IR 05000245/1986001
| ML20203C448 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/11/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203C437 | List: |
| References | |
| 50-245-86-01, 50-245-86-1, 50-336-86-01, 50-336-86-1, NUDOCS 8604210159 | |
| Download: ML20203C448 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report:
50-245/86-01; 50-336/86-01 Docket Nos:
50-245/50-336 License Nos.
Northeast Nuclear Energy Company Facility:
Millstone Nuclear Power Station, Waterford, Connecticut Inspection at: Millstone Units 1 & 2 Dates:
December 31, 1985 through February 24, 1986 Inspectors:
John T. Shediosky, Senior Resident Inspector Thomas Foley, Senior Resident Inspector (January 1986)
Geoffrey E. Grant, Resident Inspector Approved:
&NM 4/41/B6 E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:
Routine NRC resident (153 hours0.00177 days <br />0.0425 hours <br />2.529762e-4 weeks <br />5.82165e-5 months <br />) inspection of plant operations, equip-ment alignment and readiness, radiation protection, physical security, fire pro-tection, design changes, and surveillance.
Inspections addressed failures of the Unit 1 Emergency Gas Turbine Generator and two Main Steam Isolation Valves during surveillance testing.
Findings: There were no violations identified.
Improved Emergency Gas Turbine Generator performance was identified as being needed to assure more reliable onsite AC power availability (Detail 2).
i 8604210159 860414 DR ADOCK 05
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TABLE OF CONTENTS P,ag 1.
Summary of Facility Activities...
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2.
Emergency Gas Turbine Generator boilures - (Unit 1)...................
a.
Inspection Findings..............................................
b.
Detailed Problem Description.....................................
3.
Follow-up of a Problem Identified at Another BWR Facility Standby Liquid Control System Squib Valves' Failure to Fire...................
4.
February 5, 1986 Reactor Scram - (Uni t 1).............................
5.
Main Steam Isolation Valve Surveillance Failures - (Unit 1)...........
6.
Review of Facility Activities.........................................
a.
Operations.......................................................
b.
Review of Plant Operation Review Committee Activities............
c.
Radiation Protection Controls....................................
d.
Main Control Board Annunciators.............................
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1 7.
Follow up of Immediate Notification to the NRC - Personnel Injur within a Contaminated Area - (Unit 2)...........................y
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8.
Exit Interview........................................................
Attachment A Tabulation of Annunciator Status
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DETAILS 1.
Summary of Facility Activities Unit 1:
At the beginning of this inspection period, Unit I was operating routinely at full power.
On January 9 the Unit 1 Emergency Gas Turbine Generator (EGTG)
failed to start during surveillance.
Although subsequent maintenance and testing appeared to resolve the problem, on January 13 the gas turbine again failed to start.
Subsequently, a malfunctioning air-start motor and fuel pump were found.
Because of these problems, an increased surveillance frequency was established.
Minor problems occurred and were corrected.
A series of satisfactory starts began on January 20.
The normal surveillance schedule was restored February 4.
A reactor trip occurred from 70 percent power at 2155, February 5 due to a flow biased APRM high neutron flux scram.
This power increase resulted from a reactor pressure transient occurring when the main steam pressure regulator was being adjusted.
Following a brief shutdown for investigation and main-tenance, ti.e reactor was made critical at 0837, February 7 and reached full power at 0810, February 9.
The plant operated at full power for the rest of the inspection period.
Unit 2:
The plant operated at full power through the inspection period.
2.
Emergency Gas Turbine Failures Encountered During Surveillance Testing On January 9 the Unit 1 Emergency Gas Turbine Generator (EGTG) failed to start during surveillance.
Although subsequent maintenance anJ testing appeared to resolve the problem, problems persisted until January 20.
The licensec established an augmented surveillance schedule to improve confidence in EGTG reliability during this period.
a.
Inspection Emphasis and Findings Since the EGTG is a Unit 1 on-site emergency power source, its problems were given high priority in inspection coverage.
Although the inspectors found that the licensee had also placed high priority on addressing these problems, the complex nature of turbine component interactions and their dependency on each other indicates that specialized technical expertise may be needed to analyze surveillance test data and direct problem re-solution.
