IR 05000245/1979028
| ML19305B537 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 01/24/1980 |
| From: | Keimig R, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19305B531 | List: |
| References | |
| 50-245-79-28, 50-336-79-29, NUDOCS 8003190859 | |
| Download: ML19305B537 (9) | |
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O u.s. NuCtExa REcU'AT0av COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I 50-245/79-28 Report No. 50-336/79-29 50-245 Docket No. 50-336 DPR-21 License No. OPR-65 Priority Category c
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Licensee:
Northeast Nurlear Fnergy cnnnany P. O. Bnx 270 Hartford. Connecf.jeut 06101 Facility Name:
Millstone Nuclear Power Station. Units 1 and 2
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Inspection at:
Waterford, Connecticut Inspection conducted:
October 15 - November 30, 1979 Inspectors: Y E b.51m w
/ ///n J. T. Shed}6fky,/ Resident Inspector date signed date signed
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date signed v/
/- 2 1-70 Approved by:
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R'. R. Kelmig, Chief,) Reactor Projects section date signed
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/ No.1, RO&NS Brar!ch
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Inspection summary:
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Inspection on October 15 - November 30,1979(CombinedRepartHos.50-245L
'79-28 and 50-736/79-29)
- Areas Inspected:
Routine, onsite, regular, backshift and weekend insnection by -
the resident inspector (48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, Unit 1; 112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br />, Unit 2). Areas inspected included:
the Unit 1 and Unit 2 control roons and the accessible portions of the Unit 1 reactor, turbine, radioactive waste, gas turb % e generator, and intake buildings, and the Unit 2 primary containment enclosure, auxiliary, turbine and intake buildings, and the condensate polishing facility; radiation-protection; physical security; fire protection; plant operation records; surveil-lance testing; calibration maintenance; core power distribution limits; and,
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reporting to the NRC.
Results: No, items of noncompliance were identified.
Region I Form 12 O NO (Rev. April-77)
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i DETAILS 1.
Persons Contacted The below listed technical and supervisory level personnel were among those contacted:
J. M. Black, Superintendent, Unit 3 P. Callaghan, Unit 1 Maintenance Supervisor F. Dacimo, Station QC Supervisor E. C. Farrell, Superintendent, Unit 2 J. Bangasser, Station Security Supervisor H. Haynes, Unit 2 Instrumentation and Control Supervisor R. Herbert, Superintendent, Unit 1 i
J. Kelly, Unit 2.0perations Supervisor
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E. J. Mroczka, Superintendent, Plant Services J. F. Opeka, Station Superintendent R. Place, Unit 2 Maintenance Supervisor P. Przekop, Unit 1 Engineering Supervisor W. Romberg, Unit 1 Operations Supervisor S. Scace, Unit 2 Engineering Supervisor F. Teeple, Unit 1 Instrumentation and Control Supervisor 2.
Review of Plant Operations - Plant Inspection The inspector reviewed plant operations through direct inspection and observation during routine power operation of Unit 1 and routine power operation and a maintenance outage of Unit 2.
Inspections were made of the accessible portions of the Unit 1 control room, reactor, turbine, radioactive waste, gas turbine generator and intake buildings; the Unit 2 control room, primary containment enclosure, J
auxiliary, turbine and intake buildings.
During the inspection, activities in progress at Unit I were routine power operations, addition of seismic restraints to service water piping and emergency condensate transfer pump suction piping, and repairs to the "B" LPCI injection valve; at Unit 2, routine power operations including the implementation of mutually agreed upon commitments as defined in an NRC letter to Northeast Utilities, dated August 25, 1979, involving the instrumentation installed on steam generator feedwater lines and the performance of required inspection of that instrumentation.
Also inspected were the replacement of the "A" Station Battery Cells with that battery remaining in service, degradation of the "B" charging pump valve block, a shutdown of the unit commencing on October 31 for the inspection and repairs of cracks in steam generator feedwater piping and the actions taken following the failure of the "D" Reactor Coolant Pump seal.
