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| {{Adams
| | #REDIRECT [[IR 05000413/1997009]] |
| | number = ML20210N734
| |
| | issue date = 08/18/1997
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| | title = Insp Repts 50-413/97-09 & 50-414/97-09 on 970608-0719. Violations Noted.Major Areas Inspected:Aspects of Licensee Operations,Maint,Engineering & Plant Support
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| | author name =
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| | author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
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| | addressee name =
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| | addressee affiliation =
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| | docket = 05000413, 05000414
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| | license number =
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| | contact person =
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| | document report number = 50-413-97-09, 50-413-97-9, 50-414-97-09, 50-414-97-9, NUDOCS 9708260105
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| | package number = ML20210N708
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| | document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
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| | page count = 32
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| }}
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| See also: [[see also::IR 05000413/1997009]]
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| | |
| =Text=
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| {{#Wiki_filter:.
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| . . . . . . . _ ,
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| Notice of Violation 3
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| withholding of such material, you muit tpecifically identify the portions of
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| your response that you seek to have witkield and provide in detail the bases
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| l
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| '
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| for your claim of withholding (e.g., explain why the disclosure of information
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| will create an unwarranted invasion of personal privacy or provide the
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| ,
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| confidential commercial or financial information). If safeguards information
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| l 1s necessary to provide an acceptable response, please provide the level of
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| protection described in 10 CFR 73.21.
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| Dated at Atlanta, Georgia
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| this 18th day of August, 1997
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| l
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| Enclosure 1
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| 1
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| U. S. NUCLEAR REGULATORY COMMISSION
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| REGION 11
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| Docket Nos: 50-413, 50 414
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| License Nos: NPF-35. NPF-52
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| Report Nos.. 50-413/97 09. 50 414/97-09
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| Licensee: Duke Power Company
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| Facility: Catawba Nuclear Station. Units 1 and 2
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| Location: 422 South Church Street
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| l Charlotte. NC 28242
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| Dates: June 8 - July 19, 1997
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| Inspectors: J. Zeiler. Acting Senior Resident inspector
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| R. L. Franovich, Resident inspector
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| M. Giles. Resident inspector (In Training)
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| N. Economos Region 11 Inspector (Sections M8.1. 2. 3. 4)
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| R. M. Moore. Region 11 Inspector (Sections 08.1. E2.1 )
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| Approved by: S. M. Shaeffer. Acting Chief
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| Reactor Projects Branch 1
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| Division of Reactor Projects
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| l
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| I
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| Enclosure 2
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| 9708260105 970818
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| PDR ADOCK 05000413
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| 0 PDR
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| . .
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| . .
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| -
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| . _ . __ _. _ _ _ _ _ _ _
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| _____ - _ _ __ -
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| EXECUTIVE SUMMARY
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| Catawba Nuclear Station. Units 1 & 2
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| NRC Inspection Report 50 413/97-09, 50 414/97 09
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| This integrated inspection included aspects of licensee operations.
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| maintenance, engineering, and plant support. The report covers a 6-week
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| period of resident ins)ection; in addition, it includes the results of
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| announced inspections ay Regional reactor safety inspectors.
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| Doerations
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| e
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| A Non Cited Violation (NCV) was identified for failure to declare three
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| ice condenser intermediate deck doors inoperable and log an associated
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| Technical Specification Action item Log entry after identifying ice
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| buildup on the doors. This item along with several other minor human
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| performance weaknesses indicated a need for greater attention to detail
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| and questioning attitude by operations personnel during the performance
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| of routine activities (Section 01.1).
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| e
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| The root cause evaluations of a reactor coolant pump trip and subsequent
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| reactor trip were adequatel
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| involve human error or nonconservative y performed. The cause
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| decision of theThe
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| making. trip protective
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| did not
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| relaying associated with the short bus of 2TB functioned as designed.
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| However, a delay in troubleshooting activities to locate the source of
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| the associated ground indicated that the ground received a low priority
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| status in the work schedule and that trained personnel were not readily
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| available to troubleshoot ground indications in a timely manner (Section
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| w.2).
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| *
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| Control room operators were effective in precluding a turbine runback by
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| reducing reactor power to 50% before the 28 Main Generator Power Circuit
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| Breaker opened on low air pressure. The licensee's root cause
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| evaluation was detailed, and actions to prevent recurrence were
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| considered adequate (Section 01.3).
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| *
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| The decision to deviate from the preferred normal alignment of
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| Lower Containment Ventilation Unit (LCVU) operation to support
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| planned maintenance exhibited non-conservative work scheduling and
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| operatorjudgement. This resulted in lower containment air
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| temperature increasing slightly above the adjusted Technical
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| Specification limit for a brief period of time. The LCVU
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| operating procedures did not address the adverse impact of
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| removing two LCVUs from service simultaneously, nor did the
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| procedure address the interaction between LCVU operation and
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| integrated containment ventilation systems. These procedural
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| inadequacies were identified as a NCV (Section 01.4).
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| *
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| A violation (first example) for failure to follow procedure was
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| identified related to Operations failure to adequately document 10 CFR
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| 50.59 screening evaluations (Section 08.1).
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| Enclosure 2
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| _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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| 2
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| Maintenance
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| e A Failure In!estigation Process (FIP) team was thorough in investigating
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| the cause of an electrical flash in a 600 Volt breaker cubicle
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| associated with Motor Control Center 2MXM. The root cause indicated
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| configuration and procedure weaknesses in the method of locking out 600
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| Volt breaker cubicles to the maintenance position. Adaquate corrective
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| actions to prevent recurrence of this incident were implemented (Section
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| M1.1).
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| e
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| The licensee's identification of a technician's failure to follow a leak
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| rate test procedure that resulted in an invaild test of valve 2NV-874
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| during the previous refueling outage was an example of good questioning
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| attitude: however, the procedure completion review was untimely. The
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| Plant Operations Review Committee performed a thorough review of
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| subsequent activities to aroperly retest the valve. Good engineering
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| support was arovided, bot 1 in developing a leak rate test procedure and
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| briefing paccage for the evolution. The failure to follow the leak rate
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| test procedure was identified as a Violation (Section M1.2).
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| Enaineerina
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| e The licensee's identification of a discrepancy between primary and
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| secondary thermal power indication exhibited attention to detail in the
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| review of plant data. Actions to initiate a FIP team to investigate the
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| root cause were appropriate and steps to reduce reactor power until the
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| discrepancy was understood were conservative. Replacement of a faulty
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| T,,, card was well-planned, coordinated and controlled and executed in
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| an expediticas manner (Section El.1).
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| o Resolution of Design Base Document (DBD) open items was generally
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| adequate. However, a violation (second example) for failure to follow
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| procedure was identified related to Engineering's failure to enter DBD
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| open items into the Problem identification Process as required by
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| procedure and stated in the licensee's response to the Des'.gn Basis
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| 50.54f letter (Section E2.1).
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| e The licensee's corrective action audit that assessed the resolution of
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| Self-N iated Technical Audit findings was identified as a strength in
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| correc " ve action performance (Section E2.1).
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| e The licensee adequately addressed the Emergency Diesel Generator 10 CFR
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| Part 21 issue related to potentially defective intake / exhaust springs
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| (Section E2.1).
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| * Based on in-office review of the licensee *s March 31, 1997, annual
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| summary on 10 CFR 50.59 changes, onsite review of the licensee's 10 CFR
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| 50.59 evaluations, and audit of the licensee's procedures, the inspector
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| concluded that the licensee had complied with t1e provisions of the
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| regulation for the changes listed in the annual summary (Section E3.1).
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| Enclosure 2
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| -
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| ,
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| 3
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| Plant Suncort
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| e Radiological control practices observed during the inspection period
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| were considered to b(. proper (Section R1.1).
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| l
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| l
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| Enclosure 2
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| ,
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| -
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| - _
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| _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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| I
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| Reoort Details
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| ; Summary of Plant Status
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| ,
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| Unit 1 operated at or near 100% power during the inspection period.
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| l On June 26, a Unit 2 reactor trip occurred on low Reactor Coolant System loop
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| l
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| i
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| flow as a result of an electrical ground fault which de energized the
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| electrical bus that powers the "2B' Reactor Coolant Pump (RCP). The unit was
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| returned to 100% power operation on June 29. Power was reduce 1 to 50% on July
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| 2 to preclude a turbine trip / reactor trip u)on the anticipated failure of ;
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| Main Generator Power Circuit Breaker (PCB) 23. A solenoid (or pilot) valve '
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| associated with the air supply to all three main generator PCB poles had
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| failed, rendering the air system unable to deliver air to the breaker. The
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| solenoid valve was replaced, and the unit was returned to 100% power the
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| following day. Reactor power was reduced to 99.3% on July 15 in response to a
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| discrepancy between primary and secondary thermal power indications. The
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| discrepancy was attributed to feedwater venturi defouling and hot leg
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| streaming, and did not reflect an actual temperature difference. The unit
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| returned to 100% power on July 17 and operated at or near 100% power for the
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| remainder of the inspection period.
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| Review of UDdated Final Safety Analysis Report (UFSAR) Commitm_gn_t1
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| While performing inspections discussed in this report, the inspector reviewed
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| the applicable portions of the UFSAR that were related to the areas ins)ected.
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| The inspector verified that the UFSAR wording was consistent with the o) served
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| plant practices, procedures, and/or parameters.
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| I. Operations
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| 01 Conduct of Operations
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| 01.1 General Comments (71707)
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| The inspector conducted frequent control room tours to verify proper
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| staffing operator attentiveness and communications. and adherence to
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| approved )rocedures. The inspector attended daily operations turnover
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| and Site )irection meetings to maintain awareness of overall plant
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| operations. Operator logs were reviewed to verify operational safety
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| and compliance with Technical Specifications (TS). Instrumentation,
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| computer indications, and safety system lineups were periodically
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| reviewed from the Control Room to assess o)erability. Plant tours were
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| conducted to observe equipment status and Jousekeeping. Problem
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| Identification Process (PIP) reports were routinely reviewed to assure
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| that potential safety concerns and equipment problems were reported and-
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| resolved,
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| in general, the conduct of operations was professional and safety
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| conscious. Good )lant equipment material conditions ar.d housekee ing
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| were noted througaout the report period. However, as addressed b low,
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| sevcral minor operator human performance deficiencies were identified
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| Enclosure 2
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| _ _ _ _ _ _ _
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| .