Based on the problems during this inspection period and those experienced during the 1985 refueling outage (discussed in liRC Inspection Report 50-245/85-26), such expertise has not been effectively provided or utilized.
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The inspector found that the licensee has implemented the surveillance program required by the Operating License Technical Specifications along
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with a preventive maintenance program to implement their commitments from Section 4.28.3 of the Systematic Evaluation Program's Safety Assessment.
In addition, some turbine parameters are recorfed for analysis during starts for surveillance testing.
However, these measures have not pre-vented multiple instances of EGTG failure to perform.
The inspectors
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therefore concluded that additional measures of EGTG component status and performance trends may be needed to assure improved EGTG reliability.
Since existing regulatory commitments are met by the licensee's present program, there are no unresolved items identified at this time.
However, EGTG performance and programs to improve reliability will continue to receive routine inspection emphasis, b.
Detailed Problem Description On January 7, 1986, pre-start checks of the EGTG were performed in pre-paration for the normal monthly operational readiness surveillance test.
A problem was identified with a relay associated with the transfer of the redundant fuel forwarding pump, as was an excessive oil leak on the governor system.
Corrective maintenance included relay replacement and replacement of the electronic governor type EG-R actuator unit.
A normal start of the Gas Turbine was conducted on January 8 to check repairs and governor response.
Operation was satisfactory.
When the monthly EGTG Operational Readiness Test (" emergency" start) was attempted on January 9, the Emergency Gas Turbine Generator failed to successfully complete its start sequence.
This Surveillance Test simu-lates a loss of off-site power simultaneous with an Emergency Core Cool-ing System (ECCS) initiation.
That results in a rapid acceleration starting sequence.
(The Technical Specifications require placing the generator on-line within 48 seconds.)
Subsequent to this failure a turbine start was made at the normal (slower acceleration) rate in order to gather engine data.
Although the EGIG successfully started, there was delayed fuel ignition accompanied by indications of abnormal fuel flow rate.
Several additional normal starts were conducted successfully, and an Operational Readiness Test was satis-factorily conducted, but abnormalities in the fuel flow traces persisted.
The vendor for the fuel control system, Woodward Governor, was called for assistance.
On January 10 their representative reviewed the recent EGTG operational history and recommended additional testing.
An emer-gency start was conducted satisfactorily on January 10.
On January 13, however, the Gas Turbine again failed to start.
Several fuel tests were performed to purge air suspected to be in the fuel lines.
On the last of these fuel tests, the Gas Turbine failed to accelerate.
The turbine-generator manufacturer, General Electric, was contacted and recommended contacting the Batch Air company for assistance because of apparent problems with the air start motor.
The Batch Air representative arrived on January 14, concurred that the air-start motor had failed, and recom-
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mended replacement of the motor and the engine-mounted fuel pump.
These repairs were made and a normal start was satisfactorily conducted on January 15.
However, indications of air in the fuel system persisted.
A number of fuel tests were conducted to purge the air from the system t
l and identify the source of leakage.
A suspected source of leakage (the l
engine mounted fuel shut-off valve) was replaced.
A normal start of the l
Gas Turbine then failed, with the cause identified as a faulty solenoid l
on the new fuel shut off valve.
Subsequent to the solenoid's replacement,
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normal and emergency starts were conducted satisfactorily.
An additional emergency start was conducted satisfactorily on January 16, but some minor fuel system leaks were noted.
After repair of these leaks, another normal start was conducted.
Turbine light-off was delayed and fuel sys-
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tem flow again showed abnormalities.
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On January 17, af ter the governor EG-R actuator unit was replaced with the unit that had been removed on January 8, a normal start was conducted satisfactorily.
The licensee decided that, since the cause of the prob-lem could not be definitively identified, the remaining governor system
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that could be contributing to the problem, the servo-limiter, would be replaced.
After that replacement, several fuel tests and adjustments were performed to purge the system of air.
An emergency start was then conducted satisfactorily.
The licensee committed to an accelerated sur-veillance schedule in order to increase confidence in the operability of the Gas Turbine.
Satisfactory emergency starts were conducted on January 20, 21, 22, 24, and 28, and again on February 4.
During some of these starts, minor adjustments were made to the servo-limiter to achieve faster start times.
