The SALP Board may also include an appraisal of the p functional area.
This performance trend will erformance trend of a definite trend of performance within the evaluation ponly be used wh and the Board believes that continuation of the trend may res lte of performance level.
The trend, if used, is defined as:
in a change u
Improving:
close of the assessment period. Licensee performance was deter near the Declining:
close of the assessment period. Licensee performance was deter near the III. Summary of Results A.
Overall Facility Evaluation St.
Lucie continues to be a well managed site competent and professional staff.
, with a technically the areas of plant Major strengths were identified in operations, maintenance, activities, and training.
surveillance, licensing No major weaknesses were identified.
of plant performance during this assessment perio o the high level noted to recur in both the Radiological One weakness was analyses, in that plant procedures were not alw the Controls and Surveillance levels.
a e to maintain experience B.
each functional area are as follows:The performance cate v ous SALP periods in Functional Area July 1, 1983 -
October 31, 1984 November 1, 1984 -
Plant Operations
_ April 30 J 986 1
1 Radiological Controls 1
2 Maintenance 1
1 Surveillance 1
1 Fire Protection 2
1 2
Security and Safeguards 1
2 Outages Not Rated 2
j i
6 Quality Programs and Administrative Controls 2
2 Affecting Quality Licensing Activities 1
1 Training and Qualification Effectiveness Not Rated 1
IV.
Performance Analysis A.
Plant Operations 1.
Analysis During the evaluation period, inspections were perform resident and regional inspection staffs.
y the Management involvement a high level and was augmented by the licensee new management position titled Site Vice President.This of a strengthened the local control The position was filled on March 1, 198 had previous experience as the St.
nager who start up and as the Site Vice President at another nucl Plant generat above average. ion performance for both u the second year in a row, having an annual load fact of 100 percent for the pericd from September 1984 or in excess September 1985 It is not to in excess of 100 percentunusual for a plant to have a load factor for short periods of time, however, this marked the first time a nuclear power plant recorded an annual load factor in excess of 100 percent a ever and the lower than predicted temperatur This n
taken directly from the Atlantic Ocean.
water Plant operations manner with operatorscontinued to be conducted in a professional exhibiting proficiency.
high degree of operating a
In general, the licensee's performance in the areas of pro compliance and adequacy over the last SALP period and ural this period was good to excellent.
However, there have been some violations which Indicate a slight Violations (c) and (e) listed below, coupled with a similar decline in this area.
2 7
violation (a) in the Outage analysis, could be indicative programmatic weakness.
These violations prompted additional licensee management attention to ensure the adequa and procedure updates and the institution of measures e ures that a major programmatic problem does re Procedures not develop.
A site Department ha been established to implement procedure review program. s Administrative procedures have been a
developed to control the preparation, review, revision and approval of the upgraded procedures and to provide guid the writing of procedures.
Emergency procedures have beenor rewritten utilizing the appropriate guides.
Of f-normal and annunciator response procedures were being upgraded the SALP period.
All operating procedures have been scheduled fo upgrading after the completion of the off normal procedures upgrading process includes detailed operating and mu The
- reviews, Facility Review Group Several changes have a(FRG) review and Plant Manager ne approval.
design control process to ensure that potential problemlso with procedure updates as they relate to Plant Changes /
s dealing Modifications (PC/Ms), a,re adequately addressed A special inspection was conducted to assess the lice Generic Implications of Salem ATWS Events. co were identified in the post-trip review procedure implement indicating a possible la post-trip review process.ck of supervisory involvement in the The licensee had identified several other deficiencies and had revised the procedure to imp effectiveness.
The revised procedure, should resolve the program deficiencies. if properly implen,ented,
For Unit 1, there were three reactor trips and there wer actuations of the engineered safety features (ESF);e three trips were at power levels greater than 85 percent.
Unit l's two of the reactor trip frequency of 0.26/1000 hours of operation compa trips /1000 hours of operation.very favorably to the curren res discussion of reactor trips.)
(See Section V.J for a further For Unit 2, there were sixteen reactor trips, six of which power levels greater than 85 percent; there were six ESF were at actuations.
Unit 2's reactor trip frequency of operation was higher than the current nAional average frequ 1.54/1000 hours of Both units had an availability y.
factor Unit l's over 86 percent.
of over 78 percent with load factor was in excess of 100 percentAs discussed earlier, Uni September 1984 to September 1985.
for the period from
8 Management's expeditious and thorough. responsiveness to NRC and other The previous initiatives was Event Reports (LERs). associated with the adequacy of NRC Region II, the licensee successfully altered itA censee presenting information in LERs.
s methods of in this SALP period, LER descriptions and cau early have shown dramatic improvement.
Events at St. Lucie are yses generally re occurrence. ported within the required time period following period for both units.There were 43 LERs submitted duri Near the end of this evaluation period (one day) strike by the iron workers' un(ion cause,d a1986 April 28 plant operations personnel because some operators wou shortage of the picket line.
to assure adequate staffing of critical positionsLic not cross the period, added emphasis has been pl During and a repainting program was initiated to improve pla ant cleanliness preservation and appearance.
Plant tour observations have periods of high outage related activity. consiste
, even during excellent during the latter part of the SAlpHousekeeping has been period.
Conduct of operations in the control room was general Plant management is quite sensitive to control room d excellent.
quick to correct lapses.
The NRC's ques emeanor and addressed in a prompt and courteous manner.tions were always being properly briefed with information wh Observations have safety.
shift annunciators, plant or system status and lineu pact plant various annunciator Procedures for requirements for responses and Technical Specification LCOs were consistently followed.
rooms were always adequately staf fed with an appropriat The control talent and experience.
The senior e mix of Supervisors (NPSs) and their operators, Nuclear Plant assistant ANPSs, appropriate level of responsibility within the are given an operational issues and management dec FPL structure, ertain lower levels than normally encountered.
somewhat effect on operator morale and has improved manageme in operations.
been the use of the morning meetingAnother contributor t c ency and new problems are discussed. Plant status for bo i
e evolutions scheduled to address, in greater detail, particular proble Additional meetings are then ms and
D 9
their solutions.
morning meetings, which are conducted by Ope in these atmosphere within the plant organization of supporting
, there is an operation.
This has resulted in other departments, such as ant's Maintenance, being more readily available support the needs of the Operations Department.to respond to and Five violations were identified:
a.
Severity Level IV violation for an isolation valve.
(335/85-07) inoperable containment b.
Severity level IV violation for failure to properly alig instrument air supply to a main feedwater regulating e
after testing.
(389/85-10) ve c.
Severity Level IV violation for failure to adequately establish plant procedures which reflect characteristics of the main steam isolation valve a the operating solenoid valve logic control circuit.
(389/85-20) d.
Severity Level IV violation for failure to maintain operable shutdown cooling loops during cold shutdown two operations with the reactor coolant loops not filled.
(335/85-36) after a plant modification. Severity level V violation f e.
(389/85-17) 2.
Conclusion Category:
1 Trend: Declining 3.
Board Recommendations The board noted that Unit 1 was a superior criteria for a Category I rating, however,. performer and met the was determined to fit the Category 2 rating. Unit 2's performance management involvement, Based on the strong an overall rating appropriate.
of I was deemed B.