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| ,
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| 2
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| involving a failure to enter a TS Action Statement, failure to identify
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| equipment status anomalies, and failure to properly document a Technical
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| Specification Action item Log (TSAIL) entry.
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| Failure to Declare Unit 2 Ice Condenser Intermediate Deck Doors
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| inoDerable and Enter ADolicable TS Action Statement
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| On June 17 at 2:38 p.m., while performing the weekly TS surveillance on
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| the intermediate deck doors the licensee identified that three doors
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| had ice buildup (reported to be less than one half inch thick). The
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| function of these doors is to open during a des.gn basis accident to
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| ensure that the containment loss Of Coolant Accident (LOCA) atmos)here l
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| would be diverted through the ice condenser. Upon discovery of t1e ice,
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| a test procedure discrepancy was entered and a work request was
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| initiated to remove the ice. However, work to remove the ice or
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| investigate the extent of the impact on the door opening function was
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| not initiated due to problems with personnel accessing containment
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| through the containment airlock door. Later that night, the oncoming
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| Shift Work Manager became aware of the previces day's problem and
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| -contacted engineering personnel to perform an operability evaluation of
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| the condition. The following morning, the inspector reviewed the
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| results of this evaluation. The evaluation concluded that the " ice
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| condenser" was operable. This was based primarily-on a previous McGuire
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| Nuclear Station analysis that showed up to one-third of the intermediate
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| deck doors could fail to open and there would still be enough ice
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| condenser flow area for LOCA heat removal. The inspector determined the
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| evaluation focused to narrowly on the ice condenser system operability
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| and failed to adequately evaluate the operability of the intermediate
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| deck doors, especially with regard to consideration of information in
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| the applicable TS and Bases.
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| TS 3.6.5.3 requires the intermediate deck doors be operable in Modes 1-
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| 4. TS Surveillance Recuirement 4.6.5.3.2 requires a 7-day verification
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| that the intermediate ceck doors be closed and free of frost
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| accumulation. The TS Bases also states that impairment by ice, frost.
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| or debris is considered to render the doors inoperable, but capable of
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| opening. Based on this, the inspector concluded that operations
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| personnel had failed to declare the three doors inopera]le and follow
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| the Action Statement of TS 3.6.5.3.a when the problem was initially
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| identified. This action statement allowed power operation to continue
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| for up to 14 days provided ice bed temperature was monitored at least
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| once per four hours and the maximum ice bed temperature was maintained
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| less than or equal to 27*F. The licensee initiated PIP 2-C97-2014-to
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| investigate this incident.
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| On June 18. after repairing the containment airlock, ice was removed
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| from the three intermediate deck doors. The cause of the ice buildup
| |
| was found to be the failure of heat tracing on an ice condenser air
| |
| handling fan drain line, which prevented adequate draining of defrost
| |
| condensate. The heat tracing was subsequently repaired. The licensee
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| Enclosure 2
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| -
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| ,
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| 3
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| i
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| determined during activities to remove the ice that all three doors were
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| l not blocked to the extent that would have prevented their opening during
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| '
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| a LOCA. The inspector also noted that the ice bed monitoring system was
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| operational during the period that ice was on the doors and control room
| |
| annunciator alarms would have alerted the operators of anomalous ice bed
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| temperatures. Therefore, the ins)ector considered the safety
| |
| consequences of this incident to )e minimal.
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| The inspector reviewed Operations Management Procedure (OMP) 2-29.
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| Technical Specifications Action Item Log. Step 3.4 requires that non-
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| compliance with a Limiting Condition For Operation requiring operation
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| in a TS Action Statement, be logged in TSAll. The ins)ector determined
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| that a TSAll entry was not logged for this condition w1en ice was
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| identified on the doors rendering them inoperable. The failure to
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| declare the doors inoperable and enter a TSAll entry for t % applicable
| |
| TS Action Statement in accordance with OMP 2-29 was identitied as a
| |
| Violation of TS 6.8.1. Procedures and Programs. This failure to follow
| |
| procedures constitutes a violation of minor significance and is being
| |
| treated as a Non-Cited Violation (NCV). consistent with Section IV of
| |
| the NRL Enforcement Policy. This item is identified as NCV 50 414/97-
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| 09 01: Failure to Declare Ice Condenser Intermediate Deck Doors
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| Inoperable and Log Appropriate TSAll Entry.
| |
| Auxiliary Shutdown Panel Volume Control Tank (VCT) Instrumentation Drift
| |
| During a walkdown of the four Motor Driven Auxiliary Feedwater Shutdown
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| Panels, the inspector identified that three of the four VCT level
| |
| indications were not reading accurately. There is one VCT gauge on each
| |
| Shutdown Panel. Gauge indications differed from control room
| |
| indications by as much as 20 percent level. The ins)ector alerted
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| operations-personnel to-the problem and noted that t1ey were very
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| responsive in initiating corrective actions. Due to subsequent problems
| |
| in calibrating the gauges and unavailability of like parts, engineering
| |
| modifications were developed and implemented to replace the gauges with
| |
| more accurate models. Based on discussions with Instrumentation and
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| Electrical (IAE) personnel, it was indicated that most likely, the
| |
| gauges had drifted out of accuracy over a long period of-time.
| |
| The inspector reviewed periodic surveillance test procedures associated
| |
| with verifying Shutdown Panel instrumentation indications. VCT level
| |
| was not among the indications checked periodically. The inspector
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| noted. however, that VCT level was not required by TS to be o)erable
| |
| from the Shutdown Panels. However, the VCT indication could )e
| |
| potentially used during operation from the Shutdown Panels. It was also
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| apparent that-there had been opportunities to have identified the gauge
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| output drift during the periodic surveillances of other Shutdown Panel
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| instrumentation.
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| Enclosure 2
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| _________ __- _ _ .
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| -
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| l 4
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| Unit 2 Power Rance Channel NI-42 Soare Window Illuminated
| |
| On June 27. 1997, the day after Unit 2 tripped on low Reactor Coolant
| |
| System flow, the inspector noticed an annunciator window on the Nuclear
| |
| Instrument (N1) 42 Power Range drawer that was illuminated. The
| |
| annunciator window was labeled " spare" and appeared to serve no
| |
| function. The inspector questioned the control room operators about the
| |
| illuminated window. The window apparently first illuminated following
| |
| the trip; however, the operators were not aware that the window was
| |
| illuminated, nor the reason for the condition. Based on subsequent
| |
| discussions with reactor engineering personnel, the inspector learned
| |
| that this spare annunciator window was previously used as the negative
| |
| rate trip indication light. During the previous refueling outage. this
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| trip function was isolated from the reactor protection logic, the
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| modification that implemented the rate trip change was supposed to have
| |
| removed the bulb from these windows on all of the N1 drawers. .It was
| |
| believed that the bulb in the NI-42 drawer was removed, but may have
| |
| been reinstalled by lAE personnel by mistake during subsequent NI
| |
| maintenance activities following the refueling outage. The light was
| |
| extinguished once the rate trip function was reset and the bulb. removed.
| |
| The licensee initiated a PIP to address this problem.
| |
| TS Loaaina Error for Trackina Containment Airlock Door Seal Surveillance
| |
| lRR
| |
| On July 11, 1997, during review of the Unit 2 TSAIL. the inspector
| |
| noticed an incorrect entry that was made on July 9. The entry was for
| |
| tracking a TS required 72 hour airlock door seal test following opening
| |
| of the airlock door on July 9. The time required for the test to be
| |
| performed was listed in TSAIL as July 16 instead of July 12. The
| |
| inspector discussed the error with operations personnel who corrected
| |
| the entry. It was also indicated that the seal test was scheduled to be
| |
| performed that same day. Based on this, the inspector determined the
| |
| test would not have been missed even though the TSAll was incorrect.
| |
| The inspector was concerned that the TSAll error had not been identified
| |
| over the two previous two days that the problem existed.
| |
| Individually, the above problems had little actual safety consequences.
| |
| however, in the aggregate represented the need for greater attention to
| |
| detail and questioning attitude by operations personnel during the
| |
| performance of routine activities.
| |
| 01.2 Unit 2 Reactor Trio on low Reactor Coolant System Flow-
| |
| a. Insoection Scope (71707. 937,01).
| |
| On June 26 a Unit 2 reactor trip from 100% power occurred when the 2B
| |
| Reactor Coolant Pump (RCP) tripped and caused a loss of flow signal in
| |
| the associated loop. The inspector discussed the unit trip with
| |
| engineering, operations and maintenance personnel, as well as reviewed
| |
| the associated electrical diagrams. Unit Trip Report and Pl? 2-C97-2221.
| |
| Enclosure 2
| |
| | |
| l 5
| |
| i b, Observations and Findinas
| |
| i
| |
| !
| |
| On June 21. a negative leg ground was detected on ron vital distribution
| |
| bus 2CDB. The ground subsequently was traced to tre 125 VDC control
| |
| l power circuit of breaker 2T6 6. On June 26. the b"eaker was opened to
| |
| '
| |
| facilitate troubleshooting the cause of the ground. The Instrument and .
| |
| Electrical (IAE) technicians noticed that the breaker failure initiation l
| |
| relay in 2TB 6 control cubicle was chattering, but continued with their i
| |
| troubleshooting activities. Shortly thereafter, a reactor trip
| |
| occurred.
| |
| The licensee determined that. the source of the ground fault was the
| |
| breaker pushbutton, a Cutler-Hammer E30 model, lhe pushbutton had '
| |
| failed and created a negative leg-to ground fault on 2CDB. The
| |
| pushbutton internals had changed state when 2TB 6 was tripped open
| |
| during troubleshooting, introducing a fault path to the positive leg.
| |
| Noise from the cabinet ground was induced through the switch and the
| |
| breaker failure initiation relay (94B) coil, causing it to chatter and
| |
| eventually actuate to trip the incoming breaker on the short bus of 2TB.
| |
| The auto close function of the 2TB tie breaker was blocked by a lockout
| |
| rela
| |
| bus,y, and the bus de-energized. The 2B RCP. which is supplied from the
| |
| tripped, and the subsequent low flow in the B loop caused a reactor
| |
| trip.
| |
| The inspector discussed the reactor trip with operations and engineering
| |
| personnel to determine if the root cause involved a human error. The
| |
| chattering of the relay, generated when 2TB 6 was opened, could have
| |
| been stop)ed if the IAE technicians had reclosed the breaker when they
| |
| noticed tlat relay chattering. However, they did not understand what
| |
| was causing the chattering at the time. The inspector concluded that
| |
| the IAE technicians responded appropriately by leaving the breaker in
| |
| the opened position since the cause and impact of the relay chattering
| |
| were not understood.
