IR 05000321/1991001
| ML20217B328 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 02/19/1991 |
| From: | Herdt A, Randy Musser, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20217B292 | List: |
| References | |
| 50-321-91-01, 50-321-91-1, 50-366-91-01, 50-366-91-1, NUDOCS 9103120058 | |
| Download: ML20217B328 (16) | |
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UNITED STATES
[s.O 0f 0p 'o NUCLEAR REGULATORY COMMISSION
[* n REGION 11 5 j 101 MARIETTA STREET, * I t ATLANTA, GEORGI A 30323
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Report Nos.: 50-321/91-01 and 50-366/91-01 Licensee: Georgia Power Company P.O. Box 1295 Birmingham, AL 35201 Docket Nos.: 50-321 and 50-366 License Nos.: DPR-57 and NPF-5 Facility Name: Hatch Nuclear Plant Inspection Conducted: January 1 -
February 09, 1991 Inspectors: b h J /c 2 /19 /9; Leonard D. Wert, Jr., Sr/ Resident Inspector Date Signed GE5 aw z ts m Randal A. Mus Res Date Signed Approved by: b6 /j.r dk@entInspector 8hk Alan R. Herdt, Chief, Reactor Projects Branch 3 Dat6 Signed Division of Reactor Projects SUMMARY Scope: This routine, announced inspection involved inspection on-site in the areas of; operations, including review of a Unit One scram due to a failed switchyard breaker, maintenance activities, surveillance testing, ESF system walkdown, and review of open item Results: Two strengths in the licensee's programs were noted during this period:
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The Safety Audit and Engineering Review (SAER) group performed an audit involving radioactive waste programs and issues. The audit had several significant findings some of which resulted in the submittal of LERs. A strong commitment toward correction of the identified deficiencies and improving performance in this area was displayed by managemen (paragraph 2c)
The Event Review Team (ERT) process following the Unit One scram on a failed switchyard breaker was noted as particularly thorough and highly detailed. Each of the several problems which occurred during the event appeared to have been meticulously examine (paragraph 2b)
9103120058 910219 PDR 0 ADOCK 05000321 PDR
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REPORT DETAILS Persons Contacted Licensee Employees
- *C. Coggin, Training and Emergency Preparedness Manager D. Davis. Plant Administration Manager
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- 0. Edge, Nuclear Security Manager P. Fornel, Maintenance Manager
- 0. Fraser, Safety Audit and Engineering Review Supervisor G. Goode, Engineering Support Manager
- M. Googe, Outages and Planning Manager
- J. Hammonds, Regulatory Compliance Supervisor
- J. Lewis, Operations Manager
- C. Moore, Assistant General Manager - Plant Support 40. Read, Assistant General Manager - Plant Operations H. Sumner, General Manager - Nuclear Plant
- S. Tipps, Nuclear Safety and Compliance Manager
- R. Zavadoski, Health Physics and Chemistry Manager Other licensee employees contacted included technicians, operators, mechanics, security force members and staff personne .