Radiological Controls 1.
Analysis During the evaluation period, routine radiological controls inspections were performed by the regio staffs.
on
10 chemistry overexposure incident, inspection, a special inspection involv using the NRC Region II mobile laboratory.and a confirma The licensee's health physics staf fing level appeared ad support routine operations.
Additional refueling outages. technicians were utilized to supplement the evaluation period. Health physics staff turnover was low durin l
r ng The licensee maintained a small technic staf f on-site, with much of the health physics technical ex in dosimetry processing, solid radioactive waste classificatio and audits residin audit program was, g in the corporate health physics group.
n The by the licensee at the end of the assessment period.
During 1985, the licensee developed a formal training and qualification program for health physics technicians.
The licensee has submitted the program to the Institute of Nucle Power Operations and anticipates that accreditation will be achieved in the fall of 1986.
The licensee environmental reports. submitted the required effluent and radiologica There were no unplanned radioactive liquid or gaseous releases during 1985.
Releases, while higher than regional averages for gaseous effluents, were within the prescribed limits of the Technical Specifications.
(Ci) of fission and activation gases and 0.98 Ci of iodine-13 60,340 curies were discharged to the atmosphere in gaseous effluents from units in 1985.
The 1985 Region II averages for a two unit site (based on 12 operating PWRs) were 5260 Ci and 0.023 Ci, respectively.
and activation products and 650 Ci of tritium. Liquid eff averages were 1.3 Ci and 780 C1, respectively. The 1985 Region II within 10 CFR Part 20 and 10 CFR Part 5 public were 0.4 mrem from liquid effluents gamma and beta dose from gaseous effluents.
doses represented 8 percent of the 10 CFR PartThese calculated limits for liquid releases and 7 percent of the limits for gase 50 Appendix I releases.
The consistently high gaseous effluent releases over a perio several years were caused by a higher than expected rate of fuel cladding perforation in both units.
of the gaseous radioactivity has been from Unit 1.In 1985 and at and has been able to achieve holdup times The licensee
11 days in an effort to employ available design features to releases.
reduction program which enabled the det minimize with the waste gas decay tank system.
e problems A deviation from the Final Safety Analysis Report (F criteria / objectives was identified during the evaluatio esign Several reactor auxiliary building unfiltered air to flow out of the RAB.and the RA allowing of high potential The flow of air from areas radioactivity was possible. radioactivity toones of low potential licensee was effective in preventing a recurrenceThe corr The licensee's post accident evaluated during the SALP period. sampling systems (PASS) were Units 1 Since the PASS installations in and 2 were supplied by different operators are required to be separately trained and quali vendors, the plant each installation.
The evaluation found the PASS insta e
or operable for both units, and training and procedures were determined to be adequate.
A special NRC inspection reviewed the circumstances inadvertent personnel operations in a Unit I steam generator. exposure while conducting ng an lancing in the licensee's radiation protection programIt disclosed a weakn memoranda and the experience level of the health physics
, in that informal technicians, rather than approved procedures specify radiological protection requirements for maintena
, were relied upon to activities which had high exposure potential.
was, in large part, responsible for a Severity Level III viol ti involving an overexposure to the upper arm of the wh l a on worker performing those sludge lancing operations o e body of a denied this violation, however, on July The licensee the bases for the licensee's denial.
11, 1986, the NRC rejected Both the on site and involved in the resolution of the technical issues suthe overexposure incident.
rrounding the in that it failed to adequately address the placeinvestigatio on the arm and the dose gradient in the steam generator ha ment of dosimetry The e.
respiratory protection and Radiat ?bn Work Permit appeared adequate; however, one proposed violation was id programs in that respiratory protection equipment issuance records e
addressed procedurally as required by regulations, and were not consequently, none were maintained.
issued after the end of the SALP period and has n tThis propos responded to by the licensee.
o yet been
o 12 Collective personnel exposure during 1985 was approximatel man-rem per reactor, which was somewhat above average (425 man-rem) for U.S. pressurized water reactors (PWRs), but daring the period. considered significant in light of the extensiv is not in 1986 is approximately 300 man-rem per reactor.The From October 20 to December 31, 1985, 461 skin and clot contamination events occurred.
The number of skin and clothing contamination events was noted to decrease to 64 between Jan and April 17, 1986.
effectiveness was begun byTracking of contamination control progra the licensee during the evaluation period.
On February 1,1986, the licensee had 46,565 square fee or 35 percent of the radiation controlled area of the plant,
~
controlled as contaminated.
On March 31, 1986 the area controlled as contaminated increased to 51,042, or,38 percent of the plant.
It 11censee's program for reducing the plant's conta During 1985, the licensee disposed of 14,590 cubic feet of solid radioactive waste containing 796 curies of activity per unit.
This represented a significant decrease when compared to the 1 figure of 21,625 cubic feet, which was unusually large due to the disposal of the Unit I reactor thermal shield.
of f site was generally adequate. Packaging and prepa of Department of Transportation (00T) regulations were i The itcensee failed to package radioactive material in a stro tight container and the radiation levels on the external surfaces of two packages in a shipment These violations may have been caused, in part, exceeded the reg by a temporary by personnel reassignments. reduction in health physics staff The second violation was determined to be a Severity Level III violation, however, no civil penalty was assessed.
These proposed violations were issued af ter the end of the SALP period and have not yet been responded to by the licensee.
The quality control program for radiological measurements met th general guidance of NRC Regulatory Guide 4.15.
Some procedural deficiencies were identified
- however, in that detailed intralaboratory and interlaboratory crosscheck implementing procedures were not formalized. The results of the 1984 and 1985 NRC spiked sample crosscheck program for iron-55 were in disagreement.
three consecutiveGenerally, enforcement action is considered af ter discrepancies were sample crosscheck disagreements.
Measurement also noted in various liquid media for
' '.=
13 manganese-54 and iodine-131.
In the spiked particulate filter, cobalt 57 was in disagreement, and all nuclides for the filter geometry exhibited a consistently high bias.
These results demonstrated the need for increased management involvement in the radiological measurements quality control program, to ensure the validity of measurements for quantifying plant effluents.
Both units operated in a very stable manner during the evaluation period, enabling the control of secondary chemistry to a standard higher than the guidelines recommended by the Steam Generator Owners Group.
Implementation of an aggressive water chemistry program was a noted strength.
The licensee was actively attempting to resolve an air ejector design problem which caused the concentration of air in the condenser hotwell to remain higher than desired.
One violation and one deviation were identified:
a.
Severity Level III violation for failure to establish radiological control procedures for steam generator work and failure to perform adequate surveys (evaluations) of individual exposure such that one worker received an overexposure of the whole body.
(335/86-01) b.
Deviation from FSAR design criteria / objectives in that RAB doors were blocked open.
(389/86-01)
Three additional proposed violations were identified during the SALP period. These violations were not issued until after the end of the SALP period and the licensee has not yet responded to the citations.
Proposed Severity Level IV violation for inadequate precedures addressing the maintenance of respiratory protection equipment issuance records.