All of these starts exhibited normal characteristics and the licensee j
returned to a normal surveillance frequency.
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The licensee has initiated an analysis program to determine the root i
cause or causes of the Gas Turbine failures.
This effort includes post-l failure analysis of key parameter traces; vendor disassembly and testing (
of the type EG-R actuator, the servo-limiter and the engine-mounted fuel pump; refurbishment of governor hydraulic system hoses and fittings, and evaluation of a possible design change involving the external Gas Turbine fuel shutoff solenoid valve.
Initial analysis indicates the Type EG-R actuator installed on January 8 may have caused most of the Gas Turbine i
l failures.
Final resolution awaits the completion of the analysis pro-l gram.
This will be reviewed by the inspectors when available.
3.
Follow-up of a Problem Identified at Another BWR Facility - Standby Liquid Control System Squib Valves' Failure to Fire During Surveillance testing on February 6 and 11, 1986 at the Vermont Yankee Nuclear Plant, the explosive squib valves used in both injection pathways of the plant's Standby Liquid Control System (SLCS) failed to fire.
As addressed in NRC Information Notice 86-13, issued on February 21, the fallJres were due
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to a combination of two problems.
The first was a wiring change within a ter-minal box associated with the squib firing circuit and the second was use of squib units with alternate internal wiring.
Each of the two squib units pro-vided for the system have two redundant bridge wires which are both energized when the system is started.
The problems occurring at Vermont Yankee resulted in each of the two bridge wires being connected to only one side of the firing circuit.
If either wiring change had occurred alone, the firing circuit would have performed properly.
This problem was masked because the bridge wire continuity circuit was satisfied.
That was due to circuit continuity being completed outside of the wiring in the squib units.
This problem could result in the SLCS being inoperable for the eighteen month period between surveillance testing.
That was brought to the licensee's at-tention on February 18.
The Millstone 1 system was last tested during the 1985 refueling outage, when both explosive squib units were fired in place and demineralized water was injected into the reactor vessel.
Based on the information supplied by the inspector, the licensee performed continuity tests to verify proper grouping of the connector pins to each of the two bridge wires within both of the installed explosive sq'alb units.
Additional con-tinuity tests were made of the three spare squib units in storage.
In addi-tion, the continuity monitoring circuit alarmedbhen the power connector was removed from an individual squib unit.
These actions verified circuit integ-rity.
The licensee has upgraded their purchasing procedures to require that the vendor provide a drawing of the internal squib bridge wire connections with the squibs.
The maintenance procedure for installation of the explosive squib units will contain a requirement to verify pin to pin continuity of the bridge wires.
Records for the installation will contain this data.
The inspector had no further questions on this item.
4.
February 5, 1986 Reactor Scram - (Unit 1)
A reactor trip occurred from 70 percent power at 2155, February 5 due to a flow-biased Average Power Range Monitor (APRM) high neutron flux scram.
This power increase resulted from a reactor pressure transient occurring when the main steam pressure regulator was being adjusted by the control room operator.
Reactor pressure control was being maintained by the turbine control Elec-tronic Pressure Regulator (EPR).
The operator was to increase set pressure from 990 to 1000 psi.
As the EPR pressure setpoint was increased, it exceeded the Mechanical Pressure Regulator (MPR) setpoint.
At that point the MPR began controlling.
(The system controls on the lower set pressure of the EPR or MPR.) Apparently, as the MPR began controlling, a twenty psi pressure in-crease occurred.
This resulted in a reactor power spike causing Reactor Pro-tection System (RPS) actuation.
All safety systems operated properly; this included an isolation of the Reactor Water Cleanup System and an initiation of the Standby Gas Treatment System.
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The turbine control vendor assisted in the investigation of this problem.
MPR sub-system stability was improved through adjustment of the Bean snubber valve used to dampen the regulator response.
This was demonstrated during plant startup by pressure swihg testing at 15 percent power on February 7.
The steady state oscillation was reduced to approximately 2 psi.
Investigation also confirmed that the operator had not been aware of the transfer of pressure control from the EPR to the MPR because the indi ator signifying that the MPR was controlling had failed.
That was repali*..
In addition, the licensee is considering the installation of an annunciau.,r at the main control board to indicate the transfer of pressure control to the MPR.