NRC Resident inspectors
- L. Wert
- R. Musser
- Attended exit interview Acronyms and initials used throughout this report are listed in the last paragrap . PlantOperations(71707) Operational Status Unit 1 operated at power from the beginning of the rcport period until January 18, 1991. On that date the unit scrammed from 100 percent power due to a problem on a 230 kV transmission line and a failed switchyard breaker (see paragraph 2b). The unit returned to power operation January 20, 1991, and operated at rated power for the remainder of the report period. Unit 2 operated at power for the entire reporting period. At the end of this period Unit 2 hcd operated in excess of 310 days continuously at power. On February 9, 1991, Unit 2 began its end-of-cycle power coastdown and is expected to be at approximately 88 percent of rated thermal power at the
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commencement of the refueling outage scheduled to begin on March 20, 199 The inspectors reviewed plant operotions throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative controls. Control room logs, shif t turnover records, temporary modification logs, LC0 logs and '
equipment clearance records were reviewed routinely. Discussions were conducted with plant operations, mainter.ance, chemistry, health physics, instrumentation and control (l&C), and nuclear safety and compliance (NSAC) personne ~Activitio within the control rooms were monitored on an almost daily basis. Inspections were conducted on day and on night shif ts, during weekdays and on weekends. Observations included control room manning, access control, operator professionalism and attentiveness, and adherence to procedures. Instrument readings, recorder traces, annunciator alarms, operability of nuclear instrumentation and reactor protection system channels, availability of power sources, and operability of the Safety Parameter Display system were monitore Control Room observations also included ECCS system lineups, containment integrity, reactor mode switch position, scram discharge volume valve positions, and rod movement control Numerous informal discussions were conducted with the operators and their supervisors. Some inspections were made during shift change in order to evaluate shift turnover performance. Actions observed were conducted as required by the licensee's administrative procedure The complement of licensed personnel on each shif t met or exceeded the requirements of T Several safety-related equipment clearances that were active were reviewed to confirm that they were properly prepared and execute Applicable circuit breakers, switches, and valves were walked down to verify that clearance tags were in place and legible and that equipment was properly positioned. Equipment clearance program requirements are specified in licensee procedure 30AC-0PS-001-05,
" Control of Equipment Clearances ard Tags." No major discrepancies were identifie Selected portions of the containment isolation lineup were reviewed to confirm that the lineup was correct. The review involved verification of proper valve positioning, verification that motor and air-operated valves were not mechanically blocked and that power was available (unless blocking or power removal was required), and inspection of piping upstream of the valves for leakage or leakage path ,- -
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Plant tours were taken throughout the reporting period on a routine basis. The areas toured included the following:
Reactor Buildings Station Yard Zone within the Protected Area Turbine Building Intake Building Diesel Generator Building Fire Pump BuilC ng Central and Secondary Alarm Stations Switchyard and Relay Building Security Training facilities During the plant tours, ongoing activities, housekeeping, security, eciaipment status, and radiation control practices were observe During this report' period, the inspectors toured the security training facilities onsit In addition to visiting the main security training building, the inspectors also toured several other buildings which house simulators and models used for training. The inspector also visited the weapons training range and associated physical fitness training areas. Detailed discussions were held with security training management and personnel during the tours. The inspectors were impressed with the apparent dedication of the training-personnel. Significant effort has been made to ensure security force training is as realistic and appropriate as possible, Unit 1 Scram Due to Switchyard Breaker Failure and 230 kV Line Fault (93702, 71707) (Unit One)_
At 1600 on January 18, 1991, Unit 1 scrammed from 100 percent rated power. The reactor scram was initiated by a turbine trip which resulted when a switchyard breaker failed to open properly on a-230 kV line fault. The switchyard problems resulted in deenergization of the 4 kV-(nonessential) A, B, C, and D busses on the generator tri This resulted in a loss of feedwater and further complicated the transient. A small fire occurred in the control circuitry for PCB 179500(theswitchyardbreakerwhichdidnotopenasexpected)which was extinguished within a few minutes by a switchyard maintenance worker with a carbon dioxide fire extinguisher. The inspector ;
observed the Event Review Team Leader's meeting with the involved operators, monitored the review of the SPDS tapes of the transient in l the simulator and closely followed the licensee's redovery action The following significant items were identified and thoroughly investigated as a result of the scram;