(335/86-09)
Proposed Severity Level III (with no civil penalty) violation for failure to maintain radwaste shipment external radiation levels within limits.
(335/86-09)
Proposed Severity Level IV violation for failure to package radioactive material in a strong, tight shipping container.
(335/86-09) 2.
Conclusion Category: 2
14 3.
Board Recommendations The Board noted a decrease in the effectiveness o have been caused, in part, by personnel chang
, which may experience level of the health physics staff and by the lack reduced the detail in transportation procedures.
The of inspection activity. increased attention to this area, and the N u
ncrease its C.
Maintenance i
1.
Analysis During the evaluation period, i
resident ar.d regional inspection staffs. inspections were performed by the Licensee management continued to seek improvements in the maintenance program, and emphasized adherence to procedural and regulatory requirements.
This resulted in a number of violations decrease in the excellent Un't 1 performance record since completing The to the core support barrel and renoving the the repairs another indication of the quality of maintenance activities rmal shield is Maintenance staffing and training were adequate The plant work order (PWO) backlog at St. Lucie appears under control.
The licensee subscribes to the Institute of the outstandingNuclear Power Operations guideline that no mor PW0s be greater than percent of comformance with that guideline, three months old.
In three months delinquent was noted to drop significa tlthe number o l
n y.
techniques to monitor equipment performance i
number of The program uses vibration analyses on mechanical eq yze failures.
infrared analyses on electrical equipment, oil analyses on Motor Operated Valve Analysis and Testing Sys
, and the determine the operability of motor operated valves.
These (M0 VATS) to techniques have enabled the licensee to detect deg equipment performance and effect repairs before failures occu rading trends in Management r.
responsiveness to NRC initiatives previously established high levels discussed in the l remained at the report and was evidenced by ast SALP experience feedback program. the continuation of the operating Additionally, initiative, own has established a Quality the licensee, on its Improvement Program
15 (QIP) which encourages the direct involvement of craftsmen and technicians in achieving, maintaining and improving quality. The participation of these - working level individuals has had a positive effect because they can make inputs to management and cbserve improvements brought about by their efforts.
Maintenance activities involving the reactor coolant pump oil seals and anti-reverse rotation devices (ARRD) were also reviewed.
The degradation of these components were quickly identified and proper corrective action was promptly initiated. Site management readily committed to formal reports to the NRC as investigation and assessment results were compiled.
A special inspection to assess the licensee's compliance with Generic Letter 83-28 raised concerns regarding the preparation, review, approval, and implementation of reactor trip breaker maintenance procedures.
The licensee's proposed corrective for these concerns were judged to be adequate.
The measures
~
licensee's programs for reactor trip system post-maintenance testing and equipment classification were found to meet the requirements of the Generic Letter.
No violations were identified during the assessment period.
2.
Conclusion Category:
1 3.
Board Recommendations The board noted that the Category I rating was based on a limited inspection effort which failed to reveal any significant deficiencies.
D.
Surveillance 1.
Analysis During the evaluation period, inspections were performed by the resident, regional and headquarters inspection staffs.
The regional staff performed inspections of the surveillance testing, calibration control and snubber surveillance programs, and the headquarters staff performed a special dhvironmental qualification program inspection.
The surveillance testing programs appeared effective.
Technical Specification surveillances were almost always completed in a timely manner.
No instances of using out-of-date surveillance procedures were identified during the evaluation period.
Management involvement in staffing and training for operational surveillances continued to be adequate.
16 Though surveillance scheduling and implementing procedures were generally effective, four cases of missed surveillances, which occurred near the end of the evaluation period, indicated a program weakness in the scheduling of plant surveillances during the reassignment of plant personnel.
The licensee identified these cases and has vigorously implemented measures to correct the missed surveillance problem.
Plant Quality Control (QC) audited the departments responsible for conducting surveillances to ensure that an adequate and timely method of verifying the completion of surveillances existed within the responsible departments.
This review determined that three of the nine departments involved in the performance of TS surveillances lacked scheduling procedures and two la:ked an individual directly responsible to oversee or review.the conduct of surveillances. The licensee has implemented three new scheduling procedures, and the two deficient procedures have been revised to include sign-offs for internal, departmental reviews.
While the results cannot be judged at this time, it is-expected that this added visibility and the delineation of responsibility will improve the conduct of surveillance testing.
A special inspection to assess the licensee's compliance with Generic Letter (GL) 83-28 found that trip system reliability testing met the intent of the GL. The licensee's trending program for critical reactor trip breaker parameters was found not to include all the parameters recommended by NRR, and their response l
to a request from NRR for more program was not timely.
information on their trending The calibration program was effective in maintaining current instrument calibrations.
Problems were identified, however, in that gauges required for inservice inspection (ISI) calibrations were not included in the calibration program and the ISI vibration monitoring program was inconsistent. The remaining areas of this program appeared effective.
Snubber surveillance program planning was evident in the well-defined and written procedures.
Policies were adequately stated and understood, and reviews were timely, thorough and technically i
sound.
Records of snubber inspection results were complete, legible and readily retrievabla on a personal computer system.
The resolution of problems encountered during snubber surveillance inspections (functional test failures) were conservative, timely, technically sound and thorough.
- Staffing, training and qualification of personnel involved in snubber surveillance were adequate.
A special inspection determined that the licensee had implemented a program to establish and maintain the environmental qualifica-tion of equipment within the scope of 10 CFR 50.49.
Although there were some potential problem areas in procurement and L
?
17 maintenance, there' were no findings affecting the sa of the plant.
The findings were ration similar inspections at other Region II facilities. typical of findin Two violations were identified:
a.
Severity Level (86-07/06)IV violation for missed surv examples).
b.
Severity Level IV violation for failure to correct batt specific gravity for electrolyte level.
ery (85-08) 2.
Conclusion Category:
1 Trend: Declining 3.
Board Recommendations The Board expressed a concern surveillance program effectiveness during a period of pe regarding the decrease in transitioa.
The same problem was noted to have occured in nnel radioactive waste transportation program and indicates a increased management oversight during future staff c eed for E.
Fire Protection 1.
Analysis During this assessment period inspections of the licensee's routine fire protection and pre,vention program were con the regional and resident inspection staffs.
In addition, e
y special Unit 2 inspection was conducted by the regional a
assess the status of the licensee's implementation of o
requirements of 10 CFR 50, Appendix R.
the was found to be satisfactory.The licensee's routine f for the administrative control of fire hazards within thTh From a fire protection e plant.
standpoint, housekeeping and control of flammable materials were satisfactory.
The fire protection extinguishing systems, detection systfms, fire barriers and barrier penetrations were found to be in service Procedures for the surveillance inspection, testing and tenance of the plant's fire protection have been established and implemented. systems and equipment features have been satisfactorily tested and maintained The fire protection
o 18 The licensee has also established procedures organization and training of the fire protection governing the fire brigade.
staff and the The fire brigade training program was well defined and fully implemented.
The training and drills for the brigade members met the frequency fire procedures and the NRC's guidelines. specified by the licensee's The licensee has established an on site fire brigade training facility, which presently consists of fbmmable liquid burn pit utilized for portable fire extinguisher and small fire attack hose line training operations.