The licensee is also evaluating vendor recommendations to perform in-ternal MPR modifications which have improved pressure stability at other Boiling Water Reactor facilities.
5.
Main Steam Isolation Valve Surveillance Failures - (Unit 1)
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Several hours af ter the February 5 reactor scram, routine surveillance testing of the Main Steam Isolation Valves (MSIVs) was performed.
During these tests each valve was stroked fully closed and then re-opened.
At 0240, February 6, valve 1-MS-ID, the "0" Main Steam Line (MSL) inboard isolation valve, failed the test when it had dual open and closed position indication lamps lit with its control switch in the "close" position.
The operators' immedi.te reaction to this potential stuck open valve was to close the other "D" MSL MSIV. Although valve 1-MS-2D was closed at 0241, it required three actuations of its control switch to close the valve. With this valve closed Technical Specification 3.7.D.2 was met.
After entering the Primary Containment valve, 1-MS-1D was found fully shut.
The valve had actually closed during the test.
Its " valve open" position in-i dicating switch was found to have not reset due to a warped slide plate.
The switch was repaired'and tested.
Different problems were identified with the other MSIV (1-MS-20).
Its air operator pilot valve was disassembled and in-spected.
A small amount of dirt was found within the assembly lower cover.
These valves are susceptible to failure if contaminated with a small amount of dirt.
Because of this, the pilot valve and its associated air filter were replaced.
Further investigation failed to locate the source of the foreign material.
Following these repairs the reactor was made critical at 0837, February 7 and reached full power at 0810, February 9.
The inspectors reviewed the licensee's actions taken prior to the return to power operation.
Questions remain as to the source of foreign material found within the MSIV 1-MS-20 pilot valve.
Observations will be made of associated maintenance actions during future routine inspections, and particularly in the area of cleanliness controls.
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6.
Review of Facility Activities The inspector regularly observed the licensee's 0800 daily meeting with the Station Superintendent.
Principal staff provided a brief status of their area.
These meetings were immediately followed by simultaneous unit meetings chaired by each unit superintendent.
Those meetings provided a status of each depart-ment and their plans for the day.
All meetings attended were five to fifteen minutes in duration, informative, succinct, and professionally conducted.
No unacceptable conditions were identified, a.
Operations The inspector toured both control rooms on a daily basis, reviewed shift logs, discussed plant parameters and alarms with reactor operators peri-odically',of operating equipment. witnessed shift turnovers, and accompanie
" rounds Through discussions with both licensed and non-licensed operators, the inspector concluded that the operating staff was knowledgeable of plant status and operating equipment.
Licensed operators were very cooperative and responded to each question without delay.
Operators appeared very familiar with the control boards, operating procedures, and plant poll-cies.
Several shift turnovers were observed at each unit.
The inspector noted that operators followed a shif t turnover check list.
The shift turnover appeared very informal.
A highly disciplined atmosphere was not apparent in either control room. Operator appearance was casual (there is no standard dress code for operators).
Snack food containers were peri-odically lying about the Unit 1 control room during back-shift turnovers.
No correlation of the lack of a disciplined appearance to a lack of pro-per operator action on plant conditions was observed.
The matter of control room appearance was addressed to plant management, who indicated that measures to improve that appearance are being considered.
The in-spector encouraged licensee self-evaluation of shift turnover and opera-tor appearance.
L Review of unit logs indicated that both units' shif t supervisor logs varied in format, detail, content, and legibility.
Some operator entries were very detailed, describing events and plant status in a concise chronological sequence (primarily unit 2).
Most log entries, however, are not made in such a manner.
End of shift entries sometimes acknowl-edged the completion of several surveillance procedures without annotat-ing acceptability (i.e. pass / fall) and without specifying the chronologi-cal sequence of when each took place.
For example, the Unit 1 log re-corded that, at 0845 on January 12, the gas turbine air compressor was tagged out for relief valve work, No mention was made of gas turbine operability, technical specification requirements, tag-out number, who was performing the work, or estimated completion time.
In general, the logs were found to provide minimal information and lack detail and con-
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sistency.
However, no specific violations of the governing Administra-tive Procedure (ACP 10,5) were identified, and no specific entries were found to be inaccurate.