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At -35 inches reactor water level (feedwater was lost due to loss of nonvital busses) both HPCI and RCIC auto initiated as expecte HPCI experienced at least one overspeed trip (operators stated 3 trips but SPD5 tapes showed only one) and operators took manual control of HPCI to control water level, j l
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The operators did not have any further difficulty at this time
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and were able to restore level. Subsequent investigation into l the HPCI system flow controller indicated that the EG-M portion '
of the HPCI flow control system was not fully in calibratio Controller demand and null voltages were out of tolerance and could not be reset. The EG-M was replaced. Some problems with I the operation of the HPCI flow controller have been noted during previous demands and testing of the system. Over-response of ,
the control valve tends to cause large overshoots and I oscillation during the initial system response. Apparently, i
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this has been a problem with the HPCI system at other BWR plants as well. After some discussions with members of the ERT into the possible cause of the HPCI centroller problems, the inspectors discussed this issue with another BWR site resident inspector. At that site, recent improvements in HPCI performance had been achieved by completion of a modification to the control oil system which helps reduce the initial system overshoot. The modification was in accordance with Sll 480 (HPCI System Startup Transient Improvement, dated February 3, 1989). This modification has been designed for installation into the Hatch HPCI system but not yet implemente It certainly is not clear that implementation of this modification would have prevented this failure, but apparently several other utilities have seen significantly improved system performance by completing the modification. Management indicated that implementation of this modification is still under considera-tio After reactor water levei reached +43 inches, RCIC was tripped by the operators. At this time position indication was lost on 1E51-F013, the RCIC discharge valve. This valve is a DC powered motor operated containment isolation valve. The valve's breaker apparently tripped with the valve full open. Later in the scram recovery, as water level decreased to about +15 inches, operators restarted RCIC and injection flow of absat 400 gpm was indicated. (0perators did not want to supply water from-the condensate system since power had been lost to demineralizer holding pumps.) The shift was concerned since the reador water level decrease appeared to not be turning around fast enoug The crew believed the 1E51-F013 valve was not fully opene PE0s were dispatched to the valve's breaker and RCIC was tripped. Subsequent investigation _ revealed a blown fuse in the control circuitry of the valve. No cause for the bbwn fuse could be found. A search of the history on the valve did not reveal any other such problems in the pas Due to primarily to the problems with the RCIC system, reactor water level decreased to +12.5 inches and a second automatic scram was initiated. HPCI was restarted in manual control and level was recovered. At approximately 1645 HPCI was secured and one reactor feed pump was controlling reactor water leve _- . . _ _ . _ _ _ _ _ . . _ _ . _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _.. . . _ _ . . . _ . _ _ .
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-. During review of the SPDS tapes it was noted that reactor pressure peaked as high as 1097 psig. No SRV's lifted during the transient. Since one set of the SRVs has a 1080 psig (+ or-
, - 1 percent) lif t set point range required by TS, the licensee
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requested confirmation from GE that this did not indicate any problems with the SRV The ERT report stated that the GE response indicated that the SRV behavior was satisfactory. One factor in the review was a correction for the drop in pressure from the vessel to the SRV sensing point. The license did manually normally cycle the SRV's at 250 MWe during the subsequent startup in order to further confirm that the valves would operate as expecte During the review of the SPDS tapes on the transient it was noted that reactor building ventilation damper 1T41-F043B did not close as expected. This damper is an accessible area exhaust fan discharge outboard isolation damper. The inboard damper in the line, 1T41-F043A, did shut as required. (The dampers should close on a secondary containment isolation signal
. which occurred at reactor level -35 inches). Corrective maintenance was performed on the air cylinder on the damper's >
operato The sequence of events which resulted in the scram from 100 percent power began with one phase of the 230 kV Offerman transmission line becoming disconnected from a tower near the Satilla substation (approximately 30 miles south of the Hatch site). As a result of the disconnected line, a phase-to-phase fault occurred which should have resulted in both PCB 179490 and PCB 179500 opening to isolate the fault. (These breakers are in the Hatch 230 kV switchyard and are located one on each side of the faulted Offerman line), if both of these breakers would have tripped open as expected, Unit I would
, have remained on line cunnected to the grid through PCB 17951 However, at least one pole (shase 2) on the 500 breaker did not ope Consequently the next breaker in the line, PCB 179510, opened and disconnected the main generator from the c-id. Indications are that phase to ground faults resulted in a mai- nsformer lockout signal which tripped the turbine just previous se 510 breaker opening.