It is the licensee's intent to expand this facility in the future to include structural power plant firefighting and self-contained breathing apparatus training operations.
Fire protection staffin the licensee's program.g was adequate to accomplish the goals of identified, and authorities andThe fire protection staff positions are.
responsibilities are clearly defined.
The personnel assigned to these positions are well qualified for their assigned duties.
The organization and staffing of the plant fire brigade met NRC guidelines.
The inspectors reviewed the annual fire. protection / prevention audit, the 24 month QA fire protection program audit by off-site crganizations and the triennial audit by an outside fire protection organization required by the Technical Specifications These audits were conducted within the specified frequency an appeared to cover all the essential elements of the fire protection program.
The licensee had corrective actions for discrepancies identified by these audits.
hourly fire watch required by the Technical S been performed for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during the bargaining unit walkout o April 28, 1986.
The incident was reported as required applicable procedures were revised to preclude recurrenc,e.
and the In preparation for the special Appendix R inspection the licensee identified, analyzed discrepancies as requ, ired by Unit 2 operating license 2.c.13.
ments of Appendix R,Section III.G.2, had not bee Unit 2, Train "B" switchgear room and cable loft.
The NRC in the reviewed these reports and determined that the licensee-identified Appendix R discrepancies were significant with respect main one train of safe shutdown capability free from The discrepancies were, however, found to be satisfactory.
i
,,,n-.
. -, ~, -
n-.
19 In addition, the NRC's Appendix R inspection found that the licensee's alternative shutdown procedure for fire in either the control room or the cable spreading room was in error. The two procedural errors could have affected the safe implementation of alternative shutdown capabilities on Unit 2.
The licensee also failed to fully implement the control / cable spreading room alternative shutdown procedure required by license condition 2.C.13.
The licensee demonstrated a clear understanding of the Appendix R alternative shutdown procedure issues, and their approach to resolving these issues was technically sound, timely and responsive to NRC requirements.
In general, management involvement and control in assuring quality in the routine fire protection program was adequate as evidenced by the issuance and implementation of fire protection procedures that met the NRC's requirements and guidelines.
The licensee's approach to the resolution of routine technical fire protection.
issues indicated a clear understanding of the issues, and was practically always technically sound and timely.
Responsiveness to NRC initiatives was technically sound and thorough in almost all cases.
In addition, violations against the routine fire protection and prevention program are rare.
Three Appendix R related violations were identified:
Severity Level III violation for failure to provide adequate a.
fire protection features for a safe shutdown system necessary to achieve and maintain hot standby.
(389/85-06) b.
Severity Level IV violation for procedure errors which could affect the safe implementation of alternative shutdown capabilities.
(389/85-06) c.
Severity Level IV violation for failure to fully implement Appendix R. as required by license condition 2.c.13.
(389/85-06) 2.
Conclusion Category: 2 Trend:
Improving o
3.
Board Recommendations No changes in the NRC's inspection resources are recommended.
j
~
20 F.
Analysis During the assessment period inspections were performed by the regional and resident inspection staffs.
This included preparedness exercises. routine inspection and the obser one emergency The routine inspection found that response were adequately the essential elements for emergency conducted implemented.
Walk-throughs with plant staff members assigned positions of responsibility recognize emergency actionin an emergency showed that they were able to levels, correctly cla ssify events, develop correct protective action recommendations were knowledgeable of off site notification methods.A
, and that they communication communications to off-site agencies was in p The public information program appeared to provide necessary speaking engagementsinformation to the public in the fo e.
ided through a duty officer / rost rough augmentation was prov.
Walk-throughs of dose demonstrated the licensee' projection and assessment problems s ability to promptly obtain acceptable results.
Although no violations, deviations, findings were or significant negative identified during the routine inspection, the licensee's demonstration of its ability to adequately i the emergency exercises showed a basic flaw in command and mplement emergency exercise identified procedura The 1985 Emergency the Emergency Coordinator to delegate the responsibility fo declaration, off-site notifications, protective action mergency documents permitted such delegation. recommenda while other that these could potentiallyinconsistencies in the assignmentThe licen non performance of certainlead to confusion, duplication of eff functions.
The licensee did not or correct this potential problem af ter the 1985 exercise The 1986 emergency exercise confirmed that these inc remained.
This resulted in actual fragmentation of command a s encies control and contributed to the following problems:
Emergency classification;a failure to notify the NRC
21 less than full involvement of the Technical Support Center (TSC) staf f in accident mitigation; poor information flow to the Recovery Manager, including a delay of 45 minutes in informing the Recovery Manager that the core was uncovered; and a delay in the flow of information to the Emergency Operations Facility (EOF).
These difficulties developed during an exercise with a scenario that was not particularly taxing. The licensee acknowledged these findings during the NRC critique following the exercise. During subsequent discussions, the licensee's corporate emergency planning staff proposed corrective actions, including procedural revisions and special emphasis on communications training, which,-
if properly implemented, should resolve the exercise problems.
No violations were identified during the assessment period.
2.
Conclusion f'
Category: 2 3.
Board Recommendations Additional licensee management attention is necessary to ensure that the problems associated with the delegation of authority are resolved and do not recur during future exercises.
G.
Security and Safeguards 1.
Analysis Inspections during this evaluation period were performed by the resident and regional inspection staffs.
There was evidence of management involvement and control of the security program. Managerial interest and response to security-related issues and problems were generally technically sound and consistent, demonstrating the existence of policies and procedures for control of security related activities.
The licensee's security organization consists of a security management function and a contract guard force.
The security staff manning and performance capability is considered adequate to implement the physical protection program as committed to in the Physical Security Plan despite a slightly O
r
-,. ~ - - _. _ _.
,y__
.y
.-_.-_-__-_.,__--.w,_m__.,3--_
,_,,.--._v,
22 higher than normal turnover rate.
of the guard force to perform routine security as de training and qualification plan is also judged t n the o be adequate.
compliance verification role.The contract guard fo utilized in a Two apparent violations demonstrated the need for mo awareness on One violation, involving the failure to control a re security a
s.
equipment was initially AS a corrective action for this violation the cess to vital period.
initiated a s This survey, urvey to revalidate all identified vital equipment ensee which was in evaluation period, progress at the end of the SALP equipment identified as vital in the Physical S not enclosed within a vital area.
n was This resulted in an additional, apparent violation.
The licensee's operating staff and security personne failure to detect these e plant and training of security force members to recognize and ocedures appropriately to vital area barrier degradations.
These respond violations could have been avoided with better inte i
cross-training between Both violations are under consideration for escalated and action.
orcement Safeguards event reports were timely and accurate and addressed appropriate corrective actions, the impleme adequately which account for the absence of repetitive incidents n of Changes to the Physical Security Plan were submitted time frames specified in n the responsive to NRC Region 11 comments on those The licensee's independent auditors are permanently assigned unescorted vital area security are aware of security requirements while conducting othe s and One violation was identified:
s.
Severity Level IV violation for failure to secure an unattended vehicle.
(85-01) 2.
Conclusion Category: 2 l
3.
Board Recommendations I
No changes in the NRC's inspection resources are recom mended.
w m
~ -- -
a w.
e n-,,m
.mn m-----m
23 H.
Outages 1.