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The inspector also observed operations in the control room including shift turnover, and activities and maintenance on backshifts and week-ends, a.
Instrumentation Control room process instruments were observed for correlation between channels and for conformance with Technical Specification requirements.
No unacceptable conditions were identified.
The inspector verified that the instrumentation installed on Unit 2 steam generator feedwater lines was operable.
This equipment had been installed to implement commitments defined in an NRC letter to Northeast Utilities, dated August 25, 1979.
The instrumentation was found to be within the stated acceptance criteria of special proce-dure 79-2-11, Revision 0, Change 2, dated August 29, 1979.
The inspector determined that operations personnel performed surveillance on the instrumentation at the required frequency.
b.
Annunciator Alarms The inspector observed various alarm conditions which had been received and acknowledged.
These conditions were discussed with shift personnel who were knowledgeable of the alarms and actions required.
During plant inspections, the inspector observed the condition of equipment associated with various alarms.
No unaccep-table conditions were identified.
c.
Shift Manning The operating shifts were observed to be staffed to meet the oper-ating requirements of Technical Specifications, Section 6, both to the number and type of licenses.
Control room and shift manning were observed to be in conformance with Technical Specifications and site administrative procedures, d.
Radiation Protection Controls Radiation protection control areas were inspected.
Radiation Work Permits in use were reviewed and compliance with those documents, as to protective clothing and required monitoring instruments, was inspected.
There were no unacceptable conditions identified.
e.
Plant Housekeeping Controls Storage of material and components was observed with respect to prevention of fire and safety hazards.
Plant housekeeping was evaluated with respect to controlling the spread of surface and airborne contamination.
There were no unacceptable conditions identifie.
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f.
Fire Protection / Prevention The inspector examined the condition of selet'.ed pieces of fire fighting equipment.
Combustible materials were being controlled and were not found near vital areas.
Selected cable penetrations were examined and fire barriers were found intact.
Cable trays were clear of debris.
g.
Control of Equipment During plant inspections, selected equipment under safety tag control was examined.
Equipment conditions were consistent with information in plant control logs.
h.
Instrument Channels Instrument channel checks were reviewed in routine logs.
An inde-pendent comparison was made of selected instruments.
No unaccep-table conditions were identified.
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Equipment Lineups The inspector examined the breaker position on all switchgear and mntor control centers in accessible portions of the plant.
Equipment conditions were found to be in conformance with Technical Specifica-tions and operating procedure requirements.
3.
Review of Plant Operations - Logs and Records During the inspection period, the resident inspector reviewed operating logs and records covering the inspection time period against Technical Specifications and administrative procedure requirements.
Included in the review were:
Shift Supervisor's Log 10/15 through 11/30/79
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Plant Incident Reports 10/15 through 11/30/79
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Jumper and Lifted Leads Log all active entries
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Maintenance Requests and Job Orders all active entries
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Safety Tag Log all active entries
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Plant Recorder Traces daily during control
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room surveillance Plant Process Computer Printed Output daily during control
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room surveillance Key Control Log 10/15 through 11/30/79
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l Night Orders daily during control
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room surveillance
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Plant Incident Reports daily during control
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room surveillance
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The logs and records were reviewed to verify that entries were properly made; entries involving abnormal conditions provide sufficient detail to
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communicate equipment status, deficiencies, corrective action, restora-
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tion and testing; records are being reviewed by management; operating orders do not conflict with the Technical Specifications; logs and inci-dent reports detail no violations of Technical Specifications or reporting requirements; logs and records are maintained in accordance with Technical
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Specification and Administrative Control Procedure requirements.
Several entries in these logs were the subject of additional review and discussion with licensee personnel.
No unacceptable conditions were identified.
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4.