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The turbine trip resulted in a reactor trip because power vas above 30 percent rated thermal powe Apparently some current limiting resistors in the trip coil. circuit for PCB 179500 failed. This initiated a small fire in the enclosure of these resistors. The inspectors observed portions of work and testing involving repairs to this circuity and asscciated cablin _. . . . _ _ . _ _ , , . - - - _ - _ _ . _ . - _ . _ __ _ _ __ __ _ _ __ _ ____
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The current limiting resistors and adjoining control circuity were damaged and required replacement. The trip coil did not fail during the event. No mechanical problems were noted with the breake Additionali f, the main contacts on the breakers did not have any indications Of damage as a result of the transient. A quality check on switchyard activities was performed by an experienced onsite enginee The report of this check stated that this instance was the first time in 18 years of service that a breaker of this design failed in the Hatch switchyard. The report concluded that the preventive maintenance on the breakers has been adequate. One item mentioned in the report indicated that it had been previously identified (in 1990) that written procedures are not being utilizec'
i to perform protective relaying testing. This condition did not have an impact in this event and indicates that some attent~i has been directed at switchyard activities in the pas Tnis report also indicated that, dt'e to poor coordination between switchyard maintenance anc Hatch engineering, PCB 179500 was removed from service improperly. Links had been opened which affected signals sent to the turbine generator on an opening of the 500 hreaker. With only the 510 breaker operable and the plant generating to tFe grid, the opening of thc 500 breaker would not send a signal to the turbine. A Hatch engineer corrected this situation and had t 9 link rnoositioned. The inspector had, immediately following the tr cascussed the potential impact of restart with the 500 breaker inoperable with management and was assured all such considerations would be analyzed. Apparently, despite such efforts, personnel in the switchyard took acuons without the knowledge of plant Hatch personnel which could have directly affected plant operation. The inspector discussed this with engineering and plant managemen While many activities performed in the switchyard do not directly impact on unit operation those that have such potential must be closely coordinated with Hatch Engineering. The inspectors are closely following the licensee's corrective actions to ensure that such activities are more closely coordinated in the futur The inspectors conc 1:d d '
hat the ERT throughout its process from iritial SPDS tape is irough to detailed followup of the switchyard breaker arn ..m flow controller problems, was thorough and highly professiona CFR 50.72 notifications were made concerning the reactor trip, the HPCI initiation and the second reactor trip signal caused by low reactor level. The licensee also immediately contacted the appropriate Region II DRP personnel. A subsequent 50.72 call was made concerning the 1T41-F0043B damper failur Additionally, the licensee made significant efforts to keep the inspectors informed of all issues during the investigation and recovery. At approximately 1045 on January 20, Unit 1 was returned to critical operation No violations or deviations were identified.
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7 SAER Audit of Radiological Waste (71707) (40500)
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During the reporting period, the inspector reviewed the SAER Audit of Radiological Waste (90-7C-2) conducted by the site SAER organization '
from December 6, 1990 through January 7, 1991. This audit examined the radiological waste program for compliance with regulatory requirements and procedures, with special emphasis placed on TS implementation. Two of the audit findings resulted in the licensee's cubmittal of LERs 321/90-23 and 321/90-24. More specifically, LER
- 1/90-23 resulted from the licensee's failure to properly implement IS requirements for LLD, while LER 321/90-24 was submitted as a result of the failure to sample offgas within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of an increase of greater +han 50% in pretreatment activit Following SAER's presentation of the audit findings on January 7,
, 1991, ranagercat aggressively pursued corrective actions. In addition to correcting 9 e deficiencies discovered in the audit, a five person team was es.tabl!sud L ensure compliance with all chemistry / health physics related TS. .:ds team will perform a detailed /in-depth technical review of all chemistry /HP TS to confirm that current plant procedures implement the requirements specified in the TS. This efiart reflects the strong commitment by high levels of management to resolve the deficiencies and is a noted strengt No violetions or deviations were identifie ;
furveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy. The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification'where required, handling of deficiencies noted, and review of comple'ed work. The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was completed.