Analysis During this evaluation period routine inspections were performed by the resident and regional inspection staffs.
Refueling was performed on both units.
The regional inspection effort focused on Unit I refueling activities and reviews of the licensee's inservice inspection (ISI), inservice test (IST) and measuring and test equipment (M&TE) programs.
Routine inspections by the resident inspectors addressed the areas of preparation for refueling, receipt and handling of new fuel, Unit I core support barrel inspection, steam generator eddy current testing, in-core instrument replacement, reactor cavity seal ring design and testing and refueling activities. All activities appeared to be well managed.
During this evaluation period, licensee management has continued to focus attention on preventive measures and planning in an ef fort to anticipate occurrences.
For example, the licensee is continually planning for unscheduled shutdowns and outages.
A current list of action items requiring a mode of operation other than power operation is maintained, work packages are prepared and parts are ordered in advance.
When forced into an unplanned shutdown, there is little time wasted in planning and scheduling this contingency work. This allows a clearer focus on correction of the cause of the forced shutdown and minimizes the facility's backlog of " shutdown items."
Plant safety and reliability are enhanced and the length of scheduled outages is shortened.
The licensee has been very successful in planning and implementing scheduled outages. Outages have usually been completed within a few days of the schedule.
Even when unexpected problems have occurred the licensee has demonstrated the necessary flexibility to make schedule changes and still complete the outage within a reasonable time span.
This was particularly apparent during the Unit 1 outage in the fall of 1905 when problems were encountered in lif ting the upper guide structure.
The licensee took actions to minimize the incidents impact on the critical path of the outage.
The Unit I core support barrel inspection revealed no degradation in the repairs implemented during the p&vious refueling outage.
Fif teen damaged Unit 1 fuel pins were removed and replaced with solid, unfueled pins.
Additional fuel failures have been experienced since the unit was restarted in December 1985 and indicate a possible inadequacy in the licensee's failure analysis.
24 t
The licensee did not search for debris in the lower fuel assembly grids until af ter the damaged pins were removed.
This may have obscured any indications of potential debris-induced fretting in that area.
The licensee should implement a more detailed and disciplined search for fuel failure mechanisms during the next refueling outage.
While removing the Unit I core internals upper guide structure (UGS) in preparation for defueling, one of three lif ting rig attachments gave way.
This placed the UGS and lifting rig in a tilted position suspended about eight feet above the irradiated fuel.
The licensee declared an unusual event in accordance with plant emergency procedures.
It is believed that this failure was caused by inadequate thread engagement on one of the three bolts which attaches the lifting rig to the UGS. The bolt was assumed to be fully engaged when the torque limit specified in the procedure was reached.
The procedure was inadequate (see violation (a)) in that no independent verification method was required to ensure that the bolt was not cross-threaded or otherwise bound, thereby creating a false seating indication.
Management involvement was evident in the prompt and ef ficient mobilization and direction of appropriate resources in designing, manufacturing, testing and employing a temporary lifting rig for removing the UGS.
fhese actons were taken in a timely manner to ensure that a potentially hazardous situation was corrected without unnecessary delay, while at all times maintaining controls to ensure that an already tenuous situation did not degrade further and cause additional damage.
A regional inspector witnessed Unit I defueling activities from the control room, refueling floor and spent fuel pool area, and found that defueling was performed in accordance with the controlling procedure.
Management involvement in refueling activities continued to be strong and effective, both during routine operations and during the unusual event described above.
Total team refueling meetings were held twice daily and were effective in maintaining control of critical path refueling activities. Staffing during refueling met or exceeded the Technical Specification requirements. The one-day strike on April 28, 1986, had little or no impact on the Unit 2 refueling progress because of prompt management control and placement of personnel.
Unit 2 completed its second refueling outage and returned to power on June 4, 1986.
Violation (c) invcived a failure to install safety related battery racks in accordance with approved drawings.
This was considered to represent an isolated instance of inadequate drawing references in the Plant Change / Modification package and not a breakdown of the design change program.
- _ -, ~. - -.
Y
~
r 25 Licensee management involvement in inservice in inservice testing decision making wa(s at a level that assured a IST) activities appeared to be adequate and and review.
The ISI manual and implementing procedures co gement be upgraded by site and c control of the ISI program.orporate management thereby improving Because of a change in organization, the ISI Coordinator now reports to the Technical Department ra Department.
e not yet been evaluated.
Key were identified, and authoritiespositions within the organization defined.
and The ISI manual now defines responsibilities responsibilities were work.
for ISI The licensee's ISI/IST program reviews were timely technically sound.
Records were complete, well maintained and, t available.
A training program for all personnel involved in ISI was and implemented.
e ned One minor IST procedural violation (d) was identified evaluation period.
indicative of a programmatic breakdown.The violation was n e
The regional inspection of the M&T2 program found it adequate overall.
Some to be inconsistencies in documentation environmental conditions in the calibration were Four violations were identified:
a.
Severity Level IV violation for removal of the upper guide structure. inadequate procedure for (33S/85-29) b.
measures for environmentalSeverity Level IV violatio e
(85-16) conditions for calibration of M&TE.
c.
Severity Level IV violation for failure to install safety related batteries in drawings.
(85-08) accordance with applicable d.
Severity Level V violation for failure to enter pump test status in control room " Pump and Valve Summary" book.
(85-04) 5
's
\\
r 26 2.
Conclusion Category:
2 3.
Board Recommendations No change in the NRC's inspection resources are rec I.
ommended.
Quality Programs and Administrative Controls Affe 1.
Analysis During this evaluation period, inspections were perfo resident and regional inspection staffs.
rmed by the reviewed by the regional inspection staff:The following areas were program review, audits, records, document quality assurance (QA) control (QC) administration, off-site support staff control, QA/ quality,
review committee (Company Nuclear Review Board)
, and off-site (CEP) which was a spin off of the Perfor nce Program at Turkey Point.
The CEP included the following QA/QC ncement Program enhancements:
increase QA staff size (four additional positions t filled),
o be increased QA personnel training, increased QA technical expertise (one recently hi employee was a licensed operator),
red QA improved communication between QA and site person trend analysis and reporting, performance monitoring to address plant systems /hard real time operating activities, ware and expanded QA and QC surveillance programs, and f
QA audits to assure that CEP commitments are bein A number of QA implementing procedures have also be more accurately reflect program requirements.Site personnel en rewritten to appeared knowledgeable about these program enhancemen The implementation, scope be adequate. A problem was, and findings of QA audits were found to identified which reflected that audits of surveillance activities were not performed to the depth
27 necessary to assure calibration activities were being properly performed.
This appeared to be an isolated example.
document control programs were assessed as adequate Records and administration The QA/QC was determined to be adequate.
Closecut and corrective actions for NRC identified violations was timely.
The special inspection to assess compliance with GL 8 licensee management to be actively involved in assu and to be reasonably responsive to NRC initiatives regarding reactor trip system operation, maintenance, testing, and reliability.
Management involvement development, review, and, in most cases, timely submitta was evident in the responses required by the GL.