| |
| The inspector inquired about the time delay between ground detection
| |
| (identified on a Saturday) and troubleshooting activities (initiated the
| |
| following Wednesday). l.icensee personnel indicated that Single Point Of
| |
| Contact (SPOC) technicians were not trained and qualified to use the
| |
| ground chasing equipment. As a result a'stempts to locate the ground
| |
| could not be made until the following Monday when a trained IAE
| |
| technician would be available. Also, priority status was not associated
| |
| with troubleshooting the ground indication early in the week. In
| |
| addition, the inspector determined that only two techniciant on site
| |
| were fully qualified to use the ground-chasing equipment to locate the
| |
| source of a ground, and that_one of those technicians had been offsite
| |
| since February and was not scheduled to return until October of this
| |
| year. A shortage of trained personnel available to perform the
| |
| troubleshooting contributed to the delay. At the end of the ins)ection
| |
| period, the delay in investigating the ground, associated contri)uting
| |
| factors, and appropriate corrective actions were not addressed within
| |
| the licensee's corrective action program.
| |
| Enclosure 2
| |
| | |
| .
| |
| 6
| |
| The unit was restarted on June 28 after trip list activities were
| |
| performed and minor equipment problems were corrected. The licensee is '
| |
| planning to document the reactor trip in a Licensee Event Report.
| |
| l c. Conclusions
| |
| The inspector concluded that root cause evaluations of the reactor trip
| |
| were adequately performed. The cause of the tt!p did not involve human
| |
| error or non conservative decision making. The protective relaying
| |
| associated with the short bus of 2TB functioned as designed. The
| |
| inspector determined that, although the delay in troubleshooting
| |
| activities to locate the source of the ground did not affect the outcome
| |
| (reactor trip), challenges existed in the following areas: (1)
| |
| associating appropriate priority to locating ground indications in a
| |
| timely manner, and (2) ensuring that trained personnel are avullable to
| |
| troubleshoot ground indications. At the end of the inspection period,
| |
| efforts to address the delay, understand its causes, and identify
| |
| corrective actions were not evident in the licensee's corrective action
| |
| program.
| |
| '
| |
| 01.3 Unit 2 Downoower in Response to Generator Outout Breaker Trouble
| |
| a. insoection Scone (71707)
| |
| On July 2. Unit 2 control room operators received a generator breaker
| |
| trouble alarm and identified a continuous decrease in minimum close air
| |
| 3ressure on 28 Main G2nerator Power Circuit Breaker (PCB). Operators
| |
| Jegan a rapid load reduction, and the PCB automatically tripped after
| |
| reactor power reached 50%. The inspector reviewed PIP 2 C97 2177 and
| |
| discussed the downpower and associated equipment failure with licensee
| |
| personnel.
| |
| b. Observations and Findinos
| |
| On July 2, the Main Generator PCB 2B Trouble annunciator alarmed in the
| |
| control room. Control room operators determined that there was a
| |
| continuous decrease in air 3ressure on the 28 Main Generator PCB,
| |
| indicating an approach to 11e minimum air pressure is required to open
| |
| the breaker. Air
| |
| ' the resulting arc. pressure is required
| |
| Since the to openofthe
| |
| safety function thebreaker andtodissipate
| |
| PCB was open, it
| |
| was designed to automatically open before the minimum pressure required
| |
| for this function is reached. The minimum tri
| |
| Generator PCB 2B is between 446 and 452 psig. p pressure on Main
| |
| To preclude an automatic turbine runback on the potential automatic
| |
| opening of the PCB operators began a rapid load reduction, The PCB
| |
| automatically tripped after reactor power reached 50%. No overcurrent
| |
| alarms were received on Main Transformer 2A.
| |
| The license deternJned that a solenoid (or )ilot) valve associated with I
| |
| s
| |
| the air sup)1y to a:1 three main generator )CB poles had failed,
| |
| rendering t1e air system unable to deliver air to the breaker.
| |
| Normally, the solenoid valve receives signals from the breaker poles to
| |
| Enclosure 2
| |
| V
| |
| | |
| i
| |
| 7
| |
| ,
| |
| supply air to them. When the air pressure on any pole reaches
| |
| a> proximately 485 psi.-a pressure switch actuates and the solenoid valve
| |
| sluttles to pneumatically control a regulator that delivers air to the
| |
| breaker poles. When air pressure is restored to 500 psi the signal
| |
| '
| |
| from the pole to the solenoid is terminated.
| |
| Station PIP 2-C97-2177 documented the root cause of the solenoid
| |
| failure. The failed solenoid was new and had been installed during the
| |
| April 1997 refueling outage. The component failure was attributed to a
| |
| deformed nylon bushing. The valve had been assembled to compensate for
| |
| the defect which initially allowed the valve to operate as designed.
| |
| However, the valve's internal components drifted from their assembled
| |
| positions over time and eventually were unable to engage with the
| |
| valve's lower assembly, thereby preventing air flow to the poles.
| |
| To address the potential that newly purchased solenoid valves could be
| |
| installed with problems, the licensee had revised procedure
| |
| IP/0/B/4974/01, Main Generator PCB Maintenance. - Revision 5 of the
| |
| procedure included a Note between Steps 10.3.7 and 10.3.8. The-Note
| |
| read: "If pilot valve is replaced, ensure pilot valve has been
| |
| disassembled and inspected for pro >er assembly and components. or
| |
| rebuilt prior to installation." T1e inspector verified that this
| |
| procedure change had been made,
| |
| c. Conclusions
| |
| The inspector concluded that control room operators were effective in
| |
| )recluding a turbine runback by reducing reactor power to 50% before the
| |
| 3CB opened. The licensee's root cause evaluation was detailed and
| |
| actions to prevent recurrence were adequate.
| |
| 01.4 Lower Containment Air Temoerature Exceeded for Short Duration
| |
| a. Insnection Stone (71707)
| |
| On June 30. the licensee was performing maintenance on the Unit 2
| |
| Lower Containment Ventilation Units (LCVUs). While the 2A and 20
| |
| LCVUs were out of service, the lower containment temperature
| |
| increased to 117.4'F. The inspector reviewed apalicable operating
| |
| procedures. TS. the FSAR, tagout requirements, tie innage work
| |
| schedule, and PIP 2 C97-2127. The inspector also discussed the
| |
| -issue with operations, engineering and work control personnel.
| |
| b. Observations-and Findinas
| |
| During normal operation. the Containment Chilled Water (YV)
| |
| chillers service various containment loads including the LCt!Us and
| |
| the Reactor Coolant Pump (RCP) Motor Air Coolers. 0_n June 30,
| |
| preventive maintenance (PM) and electrical motor testing were
| |
| scheduled for the 2A and 20 LCVUs. The 2A LCVU was removed from
| |
| Enclosure 2
| |
| | |
| I
| |
| !
| |
| l
| |
| 8
| |
| l
| |
| service first. After the PM for the 2A LCVU was completed, but i
| |
| before motor testing was completed, operations personnel decided
| |
| to remove the 2D LCVU for PM. The 2D LCVU was removed from ,
| |
| service at 10:55 a.m. While both LCVUs were out of service, lower
| |
| containment temperature increased. To compensate for the
| |
| temperature increase, control room operators adjusted the
| |
| o)eration of the remaining inservice LCVUs (2B and 2C) from
| |
| "iormal" to "High Speed." and then to " Max Cool." However, for a !
| |
| brief period of time lower containment temperature had exceeded
| |
| the high high temperature Operator Aid Computer (0AC) alarm
| |
| setpoint of 115.6'F and the adjusted TS limit of 117.2*F.
| |
| ultimately reaching 117.4'F. Lower containment temperature was ,
| |
| '
| |
| above 117'F for approximately 3 minutes before it was restored to
| |
| within TS limits. The Action required by TS 3.6.1.5 was to
| |
| ,
| |
| i
| |
| restore the air temperature to within the limits within 8 hours or
| |
| be in at least hot standby within the next 6 hours. Since the
| |
| .
| |
| !
| |
| bich lower containment temperature existed for only a few minutes. -
| |
| th6 licensee was in compliance with the TS action. .
| |
| At anroximately 11:10 a.m., operations personnel decided to post)one
| |
| the M on the 2D LCVU. recall the associated tags and return the _CVU to
| |
| service until the 2A LCVU was restored to operation. While operators i
| |
| were returning the 2D LCVU to service and all three LCVUs to normal
| |
| alignment, the YV chillers in service (A and C) trip >ed on low flow.
| |
| Based on a review of the circumstances surrounding t1e trip of the A and ,
| |
| C YV chillers, the inspector discerned that the following took place.
| |
| When the B and C LCVUs were taken to " Max Cool" in an effort to reduce !
| |
| lower containment temperature, the flow control valves in the chiller
| |
| loop fully opened as designed, and thermostatic control of,the chilled
| |
| water supply was lost. When operations subsequently restored the D LCVU
| |
| to service and returned the LCVUs to normal operation, thermostatic i
| |
| control of the flow control valves was reinstated. The existing
| |
| temperature caused the flow control valves to throttle closed, and the
| |
| chillers tripped on low load. Normal alignment with the A and B YV
| |
| chillers was established within 30 minutes of the chiller trips. The C
| |
| YV chiller had also been restarted, but tripped after running for 10
| |
| minutes. Shortly thereafter, containment temperatures were restored to
| |
| normal levels.
| |
| Operations surveillance procedure PT/1/A/4600/02A. Mode 1 Periodic
| |
| Surveillance Items. Enclosure-13.1. Periodic Surveillance Items Data,
| |
| approved January 23, 1997, provides surveillance acceptance criteria in -
| |
| accordance with the lower containment temperature limits imposed by TS
| |
| 3.6.1.5. Lower containment minimum and maximum air temperature limits
| |
| are based on the average inlet temperatures of the operating LCVUs.
| |
| Temperature readings associated with non running LCVUs provide
| |
| indication of static air temperature and therefore, are not used to
| |
| determine average containment air temperature. Therefore. temperature
| |
| ':mits are adjusted conservatively as a function of uncertainty (because
| |
| of the reduced sample size) in generalizing local indications to average
| |
| Enclosure 2
| |
| 1
| |
| ..-._..__ ,,
| |
| -
| |
| ,a..
| |
| -
| |
| ._-..,....,--...--m.__- -
| |
| - - - _ _ - _ . . _ . . .-m.