l The following surveillances were reviewed and witnessed in whole or in part:
34SV-E41-002-1S: HPCI Operability lest 57SV-P33-001-2S: 22 H0 Analyzer Functional Test >
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8 Maintenance Activities (62703)
Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved procedures in use adequately described work that was not within the skill of the trade. Activities, procedures, and work requests were examined to verify; proper authorization to begin work, provisions for fire, cleanliness, and exposure control, proper return o# equipment to service, and that limiting conditions for operation wer' me The following maintenance activities were reviewed and witnessed in whole or in part:
MWO 2-91-0288; Repair of PSW Pump 2D Discharge Check Valve MWO 1-91-0551; Replacement of " oil % Relay 1061-K24 No violations or deviations were identifie . ESFSystemWalkdown(71710)
The inspectors routinely conducted partial wal2 downs of ESF system Valve and breaker / switch lineups and equipment conditions were randomly verified both locally and in the control room to ensure that lineups were in accordance with operability requirements and the equipment material conditions were satisfactor During this reporting period, accessible portions of the Unit 1 MCRES system were walked down in detail. This effort involved confirmation that system lineup requirements in procedure 3450-Z41-001-15, " Control Roca Ventilation System," were consistent with the as-built configuration and the applicable plant drawings (H-16042 and H-26094). The detailed walkdown also involved confirmation that valves, breakers, and switches were properly positioned and that material condition was satisfact" During the walkdown t uspector discovered that breaker 1C (Alternate Supply.to Control Building MCC 1E 1R24-5029) located in MCC 1R24-S002, was positioned in the "off" position rather than the required specified "on" position. This condition was reported to the Unit 1 Shift Supervisor and was corrected by repositioning the breaker by operations personnel. _ It appears that this condition is not of safety significance in that the sole function of this breaker was to supply an alternate source of power to an already powered MCC (1R24-S029). This f1CC provides power to var 1ous air conditioning and cooling loads in the control buildin Some confusion and delay may have occurred if the 1R24-S029 MCC nad lost power and the operators tried to reenergize the MCC through the alternate-supply by closing the feeder breaker from MCC 1R24-S002 (breaker 1E in MCC 1R24-S029). The 1R24-S029 MCC would not have been energized due th mispositioned breaker. The inspectors concluded that the operators could
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breaker 1C (in MCC 1R24-5002) was r.ot in the "on" position.
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Also noted during the walkdown was the material condition of 1Z41-F030A and 1Z41-F030C, discharge dampers of the 'A' and 'C' air handling unit Z41-F030A was found to have a very slight air leak, while 1241-F030C was found to have excess grease and dirt on and around the valve. These conditions were reported to the Unit 1 Shift Superviso The inspectors also examined the Drywell Pneumatic System on both Unit 1 and 2 during this period. This system provides nitrogen pressure.to components in the drywell including the SRVs and MSIVs. Portions of the systems were walked down by the inspectors. The following items were noted:
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The air compressors on the Unit 2 Drywell Pneumatic System had numerous RBCCW leaks at piping joints and fittings. A funnel under one leak draining the leakage to a leakoff line was marked October 198 Several other leaks were not being collected or controlled as contamination areas. When the inspectors informed maintenance management of the leaks he was informed that MWO 2-01-212 had been initiated earlier that same week to repair or collect the leakag The inspector subsequently noted .that within several days all the leaks were repaire The inspectors noted that the applicable FSAR chapters do not contain completely accurate descriptions of how the system is currently utilized at Plant Hatch. While the FSAR has been revised to some extent to indicate that the Nitrogen Storage Tank is now the " normal" supply to this system, there are still numerous inaccuracies in the FSA For example, Page 10.19-2 of the Unit 2 FSAR states that the nitrogen system supplies gas at 115 psi to the Drywell Pneumatic system and also states if pressure drops to less than 103 psig in the receiver, then an alarm will sound and the backup nitrogen system will automatically tie in via the F001A and F001B valves. Page-
- 10.19-8 states that the automatic tie in of the nitrogen system (now the normal supply) is functionally tested during each refueling
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The inspectors noted several apparent discrepancies between the two l Units involving this system. On Unit 2, the internals of check l valve 2P70-F016 (outlet of pneumatic system receiver) are removed but l the corresponding Unit 1 valve still has internals in place. It is
! not clear how the Unit I receiver is initially changed when the system is placed into operation. Also the air filter trains are handled differently between the units. On Unit 1 both filters are on line normally while on Unit 2 only one filter train is normally in service with the other as a backup or standby +. rain.