The licensee has had little difficulty in reconstructing event sequences because much information is automatically recorded by computer.
Operator turnover sheets provide some information; other information can be de-rived from other sources.
Additionally, because both units were operat-ing routinely at full power, few events occurred to record.
Nonetheless, the inspector discussed the above with operations staff personnel anc'
encouraged a self-evaluation of log-keeping.
During tours of both units, the inspector noted an abser.ce of excessive noise from operating equipment.
Packing leaks from rotating equipment were neither excessive nor insufficient (appropriately set).
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crystals, steam leaks, oil leaks, and valve packing leaks typically found
at many facilities were notably absent, and few components identified l
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l Additionally, control room parameters were without oscillation, pen re-l
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corders were trending in every case, and only a few annunciators were
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In summary, the operating equipment and standby l
components appeared to be not only maintained but clean and well cared for.
No unacceptable conditions were identified.
i b.
Review of Plant Operation Review Committee Activities During January several Plant Operation Review Committee (PORC) meetings were observed.
Three meetings were attended for each unit (a total of six meetings).
Each meeting met the respective unit's Technical Speci-
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fication requirements for composition, frequency of meetings, and re-I sponsibilities.
The committees were found to be fulfilling their func-tion regarding required reviews of specific topics.
Unit PORC meetings were conducted in a controlled and orderly fashion, with a sufficient exchange of information.
However, dissenting opinions were not encour-aged, and doing so could improve overall PORC review quality.
Unit two PORC meetings were characterized by more active participation, a more unrestrained flow of information, and by aggressive probing ques-tions.
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Unit one PORC meetings were less active.
However, the topics presented at these Unit 1 meetings were not as challenging as those presented at Unit 2.
Several items to be reviewed at each meeting were delayed for review due to insufficient information available for the PORC or to inadequate time available for review.
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The inspector discussed PORC meetings at other facilities with the Unit 1 superintendent and noted that the Unit 2 discussions appeared to be more useful. However, both units' meetings were noted as generally good.
No unacceptable conditions were identified.
c.
Radiation Protection Controls Routine tours and checks of Unit 1 and 2 radiation area boundaries, costed surveys, radiological work permits, contamination controls, and frisking
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were made.
Good radiological work practices were noted.
Boundaries were set conservatively.
Posted areas were conspicuous.
It was also noted that radiation caution symbols are utilized, notifying plant workers to ensure Health Physics is notified prior to opening potentially contamin-ated systems.
Such signs are placed in many locations throughout the facility.
The inspector observed numerous employees passing through doors having this type of caution to workers without apparent observance of the cautions by the workers.
However, there were no violations of the posted requirements noted.
Other similar postings designating Radi-ation Areas were also routinely observed.
Plant employees were routinely observed by the inspector to be passing through such Radiation Areas without apparent observance of the signs.
All personnel observed did have proper dosimetry and there were no violations observed.
Nonetheless, the inspector indicated to the licensee that the abundant use of the Radiation Caution Symbol may be causing complacency in regards to its meaning.
A more discrete use of the caution may be more appropriate.
j Additionally, during tours of both units with Plant Equipment Operators (PE0s) on back shifts, the inspector noted, on two occasions, that doors I
with signs stating "High Radiation Area" and "This Door Must Be Locked At All Times" were either open or the lock / latch was defeated by use of tape.
The inspector could not find an accessible area greater than 1000 mr/hr within either unlocked area.
This was discussed with the facility Radiation Protection Supervisor.
l During a subsequent tour on January 16, 1986, the inspectors found the door to the North Scram Discharge Volume Area open.
This is properly posted as a "High Radiation Area" and "This Door Must Be Locked At All Times." A detailed survey indicated a highest accessible gamma radiation level to be 1100 mr/hr on contact and 400 mr/hr approximately 6 inches away from the level switches. The inspector immediately brought this to the attention of the Station Superintendent and noted that, although a whole body dose greater than 1000 mr/hr was not accessible, and therefore a violation was not appropriate, a significant problem regarding the control of High Radiation Doors was apparent.
The licensee agreed and issued a controlled memorandum to his staff identifying the above subject for resolution.
No unacceptable conditions were identified.