The off-site support staff program met existing regula requirements. The training of personi.al appeared ade ensure technical competence.
Interfaca between off-site and on site staff appeared adequate.
Greater efficiency in providing staff to the site. support services was achieved by assigning o fulfilling the function of the committee charter.The off-s No violations were identified during the appraisal period 2.
Conclusion Category: 2 3.
Board Recommendations No changes in the NRC's inspection resources are recommend J.
Licensing Activities 1.
Analysis During the SALP evaluation pt<iod, the licensee continued to significant management overview in the area of licensing activities.
The licensee consistently balar.:es maintain or improve piant productivity with the need to protect the desire to the health and safety of the public.
The majority of the by the licensing group. licensing actions completed during to be referred to upper management,In the few insttnces where m to be well-informed and helpful in resolving questionsthe manage management has also become deeply involved in improving the Upper quality of the work done at the plant by actively the development of a quality improvement program. participating in management has continued to pursue a program that The licensee's improving and increasing the technical capability of the staff is aimed at
28 The licensee's submittals are most quality.
In particular, the licensee' soften timely and of high and marked improvement during the repo treatment of the no y
There were some instances du not made in a timely manner. ring the period when submittals were This occurred most frequently on requests for action on items required for restart after ref outages.
The licensee needs to improve their performanc ueling area.
The licensee also needs to improve in areas where immediate impact on plant operation.information ve an by operating experience, Generic Letters, in In particular, such areas generated etc.
The need for changes in the diesel generator Technical Specifications is a prime example.
With few exceptions, the technical co e in complete and thorough.
Where additional information has bee s
needed, it has been of a clarifying nature, for the most p in many cases handled by phone with a confirmat
, and letter.
Few, i f any, licensee responses to NRC re ory follow up additional information require subsequent questions. quests for The licensee continues to maintain a significant techn capability necessary to resolve items of. concern to the N report period, the licensee has expanded the staff at the During the site as well as the main office in Miami and the subsidia ant in Juno Beach The licensee has also utilized the service nuclear suppor.
e problems or to utilize both new and proven tech enhance the operation and safety of the plant.
will During this period, the licensee has decided to consolidat majority of its nuclear engineering support staff into a e the office complex in Juno Beach.
This consolidation should improve e
the support capability provided particularly in the reduction in response time required to re to the St. Lucie plant, technical issues.
solve Licensee management supported a number of NRC initiativ notably a site visit dealing with a residual heat removal g
, most issue.
During the period, the licensee worked with the NRC in resolving a number of multi plant and TMI items.
the licensee carefully evaluated the action in question and In each case, provided meaningful input to the NRC staff.
opinion have occurred, the Where differences of requirements to insure that the results (Technical Spe for example) reflect the plant design.
- ons,
29 The licensing group holds informal training sessions on topics of current and future interest.
The group also participates in corporate-wide training programs such as, " Supervisor Training for Quality".
The training program, measured by results, has been very effective during this rating period and is about to be evaluated by INPO for program accreditation.
2.
Conclusion Category:
1 3.
Board Recommendations No changes in the NRC's inspection resources are recommended.
K.
Training and Qualification Effectiveness 1.
Analysis No formal inspections of the St. Lucie training program were conducted during this SALP period.
Routine inspections by the regional staff did, however, touch on training of personnel in several specific areas, including health physics, fire brigade, security, ISI technicians, quality assurance staff, maintenance, and licensing. These inspections did not note any deficiencies in the areas reviewed.
Two sets of replacement operator licensing exams were administered.
Four of five senior reactor operator (SRO) candidates and five of five reactor operator (RO) candidates passed the oral and written examinations administered in February - March 1985.
The oral and written examinations administered in December 1985 resulted in six of seven SRO candidates and ten of ten R0 candidates passing.
The SRO and RO passing rates of 83's and 100*4, respectively, were above the industry average, and provide evidence of management's involvement in the training process and in the screening of prospective license examination candidates.
Six new Shift Technical Advisors (STAS) were qualified during the evaluation period,.and there are presently four new STAS in the qualification program.
A training simulator has been ordered and is scheduled to be installed by late 1986 in a new training facility which is currently under construction at the site.
No violations were identified during the appraisal period.
2.
Conclusion Category:
1
30 3.
Board Recommendations l
No changes in the NRC's inspection resources are recommended.
V.
Supporting Data and Summaries l
A.
Licensee Activities The scope of major outage work at St. Lucie was as follows:
Unit 1 10/20/85 - 12/25/85 Scheduled refueling / maintenance, inspection of core support barrel
~
~
Unit 2 10/12/84 - 11/19/84 Scheduled refueling / maintenance 11/21/84 - 11/29/84 Turbine bearing problems 12/19/84 - 12/27/84 Condenser air leak 08/08/85 - 09/07/85 RCP seals, high vibration & oil leaks 09/09/85 and 09/22/85 04/05/86 - 06/04/86 Scheduled refueling / maintenance B.
Inspection Activities The routine inspection program was performed during this period, with special inspections conducted to augment the program as follows:
1, February 25 - March 5,1985,.in the areas of liquid and gaseous radwaste management, environmental programs, and evaluation of NUREG-0737, Item II.B.3, Post-Accident Sampling System (PASS).
2.
February 25 - March 1,1985, in the areas of fire protection and the licensee's actions regarding the implementation of the requirements of 10 CFR 50, Appendix R, Sections III.G, III.J, III.L and III.O.
3.
July 8-12, 1985, concerning FPL's response to Generic Letter 83-28, Required Actions Based on General Implications of Salem Anticipated Trancient Without Scram (ATWS) Events.
Areas inspected included:
post-trip reviews, equipment classification, vendor interface and manual controls, post-maintenance testing, and reactor trip system reliability.
4.
August 19-21, 1985, on-site and in the General Office in the areas of emergency preparedness, emergency response facilities, NRC response team coordination, and NRC hurricane response equipment, coordination and procedures.
31 5.
January 8-9, 1986, in reaction to a potential whole body radiation exposure in excess of 10 CFR 20 limits.
6.
January 21-22, 1986, to follow up on previously identified findings in the area of fire protection.
7.
March 31 - April 4,1986, in the area of equipment environmental qualifications.
C.
Licensing Activities of licensing actions that were completed during the period.
These actions consisted of amendment requests, exemption rating
.shown below. requests, responses to Generic Letters, TMI items and other ac 1.
Licensing Activities Completed During the SALP Period License Condition Compliance Concerning Heavy Loads (St.
4 Lucie 2)
Purge and Vent Valve Operability (St. Lucie 1)
Environmental Qualification of Electrical Equipment (St.