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I The inspector discussed these issues as well as some other items with the
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' designated Drywell Pneumatic System Engineer. No speci:1 operational l concerns have been identified at this time. The inspeccors will continue
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to followup on these item l No violations or deviations were identifie . Inspection of Open items (92700) (90712) (92701)
The following items were reviewed using licensee reports, inspection, record review, and discussions with licensee personnel, as appropriate: (Closed) LER-321/89-10: Two Reactor Water Cleanup 1solations in Twenty-four Hour. Period. This LER addressed two unanticipated partial isolations of the RWCU system which occurred on August 23 and 24, 1989. The first event occurred approximately 10 minutes after completing a portion of the surveillance " Reactor Water Cleanup Differential Flow functional Test and Calibration." The second event occurred during the rarformance of the same surveillance, although in this case I&C technic.ans were in the process of system restoratio In both cases, annunciation of "RWCU Low Flow" and " Filter Deminera-lizer Failure" were received, followed by the closure of inboard isolation valve 1G31-F00?.
The root cause of these events could not be conclusively determine The licensee's in9estigation revealed that the procedures in use during the events to be technically correct and were being properly utilized. Other extensive investigation efforts as delineated in the r LER did not determine the cause of isolations. The licensee's !
corrective action included the temporary connection of a Data Acquisition and Analysis System in order that any problems with the RWCU isolation logic could be identified. Additionally, the licensee replaced relays 1A71-K26 and 1A71-K28 in the RWCU isolation actnation logi It was the licensee's intention to followup this-report with a_ revised LER if the Data Acquisition and Analysis System revealed the cause of the isolations. This system, however, dit. not provide the licensee with any conclusive reasons.for the isolations, and therefore no revised LER will be submitted. This item is closed.
! '(Closed)LER'321/89-14: Personnel Error Leads to Group 5 Isolation l of Primary Containment Isolation System. This LER addressed an l' unanticipated isolation of the RWCU system that occurred on l November 10, 1989. The event occurred as operations personnel were j placing the 'A' RWCU system filter /demineralizer in servic Comunication problems between plant equipment operators at the
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ramMa RWCU F/D panel occurred, and isolation valve 1G31-F052A was opened without the main control being informed. When valve
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1G31-F052A was opened, a pressure / flow transient actuated the RWCU system high differential flow alarm and initiated the leakage detection system 45 second timer. Because communications were not properly established, main control room operators were not aware that
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- the 1G31-F052A was opened, and the PE0s were not aware that the high j differential flow condition existed. When the LDS 45 second time l delay expired, the Group 5 valves (1G31-F001 and 1G31-F004) isolated per desig The root cause of this event was determined to be personnel error in that non-licensed operators failed to properly establish communications with the main control _ room prior to opening valve 1G31-FC52A as required by the system operating procedur Licensee corre:tive action involved counseling the involved personnel and issub g_a memorandum from the Manager of Operations to all operations personnel emphasizing proper communication techniques. These actions were completed by December 8, 1989. Additionally, the licensee implemented a design change which installed a small bypass line around each F/D inlet isolation valves to provide for the slow pressurization of RWCU F/D following precoa This DCR was
. implemented on July 13, 199 Based on these actions, this item is closed, (Closed) IFI 50-321,366/89-27-03: Methodolcgy for Ensuring that the Proper Procedure Revision is Utilized. In October 1989, the inspector had noted that an attachment to a procedure being used for movement of fuel during rr 'oeling operations was the incorrect revision. This revision nad only included editorial changes and thus this example had little safety significance by itsel It appeared that a method to help ensure only current procedure revisions would be utilized would be beneficial. The licensee investigated the issue and found that this was an isolated case. The distribution of the revision had been missed' A check of the distribution of 358 other