| |
| | |
| 9
| |
| containment air temperature. As the number of LCVUs in service
| |
| decreases, the temperature limit decreases (becomes more conservative).
| |
| With two LCVUs running. the lower containment TS limit of 120*F was
| |
| adjusted to 117.2'F.
| |
| The Containment Lower Compartment Ventilation Subsystem as
| |
| described in the FSAR is designed to maintain a maximum
| |
| temperature of 120*F in the lower compartment during rnrmal plant
| |
| operation. During normal operation, three units (each providing
| |
| 33.3% capacity) are in service, and one unit is on standby.
| |
| Technical Specification Interpretation 3.6.1.5 states that 3
| |
| !
| |
| containment air temperature can be maintained with one active
| |
| component out-of-service (i.e., three LCVUs in service).
| |
| Based upon a review of the FSAR and TS as well as discussions
| |
| with on-shift operators, the inspector determined that the 4
| |
| decision to remove the D LCVU from service while preventive
| |
| maintenance (PM)s on the A LCVU were ongoing was non conservative
| |
| and caused lower containment temperature to exceed the adjusted TS
| |
| limit.
| |
| The inspector also determined that problems existed with procedure
| |
| OP/2/A/6450/01. Containment Ventilation Systems. dated June 15. 1994,
| |
| which controls the configuration of the LCVUs. The procedure did not
| |
| provide adequate guidance to address the impact of removing two LVCus
| |
| from service on lower containment temperature. Operations Management
| |
| Procedure 2-18. Tagout Removal and Restoration Procedure. Revision 46.
| |
| Responsibility 4.8. states that the person placing or removing tag (s)
| |
| shall check procedures affected and any outstanding tagouts associated
| |
| with that procedure / system for any adverse effects. Because the adverse
| |
| impact of removing 2 LCVUs from service was not addressed in the
| |
| procedure, this responsibility could not be effectively realized.
| |
| n addition, procedure OP/2/A/6450/01 did not address the interaction
| |
| between LCVU operation and integrated Containment Ventilation (VV)
| |
| Systems. Step 2.7.3 of OP/2/A/6450/01. Enclosure 4.12. LCVU Additional
| |
| Cooling and YV Chiller Trip Prevention directs the operator to ensure
| |
| that three LCVUs are in the " NORM" position. The performance of this
| |
| step caused the A and C YV chillers to trip. Procedure
| |
| slowly reduce the demand on the system was not provided, guidance
| |
| nor was a to
| |
| precaution or note provided to warn of the potential to induce a chiller
| |
| trip as a function of load demand changes.
| |
| The inspector also noted that no procedure guidance was available for
| |
| swapping between running and_non running LCVU units. OP/2/A/6450/01.
| |
| Enclosure 4.2. Lower Containment Ventilation Unit Startup and Normal
| |
| Operation, provided procedural guidance for starting up the system by
| |
| placing three LCVUs in operation. Enclosure 4.7. Lower Containment
| |
| Ventilation Unit Shutdown provides procedural guidance for shutdown of
| |
| the system by placing all four LCVU switches in the OFF position.
| |
| Enclosure 2
| |
| -
| |
| | |
| l
| |
| 10
| |
| However, no procedural guidance existed for stopping an individual LCVU
| |
| and subsequently restarting it or making other required alignment
| |
| changes needed to facilitate the performance of the PM. The inspector
| |
| recognized that this lack of procedural guidance was unrelated to the
| |
| l
| |
| lower co'itainment temperature increase and the YV chiller trips.
| |
| The inspector also identified a minor discrepancy in the planned
| |
| l innage work schedule. The 2A LCVU had two work items planned to
| |
| be worked which included a PM and electrical motor testing. The
| |
| PM on the 2A LCVU was scheduled to be completed at 12:00 p.m. on
| |
| June 30, 1997. The motor electrical testing on the 2A LCVU was
| |
| scheduled to be completed at 1:00 p.m. on June 30. The PM on the
| |
| 20 LCVU was scheduled to commence at 12:00 p.m. on June 30.
| |
| immediately following the scheduled completion of the PM on the 2A
| |
| LCVU.
| |
| This schedule allowed both the A and 0 LCVUs to be out of
| |
| service for 1 hour, which was non conservative and not in
| |
| accordance with the alignment described in the FSAR.
| |
| c. Conclusions
| |
| The inspector concluded that the decision to deviate from the
| |
| preferred normal alignment of LCVU operation to support planned
| |
| maintenance exhibited non conservative work scheduling and
| |
| operator judgement. As a result. lower containment temperature
| |
| increased slightly above the adjusted TS limit for a brief period
| |
| of time. However, temperatures were reduced below the adjusted TS
| |
| limit within 8 hours as required by the TS action requirement.
| |
| Therefore, exceeding the lower containment air temperature on
| |
| plant equipment had minor safety significance and did not pose a
| |
| threat to safety related equipment. The LCVU operating procedures
| |
| did not address the adverse impact of removing two LCVUs from
| |
| service. simultaneously. nor did the procedure address the
| |
| interaction between LCVU operation and integrated containment
| |
| ventilation systems. These procedural inadequacies constituh a
| |
| violation of TS 6.8.1. Procedures and Programs. This failure
| |
| constitutes a violation of minor significance and is being treated
| |
| as a NCV. consistent with Section IV of the NRC Enforcement
| |
| Policy. This item is identified as NCV 50-414/97-09-02:
| |
| Inadequate LCVU Operating Procedure.
| |
| 08
| |
| ,
| |
| Hiscellaneous Operations Issues (92901)
| |
| 08.1 (Closed) Un.reigh.ed_Ltem (URI) 50-413.414/94-13-02: Emergency Operating
| |
| Procedure (EOP) 50.59 Evaluations Not Reviewed by Nuclear Safety Review
| |
| Board (NSRB) as Required by TS
| |
| This item was related to an apparent failure to meet the TS requirement
| |
| for the NSRB to review 50.59 evaluations for E0P changes. The
| |
| inspector's review determined that the re
| |
| being appropriately reviewed by the NSRBThe quired 50.59 evaluations
| |
| licensee's were
| |
| procedures had
| |
| Enclosure 2
| |
| | |
| __-_______ __-_ - _ _ - .
| |
| 11
| |
| been inconsistent in defining the 10 CFR 50.59 screening evaluation and
| |
| the 10 CFR 50.59 Unreviewed aafety Question (US0) evaluation. The TS
| |
| requirement was intended for the NSRB to review the 10 CFR 50.59 U50
| |
| evaluations. Nuclear Site Procedure NS0-209, 10 CFR 50.59 Evaluations.
| |
| Revision 6. was revised after 1994 to clearly define the two
| |
| evaluations. The licensee initiated a change to NSD 703. Administrative
| |
| Instruction for Station Procedures, to clearly distinguish on the
| |
| procedure change process documentation whether the evaluation performed
| |
| was a screening evaluation or an USQ evaluation. The inspector reviewed
| |
| ,
| |
| ' three US0 evaluations for E0P changes and verified the US0 evaluation
| |
| i
| |
| had been sent to the NSRB_for review. A 1995 evaluation had been
| |
| reviewed and two 1997 evaluations were scheduled for review at the next
| |
| NSRB meeting. The inspector concluded that this issue was adequately
| |
| ;
| |
| resolved and the TS requirements had been met by the licensee.
| |
| During the invettigation of the above issue, the inspector reviewed
| |
| a) proximately 20 examp',cs of 10 CFR 50.59 screening evaluations for E0P
| |
| c1anges and identified a deficiency in the licensee's procedure
| |
| implementation of this activity. Specifically, the justifications for
| |
| the screening questions were inadequate in many changes. The
| |
| justifications were inadequate in that they only repeated the screening
| |
| question as a negative statement. NSD 209, 10 CFR 50.59 Evaluations.
| |
| Revision 5. required the doca,3ntation of justification for responses to
| |
| 50.59 screening questions. It further stated that justifications should
| |
| be complete enough so that an independent reviewer cculd come to the
| |
| same conclusion. The following E0P change 50.59 screening evaluations
| |
| were inadequate and did not meet the applicable procedure requirements:
| |
| o EP/2/A/5000/FR 1.2 dated November 17, 1995
| |
| e EP/1/A/5000/FR-1.1 dated September 19. 1996
| |
| * OF/1/A/6350/08 dated February 28. 1996
| |
| e EP/2/A/5000/F-0 dated March 26, 1997
| |
| e EP/1/A/5000/FR H.1 dated August 16, 1996
| |
| * EP/1/A/5000/FR-H.1 dated January 30, 1995
| |
| This failure to follow NSD 209 for 10 CFR 50.59 screening evaluations,
| |
| is identified as the first example of Violation (VIO) 50 413.414/9/-09-
| |
| 04: Failure to Follow Procedure. The inspector did not identify any
| |
| US0 condition related to the inadequate 50.59 screening evaluations.
| |
| The inspector noted that the 50.59 screening evaluations for E0P changes
| |
| were performed by the Operations organization. Previous inspections of
| |
| 50.59 evaluation performance have concluded that the Engineering
| |
| organization performed to a high standard in this area for 50.59
| |
| evaluations related to modifications. Although both organizations
| |
| Enclosure 2
| |
| | |
| 12
| |
| receive the same training and use the same procedures. Operation's
| |
| performance in this activity was deficient as previously noted. The
| |
| inspector reviewed a 1997 50.59 USO evaluation for an E0P change. This
| |
| evaluation was good in that it included a well detailed justification
| |
| for responses to the USQ evaluation questions. This indicated that the
| |
| >
| |
| Operations deficient performance was related only to the 50.59 screening
| |
| evaluations.
| |
| II. Maintenance
| |
| l
| |
| M1 Conduct of Maintenance
| |
| 1
| |
| M1.1 Electrical Flash Durinn Breaker Preventive Maintem nte
| |
| a. Inspection Stone (62707)
| |
| The inspector reviewed the circumstances and the licensee's corrective
| |
| actions associated with an electrical flash that occurred inside a 600
| |
| Volt non safety-related breaker cubicle while periodic breaker PM was
| |
| being performed. The electrical flash resulted in a minor personnel
| |
| injury and extensive damage to the breaker cubicle.