These activities are regu-larly examined during routine inspections.
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Main Control Board Annunciators
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On February 14 the resident inspector conducted a survey of the alarm status of the Unit 1 control room annunciators. A similar survey was conducted in the Unit 2 control room on February 27.
The purpose of the I
surveys was to determine overall operator-alarm loading and to identify l
correctable plant conditions that could result in a lessened alarm burden.
l Each of the alarming annunciators was discussed at length with control l
rocm cperators.
The results of the surveys were discussed with licensee supervisory personnel.
The number of alarming annunciators was found to be small.
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The convention in the Unit 1 and Unit 2 control rooms is that white an-
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nunciator alarms generally indicate an abnormal at power condition while green alarming annunciators are generally indicative of normal conditions for power operation.
The results of both surveys are listed in Attach-ment 1 to this report.
7.
Follow up of Immediate Notification to the NRC - Personnel Injury within l
a Contaminated Area
At 1100 on January 21, 1986, an unusual event was declared at Unit 2 as a re-sult of the injury to and potential contamination of a maintenance worker.
l The worker was installing a fan in the Unit 2 main fan room.
He was dressed
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in full protective clothing due to the fan room's designation as a potentially contaminated area.
Although posted as a 0-5000 DPM/100 square cm. area, the
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fan room general area levels are less than 1000 DPM/100 square cm.
The area is posted due to the possibility that crevices may contain higher levels of
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contamination.
The fan itself exhibited levels less than 1000 DPM/100 square l
cm.
The worker's hand became caught in the fan's slowly rotating shaft.
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rotation is believed to have been caused by air flow from the other normally i
operating fans. The worker suffered a full severing of one finger on his left hand and partial severing of another.
He was immediately removed from the
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fan room and stripped of his protective clothing with the exception of the rubber glove on his injured hand.
An immediate whole body frisk indicated no gross contamination.
Due to the high area background, another frisk was conducted at a lower background location.
This frisk again indicated no con-tamination.
Because of the nature of the wound and the fact that the rubber glove remained on his injured hand, the worker was considered potentially contaminated.
Two Health Physics technicians accompanied the worker to the hospital in an ambulance.
Frisking of his injured hand at the hospital after removal of the rubber glove found no contamination.
Surveys of the affected hospital areas, ambulance and personnel who came in direct contact with the worker all indicated no contamination.
The inspector had no further questions on this item.
8.
Exit Interview l
At periodic intervals during the inspection, meetings were held between lic-l ensee site management concerning the inspection scope and findings.
No pro-prietary information was identified as being in the report finding I
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u ATTACHMENT A 1. Tabulation of Unit 1 Annunciator Status-At 1345 on February 14, Unit 1 annunciator status was reviewed with the fol-lowing noted:
Alarming Annunciators a.
Chlorinator Trouble This is a normal indication when unit is secured.
The chlorinator unit was secured due to lack of need because of cold seawater injection tem-peratures and low marine growth, b.
Station Air Compressor This is a normal indication when the compressor unit is secured.
The Instrument Air Compressor was supplying system needs.
The two units are routinely alternated to equalize running hours.
c.
Main Steam Line IB Drain Trap Level High This control room operated valve is inoperable due to a failed solenoid.
The valve can be locally operated by manually isolating the air supply.
A Work Order has been issued for repair.
Alarming Green Annunciators a.
SRM Hi Hi Flux & SRM Hi Flux /Inop This is a normal indication during power operations.
The detectors see high flux even though they are fully withdrawn.
b.
IRM Down-Scale This is a normal indication during power operation.
It is caused by detector flux levels being less than 3 percent of the selected IRM range scale.
IRM detectors are withdrawn during power operations.
c.
Cleanup Precoat Tank Level Low System has not been in use for some time.
This alarm is normal for that condition.
d.
Radioactive Waste Storage Building East Door Door alarms are retained for operator information only; it is part of an unused alarm system which monitors various doors in the plant build-ings.
Specific doors alarm when opened for normal personnel access.
The licensee has chosen to retain these alarm *
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Attachment A
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After Condenser A" Level Low Normal indication when operating the Advanced Off-Gas System and the Hydrogen Recombiner.
f.