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procedures was performed and all had been correctly distribute Corrective action to prevent similar occurrences were completed and included:
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10AC-MGR-003-0S (Pre revised to require (paration and Control ofa Procedures)
in normal circumstances) seven day period was between approval and effective dates on procedures. This has given more lead time for procedure processing and distributio This was completed in April, 199 A GM Departmental Directive was issued to all personnel emphasizing the importance of procedural compliance including verification of a correct revision before using a procedur Since this issue occurred, the ilspectors have closely monitored procedurai usage and verified that the correct revision is utilize Only one instance was identified in which the incorrect revision was being utilized. On August 21, 1990, an inspector observed an offgas system sampling evolution in which 64CH-SAM-031-0$: Routine and Post Accident Sapling of Reactor Coolant and Drywell Atmosphere using the
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Automated Isotopic Measurement system was not the latest revisio The procedure had been revised effective earlier that same e.f. The j H mistry technician had picked up the procedure before the I documentation personnel in chemistry had entered the revision in the ;
file. This revision was also primarily editorial in nature. As a I result of this occurrence, the chemistry department took action which ensure procedure revisions are verified through document control or l the plant's Nucleis computer system prior to use. Since this latest case was the only one identified since the IFI was issued and corrective actions were promptly completed, this IFI is considered close l d. (Closed) IFI 50-321,366/89-27-02: Reactor Operator Licensee Verification. This item was opened to address potential problems in l tracking of licensed operator qualifications. The inspector had i concluded that while the existing administrative controls seemed to be adequate-to prevent an unqualified individucl from assumin licensed duties, improvements could be made to that system. The licensee agreed that a mechanism for on shift supervision to access computer-based files and verify licensee status would be develope Since April 1990, shift supervision has had the capability to access TRAQS (Training Records and Qualification System) which provides current status of licensed operators. Items displayed include the status of an individuals licensee renewal, the biennial NRC physical examination, segment requalification training, hours- spent operating the facility as well as other management or emergency planning qualifications. The inspector equested that an SOS access this information and verify the qualifications of his shift. The supervisor was able to quickly get into the system from a CR keyboard and understood how to interpret the displayed information. The inspector also discussed tne entry of the information into the system with those personnel responsible for updating the data. It should also be noted that the computer-based system is completely separate and redundant to other administrative mechanisms for monitoring licensee' status. Additionally, licensed operators sign a sheet indicating that they are qualified to perform duties prior to assuming a watc The inspector concluded that this system provides an accurate and timely status of licensed operator qualification This item is close (0 pen)IFI 321,366/90-26-02: Failure to Enter Appropriate TS LC0 During Instrumentation Surveillance Testing. During this inspection period a coordinated effort between NRR, the licensee and the residents resulted in progress toward resolution of this issue. On the morning of January 17, 1991, the licensee informed the residents that part of the reasoning which caused NSAC to permit a "2-hour inoperability period" on the instruments despite a lack of specific allowance in the TS was a statement in the Unit 1 TS basis. Page 3.2-50 states "when necessary, one channel may be made inoperable for brief intervals to conduct required functional tests and i _ _ _ . . _ _ .- -. - - - - - ~~-
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calibration". 'Brief interval' is not defined in the T No such statement appears in the Unit 2 T A conference call on this issue'was held later >!it da The licensee agreed to submit a proposed change to tue TS which would define specific inoperability periods for instrument surveillance testing. In the interim, all surveillances are to be performed