| |
| b. Observations and Findinas
| |
| On June 3. 1997, an Instrumentation and Electrical (IAE) technician was
| |
| aerforming PM on 600 Volt breakers 2MXM-F09C and 2MXM-F090. These
| |
| areakers supplied power to two Unit 2 ice condenser refrigeration air
| |
| handling fans. The PM activity involved testing the overcurrent
| |
| protective devices associated with the breakers. The technician had
| |
| removed breaker F09C from its cubicle and was in the process of removing
| |
| breaker F090 from its cubicle. While removing F090, an electrical ficsh
| |
| occurred in the F09C cubicle, which was located directly above F09D.
| |
| The technician received minor facial burns. but was not seriously
| |
| injured. Breaker F09C was electrically welded in its cubicle as a
| |
| result of the electrical fault, The inspector responded to the breaker
| |
| work location and noted good licensee immediate actions in response to
| |
| the incident. These actions included terminati' 11 PM work, roping
| |
| off the area for personnel safety consideratior . nd initiating a
| |
| Failure Investigative Process (FIP) to determine the root cause of the
| |
| electrical fav a.
| |
| On June 6, 1997. Motor Control Center 2MXM was de energized, and the
| |
| breaker cubicle for F09C inspected. The damage to the bus was minimal;
| |
| however, the stabs for F09C were badly damaged and recuired replacement.
| |
| Both breakers F09C and F09D were repaired, tested, anc returned to
| |
| service. The inspector attended the PORC meeting conducted to discuss
| |
| the repair plans and noted that management performed a thorough review
| |
| of the plans with good discussions on the impact of the work planned on
| |
| the plant. The repairs were completed without incident.
| |
| Enclosure 2
| |
| | |
| _____ -
| |
| 13
| |
| The FlP team was thorough in their investigations and determined that
| |
| the stabs b? hind breaker F09C had come in contact with the energized
| |
| bus. Since the breaker power connecting cables had been determed and
| |
| left untaped in the bottom of the breaker cubicle. an electrical ground
| |
| path was created when the cables were re energized. The FIP determined
| |
| the method for racking the breaker out in the maintenance position was
| |
| inadequate. In the maintenance position a lock tab on the front of the
| |
| breaker cubicle had been used to position the breaker away from the bus;
| |
| l however this method did not provide sufficient distance between the bus
| |
| and stabs. While this method had not resulted in any problems in the
| |
| past, the result of having two breakers in the maintenance position,
| |
| located one above the other, created an even smaller bus / stab distance
| |
| that resulted in electrical flash over.
| |
| As a result of the FlP investigations, instrumentation procedures
| |
| governing work on 600 Volt breakers were revised to change the method of
| |
| racking out these breakers for maintenance. Instead of using the lock
| |
| tab, procedures directed that a padlock be placed on the breaker or the
| |
| bteaker be removed completely to ensure adequate stab / bus distance is
| |
| maintained. In addition, IAE personnel involved with breaker work were
| |
| to be provided training on this new method of racking 600 Volt breakers
| |
| out to the maintenance position.
| |
| c. Conclusions
| |
| The inspector concluded that the FlP team was thorough in investigating
| |
| the cause of the electrical flash. The root cause evaluation revealed
| |
| configuration weaknesses in the method of locking out 600 Volt breaker
| |
| cubicles to the maintenance position. The inspector determined that the
| |
| licensee adecuately implemented corrective actions to prevent recurrence
| |
| of this incicent.
| |
| M1.2 'Jngdeounte Leak Rate lest of Unit 2 Containment Isolation Valve
| |
| a, insoection Scope (40500. 61726. 62707)
| |
| On June 4,1997, the licensee identified that Unit 2 containment
| |
| isolation valve 2NV 874 had not been properly Type C leak rate tested in
| |
| accordance with 10 CFR 50. Appendix J during the previous. refueling
| |
| outage. On June 6. the valve was properly tested and failed the Type C
| |
| leak rate test. -The valve disc was replaced, and the valve was
| |
| successfully tested on June 7. The licensee submitted LER 50 414/97-004
| |
| . to document the inadecuate leak cate test conducted during the outage.
| |
| The inspector reviewec the circumstances associated with the inadequate
| |
| testing, attended PORC meetings to discuss retesting valve 2NV-874
| |
| online, witnessed aspects of the June 6 retest, reviewed leak rate test
| |
| results, and discussed the incident with engineering and Operations Test
| |
| Group (OTG) personnel,
| |
| Enclosure 2
| |
| _ -
| |
| | |
| i
| |
| 14
| |
| b. Observations and Findinas
| |
| On &ne 4.1997 the OTG Suaervisor was conducting a procedure
| |
| completion verification of Jnit 2 Periodic Test (PT) procedure
| |
| PT/2/A/4200/01C. Containment Isolation Valve t.eak Rate Test. This
| |
| procedure had been performed during the previous refueling outage in
| |
| 1
| |
| April 1997. During the review, the supervisor idcntified that Step
| |
| 2.2.3 of Enclosure 13.7. Penetration No. M228 Type C 1.eak Rate Test had
| |
| been marked "Not Applicable'' by the OTG technician performing the test.
| |
| ,
| |
| I
| |
| resulting in the step not being performed. This step required test vent I
| |
| flow path valve 2NV 873 to be opened while testing inside containment
| |
| isolation check valve 2NV 874 (associated with the Standby Makeup System '
| |
| flowpath to the reactor coolant pump seals). Without an open test vent
| |
| flowpath, the leak rate test on 2NV 874 had been invalid.
| |
| The inspector verified that appropriate actions were implemented upon
| |
| identification of the invalid lea ( rate test. These actions included
| |
| 2NV 874 being declared inoperable and in accordance with TS 3.6.3, the
| |
| outboard containment isolation valve (2NV 872A) in the penetration was
| |
| closed and power was removed from the valve operator within four hours.
| |
| The inspector attended the June 5 and 6 PORC meetings conducted to
| |
| discuss activities to retest 2NV-874. Management thoroughly discussed
| |
| the impact on the plant with testing the valve while online. In
| |
| addition engineering developed a special leak rate test procedure and a
| |
| detailed briefing package explaining the necessary actions for
| |
| controlling the retest activities.
| |
| On June 6. the inspector witnessed aspects of the leak rate test on 2NV-
| |
| 874. The inspector noted that testing was well controll?d and performed
| |
| in accordance with the test procedure.- The valve was not able to be-
| |
| pressurized and resulted in-a failed leak rate test. Valve maintenance
| |
| was performed resulting in replacement of the valve disc and disc
| |
| spring. A subsequent leak rate test was performed following the
| |
| maintenance activity. The inspector reviewed the results of this
| |
| testing which verified that leakage was within acceptable limits.
| |
| Following successful testing 2NV 874 was declared operable and the
| |
| penetration was returned to its normal configuration,
| |
| c. n
| |
| C_Qn.clusions
| |
| The inspector concluded the identification by the OTG Supervisor of a
| |
| procedure discrepancy that resulted in an invalid leak rate test of nD-
| |
| 874 was an example of good questioning attitude. The PORN performed a
| |
| thorough review of subsequent activities to properly perform the leak
| |
| rate test. Good engineering support was )rovided, both in developing a
| |
| leak rate test procedure and briefing paccage for the evolution.
| |
| The inspector noted that the procedure completion review was not
| |
| performed by the OTG Supervisor following actual completion of all
| |
| testing or prior to plant startup from the refueling outage. Since this
| |
| Enclosure 2
| |
| _ _ _ _
| |
| -
| |
| | |
| . . - _ . __- --_ --- - - - - - . . - - _- _.
| |
| 15
| |
| l was the only review that was recuired following test procedure
| |
| completion, the inspector consicered the review untimely. Had this
| |
| review been completed prior to plant startup, this problem may have been
| |
| identified and corrected arior to the unit entering a mode recuiring
| |
| containment integrity. T1e failure to open test vent valve 2hV-873
| |
| during/4200/01C
| |
| PT/2/A was identified as a violation of TS 6.8.1. leak
| |
| This rate testing of
| |
| issue
| |
| is identified as Violation E0-414/97-09 03: Failure to Follow Procedure
| |
| Results in Invalid Local Leak Rate Test of Valve 2NV 874.
| |
| M8 Miscellaneous Maintenance Issues (92902.
| |
| l M8.1 (Closed) VIO 50 413. 414/97-01-01: Failure to Include all Structures.
| |
| S stems and Components in the Scope of the Maintenance Rule as Required
| |
| b 10 CFR 50.65
| |
| This violation was identified when the inspectors determined that the
| |
| licensee had incorrectly excluded a number of structures. systems and
| |
| components from the scope of the Maintenance Rule. The licensee
| |
| acknowledged the violation and issued a Problem Investigation Process
| |
| ; (PIP) report PIP No. 0 C97-0419. to document correctivo actions taken
| |
| ! and, track the progress made in addressing the issues. The systems
| |
| affected included Nuclear Sampling (NM). Main Steam to Auxiliary
| |
| Equi) ment (SA). Auxiliary Building Chilled Water (YN) and Ice Condenser
| |
| l
| |
| '
| |
| Hitti Pins (NF). Following a review by the site Expert Panel these
| |
| systems or components were added to the scope of the Maintenance Rule.
| |
| Corrective actions taken or planned included a review of the 239
| |
| '
| |
| functions that had been excluded from the Maintenance Rule scope. This
| |
| review was scheduled for completion in December 1997.- and will be
| |
| documented in PIP No. 0-C97-0419, In addition, structures and functions
| |
| excluded from the Maintenance Rule will be reviewed for Generic Scoping
| |
| applicability. The due date for this review is also December 1997. The
| |
| inspectors concluded the licensee's corrective actions were appropriate.
| |
| ,
| |
| M8.2. (Closed V10 50-413.414/97 01-04: Failure to implement the Requirements
| |
| of (a)(1) and (a)(2) of the Maintenance Rule
| |
| l This violation was identified when the inspectors determined that the
| |
| l licensee was using Forced Outage Rate (FOR) instead of Unplanned
| |
| l Capability loss Factor (UCLF) as a Plant Level Performance Criteria for
| |
| ' monitoring A2 systs....; 3er 10 CFR 50.65. The concern was that FOR was
| |
| not as sensitive as UC F in detecting declining performance in some
| |
| systems.
| |
| The licensee acknowledged the violation and took appropriate action to
| |
| correct the problem. The licensee incorporated the Plant Transient
| |
| Criteria as part of the Forced Outage Criteria. This combination of
| |
| criteria was intended to provide appropriate equivalent defense in depth
| |
| monitoring as the Unplanned Capability Loss Factor. A Plant level
| |
| Enclosure 2
| |
| l
| |
| ._ - -- -
| |
| | |
| 1
| |
| ;
| |
| 16
| |
| l
| |
| Performance Criteria called Plant Transients, which defined unacceptable
| |
| performance was added to Engineering Directives Manual (EDM)-210 as Rev.