Lucie 1)
EXXON Nuclear Creep Collapse Methodology (St. Lucie 1)
Contrcl of Heavy Loads, Phase I (St. Lucie 1)
Axial Growth of Fuel Rods (St. Lucie 2)
PASS Core Damage Assessment Procedure (St. Lucie 2)
Control of Heavy Loads, Phase I (St. Lucie 2)
Underground Cable Insulation (St. Lucie 1)
Safety Parameter Display System (St. Lucie 1 & 2)
Inadequate Core Cooling Instrumentation (St. Lucie 1 & 2)
NUREG-0737, Generic Letter (GL) 83-37 (St. Lucie 1 & 2)
Code Error in EXXON Analysis (St. Lucie 1)
LOCA Outline, Compliance with 10 CFR 50.46 (St. Lucie 1 & 2)
_. ~ - _ _. -... -,
32 Masonry Wall Design (St. Lucie 1)
Control of Heavy Loads, Phase II (St. Lucie 1 & 2)
GL 83-28, Items 3.1.3 and 3.2.3 (St. Lucie 1 & 2)
Use of Instrumented Inspection Technique (St
. Lucie 1)
ASME Code Update (St. Lucie 1 & 2),10 year Inspecti Interval (St. Lucie 1) on Steam Generators GL 85-02 (St. Lucie 1 & 2)
GL 83-28, Items 3.1.1, 3.2.1, 3.2.2, 4.1 and 4 5 1 (S 1 & 2)
. Lucie GL 83-28, Item 1.1 (St. Lucie 1 & 2) 15 Percent Steam Generator Tube Plugging (St. Luc GL 83-28, Item 1.2 (St. Lucie 1 & 2)
GL 83-28, Item 3.1.2 (St. Lucie 1 & 2)
CE Large Break LOCA Analysis (St. Lucie 2) 2.
NRR - Licensee Meetings November 9, 1984 Cycle 2 Reload June 4, 1985 Core Support Barrel Inspection Plan July 10, 1985 8
LOCA Error September 11, 1985 Cycle 7 Reload September 24, 1985 Instrument Inspection Technique September 26, 1985 Security System October 22, 1985 Rod Swap and Cycle 7 Technical Specifications October 30, 1985 LOCA Error (follow up to July 10)
December 18, 1985 Security System December 19, 1985 Detailed Control Room Design Review February 4,1986 CSB Inspection Results
33 3.
NRR Site Visits November 1-2, 1984 Cycle 2 Outage Activities, St. Lucie 2 November 12-14, 1984 Cycle 2 Startup Testing and Plant Activities, St. Lucie I and 2 December 10-13, 1984 Visit Concerning Generic Issue A-45 February 25-28, 1985 Fire Protection Audit April 10-15, 1985 Site Visit Concerning Cycle 7 Planning, St. Lucie 1 June 19-20, 1985 Meeting with Region II to Discuss Licensing Actions October 6-11, 1985 Pilot Audit of St. Lucie SPOS November 17-22, 1985 Core Support Barrel Inspection and Cycle 7 Activities, St. Lucie 1 January 20-25, 1986 Appendix R and Generic Issue A-45 Reviews March 4-6, 1986 Security System April 20-23, 1986 Cycle 3 Outage Activities, St. Lucie 2 4
Commission Briefings None 5.
Schedule Extensions Granted None 6.
Reliefs Granted April 2, 1985 IST of Pumps and Valves, St. Lucie 1 January 13, 1986 IST of Pumps and Valves, St. Lucie 2 7.
Exemptions Granted February 21, 1985 10 CFR 50 Appendix R - Fire Protection, St. Lucie 1
34 8.
License Amendments Issued St. Lucie 1_
December 6, 1985 License Amendment 69 - Changes required by 10 CFR 50.72 and 50.73 and miscellaneous changes in definiticns and administrative controls December 12, 1985 License Amendment 70 - Change to linear heat generation rate LC0 from a constant value to an axially dependent limit January 15, 1986 License Amendment 71 - Allows continu operation at rated thermal power for a specific time following a dropped control assembly January 15, 1986 License Amendment 72 - Adds auxiliary feedwater actuation system instrumen-tation to the Technical Specifications St. Lucie 2 November 9, 1984 License Amendment 8 - Technical Specifi-cation changes asscciated with Cycle 2 March 1, 1985 License Amendment 9 - Allowed power increase from 2560 MWt to 2700 MWt March 15, 1985 License Amendment 10 - Changed valve tag numbers in continuous purge and station air system October 17, 1985 License Amendment 11 - M:dified surveil-lance requirements with regard to reconnection of pressurizer heaters to their respective buses November 14, 1985 License Amendment 12 - Limits the use of the 8-inch containment purge system December 6, 1985 License Amendment 13 - Changes required by 10 CFR 50.72 and 50.73 and miscel-laneous changes in definitions and administrative controls April 28, 1986 License Amendment 14 - Changes to moderator temperature coefficient to provide more operating flexibility and remove restrictive operational require-ments above 70 percent power
35 9.
Emergency Technical Specifications Issued None 10.
Orders Issued June 27, 1985 Order Modifying license confirming additional licensee commitments on emergency response capability (Supplement I to NUREG-0737) 11.
Status of Licensing Backlog At the conclusion of the SALP period, the consisted of the following items:
licensing backlog St. Lucie 1 TMI Related MPA 9
11 Plant Specific 7
_S t. Lucie 2 TMI Related MPA 6
10 Plant Specific 16 0.
Investigations and Allegation Review No significant investigations were conducted during this eval period.
uation E.
Escalated Enforcement Actions 1.
A Severity Level III (Supplement May 22, 1985, for failure to provide fire protection fI) violation wa ensure that Unit 2 systems necessary to achieve and maintai eatures to shutdown conditions are maintained free from fire damag n hot penalty was not imposed because A civil reported it promptly, and took decisive actionFPL discovered the pro recurrence.
to preclude its 2.
A Severity Level III (Supplement IV) violation was issued April 24, 1986, for failures to establish radiological control procedures for steam generator work and to individual exposure evaluations during that workperform adequate was not imposed area of concern. because of FPL's good prior performance in theA
. - - - - ~,
36 3.
One order was issued as noted in paragraph V.C.10.
F.
Licensee Conferences Held During Appraisal Period 1.
January 22, 1985 Management meeting in preparation for the 10 CFR 50 Appendix R inspection 2.
March 28, 1985 Enforcement Conference regarding 10 CFR 50, Appendix R violations and inoperable containment isolation valves 3.
February 26, 1986 -
Enforcement Conference to discuss a potential overexposure during steam generator sludge lancing
~
~
G.
Confirmation of Action Letters CAL 50-335/85-01 was issued on September 4, 1985, to document the NRC's concurrence with FPL's commitment to administratively restrict the Linear Heat Generation Rate to 14.0 kw/ft for the remainder of Cycle 6 for St. Lucie Unit 1.
H.
Licensee Event Report Analysis During the assessment period, 15 LERs for Unit 1 and 21 LERs for Unit 2 were analyzed by the NRC staff to determine cause. The distribution of these events was as follows:
Number of LERs Cause Unit 1 Unit 2 Comporent Failure 2
9 Design 2
Construction, Fabrication, Installation 2
1 Personnel
- Operating Activity 2
3
- Maintenance Activity 3
4
- Test / Calibration Activity 3
2
- Other Activity 1
Other 1
1 TOTAL 15 21 r-
37 1.
Enforcement Activity Unit Summary FUNCTIONAL AREA NO. OF DEVIATIONS AND VIOLAT SEVERITY LEVEL D
V IV III II I
UNIT NO.