After Cendenser "B" Level Low Normal indication when operating the Advanced Off-Gas System and the Hydrogen Recorabiner.
g.
Steam Jet Air Ejector Minimum Flow Condensate Recirculation Valve Closed Due to Loss of Control Normal indication during power operation.
The valve is closed because adequate condensate flow to the steam jet air ejector condensers exists.
2. Tabulation of Unit 2 Annunciator Status-At 0830 on February 27, Unit 2 a:""mciator status was reviewed with the fol-lowing noted:
Alarming Annunciators a.
Reactor Water Storage Tank Level High/ Low This is a legitimate alarm.
At the time the tank needed to be filled as the low level alarm setpoint is 94 percent and the tank level was 93 percent.
However, the Technical Specification minimum volume of 370,000 gallons was met.
b.
RCP "B" Bleed Off Flow Low Alarm channel is malfunctioning; the cause most likely is the sensor.
A repair Work Order has been issued, but a plant shut down of sufficient duration is required for completion.
Required flow has been verified by alternate methods.
c.
RCP "C" Bleed Off Flow Low Alarm channel is malfunctioning; the cause most likely is the sensor.
A repair Work Order has been issued, but a plant shut down of sufficient duration is required for completion.
Required flow has been verified by alternate methods.
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RCP "C" Lower Seal Temperature High Alarm channel is malfunctioning; the cause most likely is the sensor.
A repair Work Order has been issued, but a plant shut down of sufficient duration is required for completion.
Required flow has been verified by alternate method../
Attachment A
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Pressurizer Spray Loop 18 Temperature Low This is a legitimate alarm.
The loop temperature is low because that spray line is isolated due to a packing leak on its associated spray valve.
This will be corrected during the next shutdown of sufficient duntion.
f.
Tavg - Tref High or Low This is a legitimate alarm.
The programmed reference temperature has
been changed and now the alarm setpoint soust be changed.
A Work Order has been issued.
g.
Monitor Panel Trouble - Turbine EHC system This alarm indicates that the local EHC status is in an alarm condition.
However, there is a problem with the alarm circuit.
A repair Work Order has been issued and operators survey local alarm status.
There were none present on February 27.
h.
125-VDC Bus 201D Undervoltage t
There was no undervoltage condition; a problem exists with the alarm circuit.
A repair Work Order has been issued.
Alarming Green Annunciators a.
Hydrogen Monitor Panel "A" Trouble This is a normal indication during power operations.
The system is not used except following an accident.
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b.
Hydrogen Monitor Panel "B" Trouble This is a normal indication during power operations.
The system is not used except following an accident.
c.
Oxygen Monitor Panel Trouble This is a normal indication during power operations.
The system is not used except following an accident.
d.
Steam Generator Blow-down Tank Drain Pump "A" This is a normal indication when the blow-down treatment system is not in use.
It is only needed if a primary to secondary leak through a steam-generator tube results in increased Steam Generator secondary activit r-
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Attachment A
.
e.
Steam Generator Blow-down Tank Drain Pump "B" This is a normal indication when the blow-down treatment system is not in use.
It is only needed if a primary to secondary leak through a steam generator tube results in increased Steam Generator secondary activity.
f.
Steam Generator Blow-down Tank Level Low This is a normal indication when the blow-down treatment system is not in use.
It is only needed if a primary to secondary leak through a steam generator tube results in increased Steam Generator secondary activity.
g.
Condensate Polishing Facility Service Water Pump Overload / TRIP This is a normal indication when the Condensate Polishing Facility radioactive waste concentrators are not in operation.
h.
Radioactive Waste Area Supply Air Flow Low
'A new damper has been installed in the ventilation flow path but the re-vised setpoint has not been established.
The modification process is not complete.
i.
Auxiliary Steam Re-boiler Drain Tank Level High This has been a normal indication when the re-boiler is in service due to drain tank controlling at a level higher than the alarm setpoint.
j.
"A" EHC Pump Running This is a normal indication when the turbine EHC pump is operating.
k.
Turbine Bearing Lift Pump Pressure Low This is a normal indication when the turbine is operating and its lift pumps are secured.
1.
Battery Charger 201C Trouble This is a normal indication (the unit is secured and an alternate charger is in service).
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