| |
| i
| |
| '
| |
| 4. The inspectors concluded the licensee's corrective actions were
| |
| appropriate. l
| |
| I
| |
| M8.3 (Closed) Insoector Followuo item (IFI) 50 413.414/97-01-02: Followup and
| |
| '
| |
| Review of Licensee Procedure to implement the Requirements of (a)(1) and
| |
| (a)(2) of the Maintenance Rule after issuance of Regulatory Guide 1.160,
| |
| Rev.2
| |
| i
| |
| EDM-210." Requirements for Monitoring the Effectiveness of Maintenance
| |
| at Nuclear Power Plants or the Maintenance Rule " Rev. 5. revised the
| |
| definition of Maintenance such that it was now in agreement with
| |
| Regulatory Guide 1.160. Rev. 2, dated March 1997. Revision 5 of the EDM
| |
| now considers any operator action performed in support of Maintenance as
| |
| a Maintenance Preventable Function Failure (MPff) candidate. In
| |
| addition, the flow gra)h of Appendix A to the subject EDM, were revised
| |
| for clarity. One of tie two was revised from Vendor Error to Off-site
| |
| Vendor Services while the other from Operations or Plant configuration
| |
| control to Operation or Plant Configuration Control not associated with
| |
| a maintenance activity. The inspectors concluded the licensee's
| |
| i
| |
| corrective actions were appropriate.
| |
| M8.4 (Closed) IFT 50-413.414/97-OL-01 Followup on Licensee Actions to
| |
| Provide Performance Criteria for Structures After Resolution of this
| |
| Issue
| |
| EDM-210. " Requirements for Monitoring the Effectiveness of Maintenance
| |
| : at Nuclear Power Plants or the Maintenance Rule." Rev. 5. changed the
| |
| 3erformance criteria for all Maintenance Rule structures to comply with
| |
| legulatory Guide 1.160. Rev. 2. This criteria applies to both risk and
| |
| non-risk significant Maintenance Rule structures.
| |
| EDM 410. " Ins)ection Program for Civil Engineering Structures and
| |
| Components." Rev. 1. dated June 16, 1997, is the controlling document
| |
| for monitoring and assessing civil engineering structures and' components
| |
| to the requirements of 10 CFR 50.65 and Regulatory Guide 1.160,.Rev. 2.
| |
| dated March 1997. It provides examination guidelines, acceptance
| |
| criteria and documentation requirements. As such. Catawba civil
| |
| ,
| |
| engineering was responsible for implementing the ins)ection program for
| |
| l structures and components. The inspectors reviewed EDM-410. Rev. 1 for
| |
| content and adequacy. The inspectors noted that the procedure provided
| |
| adequate guidelines and the acceptance criteria contained within,
| |
| followed Regulatory Guide 1.160. Rev. 2 guidelines for acceptable and
| |
| . unacceptable performance criteria.
| |
| l
| |
| l Through discussions and document review, the inspectors ascertained that
| |
| the inspection program for structures was adequately administered and
| |
| implemented. Responsible engineers had received training and were
| |
| familiar with Maintenance Rule requirements as they applied to their
| |
| area of responsibility.
| |
| 5
| |
| Enclosure 2
| |
| L ___ _-- _ . _ _ _. .. . _ __.. _ _ _ _ __ , /
| |
| | |
| _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ - _ __ _________
| |
| 17
| |
| At the close of this inspection. 39 structures had been inspected and an
| |
| additional 120 were scheduled for inspection by year's end. Ins)ection
| |
| per the revised EDMs -210 and -410 commenced on July 1, 1997. T1e
| |
| inspectors reviewed the licensee's classroom training material. ES-CN-
| |
| 97-21. used to cormiunicate Regulatory Guide 1.160. Rev. 2 guidelines.
| |
| Training of personnel was held between June 9 and 18. 1997. The
| |
| inspectors concluded the licensee's corrective actions were ap]ropriate.
| |
| III. Enaineerina
| |
| El Conduct of Engineering
| |
| El.1 Primary and Secondary Thermal Power DiscreDancy
| |
| a. -Insoection Stone (37551)
| |
| On July 15 the licensee discovered a discrepancy of approximately 0.6%
| |
| between the Unit 2 primary and secondary thermal power indications.
| |
| Secondary thermal
| |
| was reduced to 99.7%)power
| |
| andwas immediately
| |
| a FIP team was reduced
| |
| initiated to to determine
| |
| 99.3% (reactor
| |
| the power
| |
| cause of the discreaancy. The inspector attended management briefings
| |
| by the FIP team mem)ers on the progress of their investigation: reviewed
| |
| associated TS and TS Interpretations: and discussed the issue with
| |
| Operations. Engineering and Maintenance personnel.
| |
| b. Observations and Findinas
| |
| On July 15. Operations personnel were notified by the reactor
| |
| engineering group that there was a 0.6% discrepancy between primary and
| |
| secondary thermal power indications, and that actual thermal Jower might
| |
| be greater than the secondary thermal power (the designated tiermal
| |
| power best estimate) indication. The reactor engineering group
| |
| discovered, during a routine review of secondary plant parameters, that
| |
| primary thermal power had slowly increased over time since the Unit 2
| |
| restart from the April 1997 refueling outage. A FIP team was initiated
| |
| to determine the cause of the discrepancy, and control room operators
| |
| decreased reactor aower to 99.3%. Tae reactor was operated at 99.3%
| |
| power until the FI) team could determine the cause of the discrepancy.
| |
| The FIP team determined, during the course of their investigation, that
| |
| theT,Yto586.9F.
| |
| 587.3 indication had responded
| |
| Operations been drifting downward T,,,
| |
| by decreasing since May 11, 1997, from
| |
| to minimize
| |
| the T * /T error. Lowering T,,, caused the reactor to increase AT to
| |
| maint'aIn,r,,actorpowerequaltosecondarypower.
| |
| e The drift in the T,,,
| |
| indication resulted in changes in T Tm T,,, and AT but did not
| |
| cause a change in indicated or actud3 primary and secondary thermal
| |
| power. Although the FIP team could not attribute this indication drift
| |
| to the primary / secondary thermal power indication discrepancy they
| |
| determined that a degraded 7300 process card was responsible for the
| |
| Enclosure 2
| |
| _. . - . - . . _ .
| |
| | |
| }
| |
| l
| |
| 18
| |
| drift and initiated plans to have the card replaced after the root cause
| |
| of the power indication discrepancy was identified.
| |
| The FIP team also determined that indicated feedwater flow had decreased
| |
| while steam flow had remained constant. This was attributed to
| |
| feedwater venturi defouling as a function of the new cycle (restart from
| |
| the April refueling outage was in early May). the recent reactor trip
| |
| (June 26), and was the recent rapid downpower (July 2). The result of
| |
| defouling was a decrease in indicated feedwater flow with a
| |
| consequential decrease in indicated secondary thermal Operations
| |
| maintains secondary Thermal Power Best Estimate (TPBE) power.
| |
| near 100% by
| |
| periodically opening flow control valves, which in turn causes primary
| |
| power to increase to maintain T
| |
| defouling caused an increase in.,, for and
| |
| actual 100% power level.
| |
| indicated The
| |
| primary gradual
| |
| thermal
| |
| power, as well as actual secondary thermal power. However, the
| |
| resultant discrepancy between indicated and actual secondary thermal
| |
| )ower accounted for approximately 0.10% to 0.15% of the 0.6% discrepancy
| |
| )etween primary and secondary indicated thermal power.
| |
| The major contributor (0.3% to 0.4%) to the discreaancy between primary
| |
| and secondary thermal power was determined by the IP team on July 16 as
| |
| hot leg streaming. According to Westinghouse, hot leg streaming refers
| |
| to the inability to accurately characterize bulk hot leg temperature.
| |
| The licensee examined data from the Unit 2 Beginning of C.rcle and
| |
| identified changes in the behavior of this phenomenon from previous
| |
| cycles. S)ecifically. calculations revealed that indicated Tw had
| |
| increased ay 0.2*F and caused indicated primary thermal power to
| |
| increase. As discussed above these changes were originally masked by
| |
| the decrease in primary tem -
| |
| T,,,/T,,, as a function of T,,,peratures accompanying the decrease in
| |
| indication drift.
| |
| Hot leg streaming has occurred in previous cycles on both units and has
| |
| resulted in as high as a 1.0% difference between primary and secondary
| |
| thermal power. To account for this, an adjustment factor in the OAC
| |
| calculation corrects the discrepancy.
| |
| The FIP team concluded that sea:dary thermal power had always been
| |
| accurately and correctly indicated, and that primary thermal power
| |
| indication did not reflect an actual increase in power level above TS
| |
| limits. The inspector discussed the impact of the primary thermal power
| |
| indication on Reactor Protection System setpoints and functions.
| |
| According to the reactor engineering group, the venturi defouling and
| |
| hot leg streaming factors did not constitute a sufficient temperature
| |
| error to warrant adjustment via the Reactor Coolant System (RCS)
| |
| Temperature Calibration Procedure, which is run quarterly. The OPAT and
| |
| OTAT trip strings remained within their TS limits. In addition, the
| |
| nuclear instrumentation system is calibrated to secondary thermal power,
| |
| so the associated overpower trip setpoints were unaffected.
| |
| Enclosure 2
| |
| ,
| |
| _,
| |
| -
| |
| -.-.-.c. _. ---
| |
| | |
| _ _ _ _ - _ _ _ _ - - - - _ _ _ _ - - - - -
| |
| - - - - - -
| |
| -
| |
| 19
| |
| Reactor Power was increased to 99.5% on July 16 and the degraded T,q
| |
| card was replaced on July 17. The inspector attended the prejob brief
| |
| for the card replacement and observed the work activity in the control
| |
| room. The replacement was successfully completed within less than 1
| |
| hour and without incidence. At the end of the inspection period, the
| |
| 3a license was considering either performina periodic manual calculations
| |
| to the correct the thermal power aiscrepancy, or conducting a full
| |
| calorimetric to account for the deviation.