1/2 1/2 1/2 1/2 1/2 1/2 Plant Operations Radiological Controls (*)
0/1 2/2 0/1 Maintenance 1/0 Surveillance
, Fire Protection 2/2 Emergency Preparedness 0/2 0/1 Security Outages 1/1 Quality Programs and 1/1 3/2 Administrative Controls Affecting Quality Licensing Activities Training Total
~
0/1 1/2 8/9 1/1 Facility Summary FUNCTIONAL AREA NO. OF DEVIATIONS AND VIOLATIO SEVERITY LEVEL D
V IV III II I
Plant Operations Radiological Controls (*)
1 4
1 Maintenance 1
Surveillance Fire Protection 2
1 Security Outages 1
Quality Programs and 1
3 Administrative Controls Affecting Quality Licensing Activities Training Total
~
1 2
12 2
(*) Additional apparent violations' were issued af ter the SALP period as discussed in the Radiological Controls ana end of the s.
i l
L-
38 J.
Reactor Trips this evaluation period for Unit 1.Three unplanned react uring The unplanned trips are listed belo and seven manual shutdowns.
1.
Unit 1 December 19, a.
power on a low steam generator (SG) wate "B" diesel generator breaker The was being racked out for inspection when a failed relay actuated the breake spring, closing the breaker and thereby generator.
The ensuing electrical motorizing the resulted in the loss of a main feedwat system realignment level.
plant.
b.
March 7, 1985 - The reacter tripped as a result of a protection system logic matrix test. suspected oper All systems functioned normall hours. y and the plant was returned to service in about seven The trip was subsequently found to have resulted fro a faulty matrix relay trip select switch (see next paragraph).
February 6,1986 - The reactor tripped from full power w c.
operatioris personnel were performing the monthly reactor protection system logic matrix test.
relay trip select switch.The trip was caused by a faulty matrix prior to restart of the unit. replaced and the logic matr The switch was 2.
Unit 2 a.
November 19, 1984 -
percent power while conducting a plant startup.The pump failure caused A condensate a loss of a 4160 volt bus with numerous associated alarms an,d indications and the operator jud prudent to manually trip the reactor.
normally and the reactor was promptly All systems functioned condensate pump was inspected and repaired, restarted whi.e the b.
November 19, 1984
- While conducting a recovery from the previous trip, a second reactor trip occurred because of a spurious high startup rate (SUR) spike.
minute (DPM) SUR was being maintained when a noiseA 1.0 de briefly increased the SUR above the 2.49 DPM trip setpo spike The operators were subsequently cautioned to maintain th at or below 0.5 DPM.
L 'o 39 c.
November 21, 1984 -
The reactor tripped from 68 percent because of a turbine trip caused by a loss of main power excitation.
The generator field was lost as the result of a a or failed pedestal bearing on the generator's service after completion of exciter repairs. s exciter.
All 4
d.
November 29, 1984 - The reactor tripped on a SG low water level signal caused by a closure of the "B" main steam isolation valves (MSIVs The MSIVs had received an isolation signal because).
of a blown fuse on the "A"
safeguards channel.
e.
December 18, 1984 -
The reactor tripped from 50 percent pow pump (MFP) trip on low suction pressu "A" main feedwater er loss of feedwater flow.
The MFP trip was caused by improperly venting the "B" condensate pump while placing it in service.
Attempts to restart the "A" MFP before reaching the low SG 1evel trip were unsuccessful.
was not operating at the time, started automatically but i The "B" MFP, which isolation valve breaker tripped on overcurrent valve stroked open, before the f.
December 19, 1984 -
power as the resultThe reactor tripped from about 25 percent of a turbine trip on low condenser vacuum.
A power reduction from 50 percent had been initiat to repair a cracked condensate pump recirculation li the line separated and vacuum was lost before repairs ne, but be effected.
The ensuing outage was could reactor coolant pump seals and safety injection valves extended to repair g.
April 8, power while conducting a1985 - The reactor tripped from startup from a outage.
SG maintenance SG low water level trip. Improper operator control of feedw the unit was promptly restarted.All systems functioned normally and h.
April 8, 1985 - The reactor tripped from 15 percent power while conducting a recovery startup from the trip discus above.
Operating air to a main feedwater regulating valve (MFRV) was improperly aligned after post maintenance testing on the valve, causing the valve to performing fail open when placed in service.
SG level increased to the main turbine trip setpoint, which, in turn, tripped the reactor.
realign the system after testing.A citation was issued
,n-
e-p
,., p 40-1.
April 17, 1985 - The reactor was manually trip percent power to prevent the loss of secondary ped from 99 inventory through open moisture system water j
atmospheric relief valves.
An separator reheater (MSR)
('
electrical (OEH) control-system, somehow (unex spike, which closure of all the MSR relief valvesfour turbine intercept valves purious-causing to open.
The unit -was restarted 'with the stipulation that maintenance permitted at. power. future nonroutine DEH not be both St. 1.ucie units. feature has since been remo The IV closure or J.
April 17,1985 -
improper manual control oThe reactor tripped from 20 when power recovery from the trip discusse,f SG water level during the which,-in turn, tripped the reactor.resulted in k.
July 18, 1985 -
ground isolation procedure at 100 percent pow of a the aperating procedure for DC ground isolation dire t An error in operators to remove the fuses ce the for the MSIV closure logic circuitry causing the "A" MSIV to close and the reactor to trip on asymmetric SG pressure.
ground isolation procedure, failure to adequately r
t 1.
August 8,1985 - The reactor tripped from full power wh incorrectly sized fuse in an electrical supply to the en an engineered safeguards actuation cabinet blew.
a matt.
steam isolation signal and a reactor trip on low SGTh leni.
Tne reactor co.)lant neat during the transient becauso a containmentpump seals were dama damaged seals were replaced during t i
isolation had a s.
The i
m.
September 9 1985 - The reactor was manually tripped from full power, hen high vibrations occurred on reacto w
pump (RCP) 2A2.
RCP shaft vibration had damaged n
components on the motor lower oil reservoir.
internal had previously on August 22 while The oil seal failed was incurred during a minor oil fire on Augu attempting to had been completed and the unit was returned to service Repairs September 7, only to suffer recurrent RCP high vibration on September 9.
modified as recommended by the vendor to n
i
o,o f..
41 January 7,1986 - The reactor was manually trip n.
power when a turbine cooling water (TCW) leak deve the main u
generator exciter housing.
The TCW leak was n
repaired and the unit was restarted.
January 7,1986 - The reactor tripped from 12 percen o.
while conducting a recovery from the previous tri power above.
A power spike to above 15 percent occurred wh synchronizing the turbine to the grid, causing the local e
power density reactor trip circuitry to automatically and trip the reactor.
Plant enable modified to caution operators to remain at operating procedures were the axial shape index is favorable for power escal tilow a on.
p.
January 11, 1986 -
The reactor was tripped from full when an operator, who was conducting the weekly turbine power
- overspeed trip mechanism test,
" Trip" lever instead of the " Test" erroneously operated the in turn, caused the reactor trip.lever; the turbine trip, counselled The operator was
" Trip" concerning his inattention to detail and the
" Test" lever. lever was painted rad to distinguish it from the
-,y,
- - _ _. _ -.