.within the TS specified out of service time or within 2-hours if no limit is specifie As stated in Inspection Report 90-26, the inspectors immediate concern in this issue was the apparent misuse of the "2-hour inoperability period." Licensee management concurred that this was improper and promptly initiated action to correct this. Guidance was issued which states that the 2-hour inoperability period is not to be utilized for any activities other that routine surveillance testin Additionally, the licensee initiated changes in the logkeeping requirements in order to enhance the tracking of instrumentation
. removed from service. The inspectors have observed that attention to detail has been significantly increased'concerning logging of instrumentation out of service. Additionally,'the inspectors have noted that frequently, the 2-hour period is not sufficient and the TS LC0 is- consequently ini'.iated. An example is the functional testing and calibration of ID11-K619A and B, RB Ventilation Radiation Monitors. The channels required 9 and 6-hours respectively to complete the testing, The inspectors had not noted frequent utilization of the LC0 in the past to complete the surveillanc There continues to be an apparent discrepancy in the utilization of the term 'inoperability'. - During TS surveillance testing, even if it
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results in inoperability of. equipment, the. licensee does not always declare the component or system inoperable. Operating Order-00-03-0191-S, which provides corrective guidance to the operators on this issue states "if the surveillance test takes more than 2-hours to complete, the instrument is considered inoperable and the required TS actions will be taken". The inspectors noted that in a January 21, 1991, letter to NRR addressing a~ question involving diesel generator testing, the licensee stated: " Intentionally entering LCOs for a routine surveillance test is not a good practice and requires paper work, approvals, and logging each time by the operator and shift supervisors. In addition, each time an LCO is entered additional paper work and problems can be created." If the surveillance testing mabs the system or channel addressed by the TS
. inoperable (in accordence with the TS definition of operability) then the system is inoperable regardless of the cause of the inopera-bility. The appropriate actions statement or allowable inoperability period should be entere It is expected that these details will be resolved during NRR review of the proposed TS. As of this writing, the licensee is completing a i
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proposal for revision to the TS as agreed in the January 17, 1991, conference cal . Exit Interview (30703)
The inspection scope and findings were summarized on February _ 11, 1991, with those persons indicated in paragraph 1. Dissenting comments were not received from the license Proprietary information is not included in this repor . Acronyms and Abbreviations BWR -
Boiling Water Reactor CR -
Control Room DC -
Direct Current DCR -
Design Change Request DRP -
Division of Reactor Projects Region 11 ECCS - Emergency Core Cooling System EG-M - Electro Governor M-Series ERT - Event Review Team ESF - Engineered Safety Feature F/D -
Filter /Demineralizer FSAR - Final. Safety Analysis Report GE -
General Electric GPM -
_ Gallons per Minute HP - Health Physics HPCI - High Pressure Coolant Injection I&C -
Instrumentation and Controls IFl -
Inspector Followup Item kV -
kilo-Volt LC0 - Limiting Condition for Operation LDS -
Leakage Detection System LER -
Licensee Event Report LLD -
Lower Limit of Detection
- MCC -
Motor Control Center MCRES- Main Control Room Environmental System MSIV - Main Steam Isolation Valve MWO -
Maintenance Work Order
[ NCV - Non-cited Violation L NRC -
Nuclear Regulatory Count ssion l NRR - Office of Nuclear. Reactor Regulation l
NSAC - Nuclear Safety and Compliance
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PCB -
Power Circuit Breaker l PCIS - Primary Containment Isolation System PE0 -
Plant Equipment Operator PSI - Pounds per Square Inch l-
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PSW - Plant Service Water RB - Reactor Building _
RBCCW- Reactor Building Closed Cooling Water RCIC - Reactor Core Isolation Cooling RWCU - Reactor Water Cleanup System SAER - Safety Audit and Engineering Review SIL -
Service Information Letter (General Electric)
SOS - Superintendent On Shift (0perations} -
SPDS - Safety Parameter Display System SRV - Safety Relief Valve TRAQS- Training Records and Qualification System TS - Technical Specifications URI -
Unresolved Item
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