| |
| c. Conclusiqn_q
| |
| ,
| |
| * The inspector concluded that the licensee's identification of the
| |
| E thermal power discrepancy exhibited attention to detail and a thm
| |
| review of plant data. Actions to initiate a FlP team to invr a
| |
| g root cause were appropriate, and steps to reduce reactor po'
| |
| discrepancy was understood were conservative and indicative
| |
| positive nuclear safety ethic. Replacement of the faulty T, ,a was
| |
| well-planned. coordinated and controlled, and executed in an expeditious
| |
| manner.
| |
| E2 Engineering Support of Facilities and Equipment
| |
| .
| |
| E2.1 Review of Corrective Actions
| |
| a. Inspedjon Scooe (37550. 92903)
| |
| The inspector reviewed Engineering corrective actions to resolve open
| |
| itens identified during the development of the station Design Base
| |
| Documents (DBDs) and findings from Self-initiated Technical Audits
| |
| (SITAs). Also reviewed were the licensee's actions to address a 10 CFR
| |
| Part 21 issue related to a defective Emergency Diesel Generator (EDG)
| |
| intake / exhaust valve spring. Anplicable regulatory requirements
| |
| included 10 CFR 50 Appendix B. ESAR. Technical Specifications and
| |
| implementing licensee procedures.
| |
| b. Observations and Findinos
| |
| DS_Qs
| |
| Developed between 1990 and 1994. DBDs consolidated design and licensing
| |
| documentation for selected station systems and programs. The ]rocedure
| |
| guidance for development and maintenance of DBDs was provided ay
| |
| Enoineering Directives Manual . EDM-170. Design Specifications, revision
| |
| '
| |
| 5. Open items were evaluhed for operability during the DBD development
| |
| and Licensee Event Reports (LERs) initiated as required. EDM-170
| |
| required the remaining items to be entered into the Problem
| |
| Investigation Process (PIP) for tracking and resolution. Additionally,
| |
| the l u ensee's February 10. 1997. response to the 10 CFR 50.54f letter
| |
| related to the Adequacy and Availability of Design Basis Information.
| |
| P stated that DBD open items woeli be ente 1 4 into the PIP for trackir.g
| |
| N and resolution.
| |
| Enclosure 2
| |
| .
| |
| Mi
| |
| | |
| 20
| |
| TM inspector reviewed the resolution of open item in the Reactor
| |
| coolant System DBD to sample the adecuacy of item resolution activity.
| |
| Approximately 20 items were evaluatec to verify that the PIP and
| |
| interfacing station programs evaluated and resolved the open item
| |
| issues. The items were adequately resolved.
| |
| An independent industry audit of Catawba in late 1996, identified as a
| |
| finding the numerous lon9-term unresolved DBD open items. The response
| |
| to the finding was to initiate a blanket PIP (PIP 0-C97-0595 dated
| |
| March 5,1997) to cover the systems with the identified open items.
| |
| Many of these open items were not previously in the PIP process. The
| |
| PIP corrective actions established a schedule to resolve and close the
| |
| referenced DBD open items by September 1. 1997,
| |
| During this inspection, the inspector identified additional E 'en
| |
| items which were not entered into the PIP process nor incluau .d the
| |
| blanket PIP. The open items.were included in DBD CNS-1435.00-0002. Post
| |
| Fire Safe Shutdown, revision 4. and DBD CNS-1465.00-00-0018. Station
| |
| Blackout (SBO) Rule, revision 2. Although not entered into the PIP
| |
| 3rocess. the licensee provided meeti g documentation indicating the Post
| |
| rire Safe Shutdown open items were being evaluated. These items were
| |
| identified by a November 1995 electrical post fire shutdown review
| |
| performeo after the initial DBD development and entered into the DBD by
| |
| revision 4 at that time. There was no c: :umented evaluation of
| |
| o)erability or A
| |
| tie PIP process.ppendix R commitments
| |
| Following which
| |
| the inspector's would haveof
| |
| identification been
| |
| this addressed
| |
| issue by
| |
| the licensee initiated PIP 0-C97-1918 to track resolution of these open
| |
| items. The inspector identified no significant safety concerns related
| |
| to the open items reviewed. This failure to follow procedure for
| |
| resolution of DBD open items is identified as the second example of
| |
| Violation 50-413.414/97-09-04: Failure to Follow Procedure.
| |
| *
| |
| SITAS
| |
| The ins)ector reviewed a recently comp'eted SITA report dated June 11.
| |
| 1997, w11ch reviewed the adequacy of resolution of SITA findings. The
| |
| scope of the audit was good in that it reviewed the resolution of 80
| |
| findings from four previous SITAs. The depth of the audit was good in
| |
| that corrective act ans were verified through the extent of station
| |
| programs (e.g. . PIP work requests, modification etc. .) involved in the
| |
| resolution. The findings were well defined and demonstrated an
| |
| independent and objective audit. Corrective actions for the findings
| |
| hcd not yet been developed.
| |
| EDG 10 CFR Part 21 Notice
| |
| The inspector ruiewed the licensee's actions to address a Cooper
| |
| Industries 10 CFR Part 21 notice regarding potentially defective EDG
| |
| intake / exhaust valve springs which was applicable to Catawba. The
| |
| notice was initiated in 1991 and revised on May 1. 1997. The licensee
| |
| had included an inspection for the spring defect into the EDG
| |
| maintenance procedure. A defective spring was identified at Catawba in
| |
| 1996. The spring was replaced. analyzed, and sent to the vendor for
| |
| '
| |
| Encloture 2
| |
| . _
| |
| | |
| ._. _ _ _ _ .. ..
| |
| . . .. .
| |
| . ..
| |
| 21
| |
| further analysis. The licensee's respon.e to the notice on this issue
| |
| was appropriate,
| |
| c. Conclusions
| |
| Resolution of DBD open items was generally adequate in that no safety
| |
| significant issues were identifieo in the open items. A violation was
| |
| identified for failure to follow licensee procedure requirements to
| |
| enter open DBD open items into the station PIP process for tracking and
| |
| . resolution. The audit of SITA corrective actions demonstrated that the
| |
| licensee was aggressively following SITA findings and is identified as a
| |
| strength in corrective action performance. Additionally, the licensee
| |
| adequately addressed the EDG 10 CFR Part 21 issue related to potentially
| |
| defective intake / exhaust springs.
| |
| E3 Engineering Procedures and Documentation
| |
| E3.1 Chanaes. Tests. and Exneriments Performed in Accordance With
| |
| 10 CFR 50.59 (thru December 31. 1996)
| |
| a. Insoection Scone (37551)
| |
| '
| |
| f
| |
| By letter dated March 31, 1997. Duke Power Company (the licer.see)
| |
| submitted its annual summary of all changes, tests, and experiments,
| |
| which were completed under the provisions of 10 CF,150.59 for the period
| |
| through December 31. 1996. The licensee's March 31, 1997, summary
| |
| included approximately 380 changes made during the subject period. The
| |
| inspector evaluated these changes against the p,avisions of the
| |
| regulation.
| |
| <
| |
| b. Observations and Findinas
| |
| In accordance with 10 CFR 50.59, a licensee may: (1) make changes in
| |
| the facility as described in the safety analysis report, (2) make
| |
| changes -in the procedures as described in the safety analysis report,
| |
| and (3) corduct tests or experiments not described in the safety
| |
| analysis report, without prior Commission approval, unless the change
| |
| involvy a changc in the Technical Specifications or an Unreviewed
| |
| Safety duestion (US0). The regulation defines an US0 as a proposed
| |
| action that: (a) may increase the probability of occurrence or
| |
| consequences of an accident or malfunction of equipment important to
| |
| safety previously evaluated in the safety analysis report, or (b) may
| |
| create a possibility for an accident or malfunction of a different type
| |
| than any previously evaluated in the safety analysis report or (c) may
| |
| reduce the margin of safety as defined in the basis for any Technical
| |
| Specification.
| |
| The inspector reviewed the licensee's current (dated March 10. 1997)
| |
| version of Nuclear System Directive 209. "10 CFR 50.59 Evaluations."
| |
| which is patterned after NSAC-125. " Guidelines for 10 CFR 50.59 Safety
| |
| Enclosure 2
| |
| .
| |
| | |
| _ _ _ _ _-- __ --
| |
| 22
| |
| Evaluations." June 1989. This document requires that changes be
| |
| evaluated against the appropriate Final Safety Analysis Report (FSAR).
| |
| Technical Specifications, end NRC Safety Evaluation Report sections to
| |
| determine if there is need for revision. Specifically, the criteria
| |
| specified by 10 CFR 50.59 are broken down into seven (7) questions. For
| |
| a change to be qualified for 10 CFR 50.59, the answers to all seven
| |
| questions must be "no". Based on review of this document, and the
| |
| review of the licensee's 10 CFR 50.59 evaluations. the inspector
| |
| concluded that the licensee's directive appropriately reflects the
| |
| criteria of this regulation and that. if followed accordingly, should
| |
| ensure that a change would be correctly performed under this regulation.
| |
| The inspector performed an in-office review of the licensee's summary to
| |
| determine the nature and safety significance of each change. Through
| |
| this review, the inspector selected the following changes for more
| |
| detailed review onsite:
| |
| e Exempt Changes:
| |
| Exempt Change CE-3176
| |
| Exempt Change CE-3705
| |
| Exempt Change CE-3759
| |
| Exempt Change CE-4745
| |
| Exempt Charge CE-4746
| |
| Exempt Change CE-4821
| |
| Exempt Change CE-4822
| |
| Exempt Change CE-7416
| |
| Exempt Change CE-7977
| |
| Exempt Change CE-8126
| |
| Exempt Change CE-8182
| |
| Exempt Change CE-8245
| |
| Exempt Change CE-8410
| |
| Exempt Change CE-61008
| |
| Exempt Change CE-61162
| |
| e Miscellaneous Changes:
| |
| SIMULATE (a computer code) Version 4
| |
| * Modifications:
| |
| NSM CN-11371
| |
| NSM CN-20396
| |
| o 0:?rable But Degraded Evaluations:
| |
| PIF 2-C97-0157
| |
| PIP 2-096-3250
| |
| e Operability Evaluations:
| |
| Enclosure 2
| |
| _
| |
| ~
| |
| | |
| . - _ _ _ _ _ _ _ _ _ _ - _ -
| |
| 23
| |
| Operability Evaluation dated 2/15/94
| |
| Operability Evaluation dated 2/18/94
| |
| Operability Evaluation dated 6/28/94
| |
| e Procedure Channes:
| |
| OP/1/A/6200/11
| |
| AM/2/A/5100/07
| |
| OP/2/B/6200/33. Change 4 Rev. 4
| |
| OP/1/A/6550/14
| |
| PT/1/B/4700/82
| |
| The ins ector determined that these changes were correctly evaluated
| |
| under t e provisions of 10 CFR 50.59
| |
| During the in-office and onsite reviews, the inspector made a number of
| |
| observations and has communicated them to licensee personnel:
| |
| * The use of nuke-specific system identifiers in the annual summary
| |
| (which is submitted to the NRC and is thus available to the
| |
| l
| |
| public) is discouraged unless the licensee provides a key in the
| |
| l summary. These identifiers do not bear any apparent correlation
| |
| l to the actual systems (e.g. , NC = reactor coolant system. KC =
| |
| l component cooling system, etc..). The inspector made a similar
| |
| observation on the summary submitted on March 2~. 1996 (see
| |
| Inspection Report 50-413.414/96-10).
| |
| '
| |
| o The licensee's corresponding revision of the UFSAR. per 10 CFR
| |
| 50.71. lags behind 10 CFR 50.59 evaluations. The next u)date of
| |
| the UFSAR. scheduled for late 1997. should capture all tie changes
| |
| that are within the scope of the UFSAR.
| |
| e While the licensee had acceptably evaluated all the changes
| |
| audited by the inspector, a number of them eppeared in the summary
| |
| with insufficient information for a reader to even determine what
| |
| system was involved, or what change was made. The inspector
| |
| recommended a several-sentence description. identifying the
| |
| system, the component, and the nature of the change, and
| |
| accompanied by a several-sentence evaluation. Despite this
| |
| problem with the summary, the evaluations were found to be
| |
| thorough and in compliance with 10 CFR 50.59. The licensee was
| |
| aware of this aroblem with the summary and has initiated actions
| |
| to correct suc1 weakness by revising its guidance document. NSD
| |
| 209 (see Problem Investigation Process Form 0-C97-2027. dated June
| |
| 19. 1997).
| |
| * The term " Exempt Changes" may cause confusion in the context of 10
| |
| CFR 50.59. It is a term internal to the licensee's docunentation.
| |
| It pertains to changes that "do not require the Modification
| |
| Enclosure 2
| |
| | |
| - _ _ _ _
| |
| 1
| |
| b
| |
| 24
| |
| Program controls for configuration management and therefore are
| |
| specifically exempted from the requirements to process an
| |
| editorial NM or NSM." According to licensee personnel, an " exempt
| |
| change" is essentially a minor change.
| |
| e The summary contained a significant number of errors, which stated
| |
| the opposite of the actual facts. For example, test procedure
| |
| TT/1/A/9200/88 states "there are Unreviewed Safety Questions
| |
| associated with this test procedure" when the onsite evaluation
| |
| shows that there was no unreviewed safety question. The licensee
| |
| submitted a letter on July 9, 1997, correcting such errors.
| |
| c. Crnclusions
| |
| Based on in-office review of the licensee's March 31, 1997, annual
| |
| summary on 10 CFR 50.59 changes, onsite review of the licensee's 10 CFR
| |
| 50.59 evaluatius, and audit of the licensee's 3rocedures, the inspector
| |
| concluded that the licensee had complied with t1e provisions of the
| |
| regulation for the changes listed in the annual summary.
| |
| l
| |
| IV. Plant Suocort
| |
| R1 Radiological Protection and Chemistry Controls
| |
| R1.1 Tours of the Radiolooical Control Area (RCA) (71750)
| |
| The inspectors periodically toured the RCA during the inspection period.
| |
| t Radiological control practices were observed and discussed with
| |
| !
| |
| radiological control personnel, including RCA entry and exit, survey
| |
| postings locked high radiation areas, and radiological area material
| |
| conditions. The inspector concluded that radiological control practices
| |
| were proper.
| |
| V. Management Meetinas
| |
| X1 Exit Meeting Summary
| |
| The inspectors ) resented the inspection results to members of licensee
| |
| management at t1e conclusion of the inspection on July 11 and July 23. 1997.
| |
| The licensee acknowledged the findings presented. No proprietary information
| |
| was identified. Dissenting comments were not received from the licensee.
| |
| Enclosure 2
| |
| | |
| _ - _ _ _ . - - - _
| |
| .,
| |
| -. -
| |
| t
| |
| 25
| |
| PARTIAL LIST OF PERSONS CONTACTED
| |
| Licensee
| |
| Bhatnager. A. . Operations Su>erintendent
| |
| Birch. M. . Safety Assurance ianager
| |
| Coy., S., Radiation Protection Manager
| |
| Forbes. J., Engineering Manager
| |
| Jones. R.. Station Manager
| |
| Harrall. T., Instrument and Electrical Maintenance Superintendent
| |
| Kelly. C.. Mainteriance Manager
| |
| Kimball . D. , Safety Review Group Manager
| |
| Kitlan. M., Regulatory Compliance Manager
| |
| '
| |
| Nicholson. K., Compliance Specialist
| |
| Peterson. G., Catawba Site Vice-President
| |
| Tower. D., Regulatory Compliance
| |
| l
| |
| ,
| |
| 4
| |
| Enclosure 2
| |
| u
| |
| | |
| _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ __
| |
| 26
| |
| INSPECTION PROCEDURES USED
| |
| IP 37551: Onsite Engineering
| |
| IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and
| |
| Preventing Problems i
| |
| IP 61726: Surveillance Observation
| |
| IP 37550: Engineering
| |
| IP 62707: Maintenance Observation
| |
| IP 71707: Plant Operations
| |
| IP 71750: Plant Support Activitia
| |
| IP 92901: Followup - Operations
| |
| IP 92902: Followup - Maintenance
| |
| IP 92903: Followup - Engineering
| |
| IP 93702: Prompt Onsite Respense to Events
| |
| ITEMS OPENED, CLOSED, AND DISCUSSED
| |
| Opened
| |
| i
| |
| 50-414/97-09-01 NCV Failure to Declare Ice Condenser
| |
| Intermediate Deck Doors Inoperable and Log
| |
| Appropriate TSAIL Entry (Section C1.1)
| |
| 50-414/97-09-02 NCV Inadequate Lower Containment Ventilation
| |
| Unit Operating Procedure (Section 01.4)
| |
| '
| |
| 50-414/97-09-03 VIO Failure to Follow Procedure Results in
| |
| Invalid Local Leak Rate Test of Valve 2NV-
| |
| 874 (Section M1.2)
| |
| 50-413.414/97-09-04 VIO Failure to Follow Procedure - Two Examples
| |
| (Sections 08.1. E2.1)
| |
| Closed
| |
| 50-413.414/97-01-01 VIO Failure to Include All Structures Systems
| |
| and Components in the Scope of the
| |
| Maintenance Rule as Required by 10 CFR
| |
| 50.65(b) (Section M8.1)
| |
| 50-414.414/97-01-02 IFI Followup and review of licensee procedure
| |
| to implement the requirements of (a)(1)
| |
| and (a)(2) of the Maintenance Rule after
| |
| issuance of Revision 2 of Regulatory Guide
| |
| 1.160 (Section M8.3)
| |
| 50-413.414/97-01-03 IFl Followup on Licensee Actions to Provide
| |
| Performance Criteria for Structures After
| |
| Resolution of this Issue (Section M8.4)
| |
| Enclosure 2
| |
| | |
| - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
| |
| 27
| |
| 50-413.414/97-01-04 VIO Failure to implement the requirements of
| |
| (a)(1) and (a)(2) of the Maintenance Rule
| |
| (Section M3.2)
| |
| 50 413.414/94-13-02 URI Emergency Operating Procedure 50.59
| |
| Evaluations Not Reviewed by Nuclear Safety
| |
| '
| |
| Review Board as Required by TS (Section l
| |
| 08.1)
| |
| <
| |
| l List of Acronyms
| |
| ! CFR -
| |
| Code of Federal Fagulations
| |
| DBD -
| |
| Design Basis Documents
| |
| EDG -
| |
| Emergency Diesel Generator
| |
| EDM -
| |
| Engineering Directives Manual
| |
| E0P -
| |
| Emergency Operating Procedure
| |
| FIP -
| |
| Failure Investigative Process
| |
| FSAR -
| |
| Final Safety Analysis Report
| |
| IAE -
| |
| Instrument and Electrical
| |
| IFI -
| |
| Inspector Followup Iten
| |
| IST -
| |
| Inservice Testing
| |
| LCVU -
| |
| Lower Containment Ventilation Unit
| |
| LER -
| |
| Licensee Event Report
| |
| LLRT -
| |
| Local Leak Rate Test
| |
| MPFF -
| |
| Maintenance Preventable Function Failure
| |
| NCV -
| |
| Non Cited Violation
| |
| NM -
| |
| Nuclear Sampling
| |
| NRC -
| |
| Nuclear Regulatory Commission
| |
| NSD -
| |
| Nuclear Site Directive
| |
| NSRB -
| |
| Nuclear Safety Review Board
| |
| DAC -
| |
| Operator Aid Com] uter
| |
| POR -
| |
| Public Document Room
| |
| PIP -
| |
| Problem Investigation Process
| |
| PM -
| |
| Preventive Maintenance
| |
| asig -
| |
| Pounds Per Square Inch Gauge
| |
| RCA -
| |
| Radiologically Controlled Area
| |
| RCP -
| |
| Reactor Coolant Pump
| |
| RCS -
| |
| Reactor Coolant System
| |
| RG -
| |
| Regulatory Guide
| |
| SA --
| |
| Main Steam to Auxiliary Equipment
| |
| SB0 -
| |
| Station Blackout Role
| |
| SITA - Self Initiated Technical Audit
| |
| SPOC -
| |
| Single Point of Contact
| |
| TPBE - Thermal Power Best Estimate
| |
| TS -
| |
| Technical Specifications
| |
| TSAIL - Tech Spec' Action Item Log
| |
| UCLF - Unplanned Capability loss Factor
| |
| UFSAR - Updated Final Safety Analysis Report
| |
| Enclosure 2
| |
| _
| |
| | |
| 28
| |
| URI- -
| |
| Unresolved Item-
| |
| USO -
| |
| Unreviewed Safety Question
| |
| VDC' -
| |
| Volts direct current
| |
| .
| |
| VIO -
| |
| Violation
| |
| -VV -
| |
| Containment Ventilation
| |
| WO -
| |
| Work Order
| |
| YN -
| |
| Auxiliary Building Chilled Water
| |
| l
| |
| Enclosure 2
| |
| _
| |
| }}
| |