Licensee Event Reports (LER's)
The inspector reviewed the following LER's to verify that the details of the event were clearly reported, including the accuracy of the description of the cause and adequacy of the corrective action.
The inspector deter-mined whether further information was required, and whether generic implications were involved.
The inspector also verified that the reporting
requirements of Technical Specifications and Station Administrative and operating procedures had been met, that appropriate corrective action had
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been taken, that the event was reviewed by the Plant Operations Review Committee, and that the continued operation of the facility was conducted within the Technical Specification limits.
Unit 1 79-1, Updated Report, Laboratory Examination Report of 8 inch, Schedule 80, Type 304, Stainless Steel Cleanup Return Lines, (GE NEDE-25148).
Cracking was determined to have originated in the machined weld prepara-tion in the weld heat affected zone.
The crack mechanism was intergran-ular stress corrosion cracking.
79-29, Failure to Close, of Isolation Condenser Inboard Steam Supply Value 1-IC-1 Upon Receipt of Isolation Signal.
Cause was a faulty torque switch.
79-30, Discovery of Missing Seismic Restraints on Emergency Diesel Gener-ator Service Water Piping.
Discovery was made during system inspection required by NRC Bulletin 79-14.
Restraint locations were identified on original stress isometrics but were not shown on construction drawings.
79-31, Discovery of Missing Seismic Restraint on Emergency Condensate TFihifer Pump Suction Piping.
Discovery was made during system inspection required by NRC Bulletin 79-14.
Restraint locations were identified on original stress isometrics but were not shown on construction drawings.
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ETS-NR/79-01, Anomalous Radioactivity Observed in Oysters.
Third quarter sample of oysters within 500 feet of discharge were determined to contain Silver-110m activity greater than the control by a factor of 100.
ETS-NR/79-02, Floor. Drain Sample Tank "B" Found to Contain 33.6 Curies of Activity Which Exceeded the Environmental Technical Specification Limit of 10 Curies.
Unit 2 79-13, Repeated event, Control Room Chlorine Gas Detection System In-operable on 11/1/79 due to Low Drip Rates of Detector Solution.
Clogged dispensers were cleaned and adjusted.
Frequency of drip rate checks was increased to once per shift.
Initial event on 5/25/79 was repeated on 11/1/79.
79-14, Repeated event, Discovery of Cracking in "B" Charging Pump Valve Body.
Cracks appear to be the result of a stress or fatigue failure in the valve block around the cylinder shoulder.
The licensee is comple' ting
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preparations to replace the A and B charging pumps in early 1980.
The replacement pumps are onsite.
79-16, Repeated event, Calibration Drift of One Channel of the Pressurizer Low Range Pressure Indication.
Channel found 250 psi lower than actual pressure.
Instrument is used to actuate pressurizer power operated relief valve in shutdown range.
79-23, Updated report, Station Battery Declared Inoperable because of Removal of Battery Rack Seismic Brackets.
This was done to' allow indi-vidual cell replacements.
79-27, Station Batteries Declared Inoperable when Drain Piping and Ven-tilation Ducting Passing Through Battery Rooms was Determined not to be Seismically Supported.
ETS-NR/79-01, Anomalus Radioactivity Observed in Oysters (reported by Unit 1).
79-28, Updated report, Hydraulic Snubber on "B" Main Steam Line Atmos-phere Dump Inoperable due to Broken Fluid Reservoir.
Updated event cause, resevoir broken off snubber by vibration induced fatigue failure.
Replaced with a modified unit which has reservoir attached to snubber.
79 29 Hydrogen Analyzer "B" Declared Inoperable due to an Equipment
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FiiTur,e Alarm.
This prevented the detection of a sensor failure.
An a' arm circuit card was replaced due to the failure of an operational suplifier.
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79-30, Failure of Engineered Safety Features Channel "A" Sensor Trip BTsiable's Power Supply.
All channels tripped and were bypassed for 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />.
The failure was caused by the power supply over-voltage protection.
79-31 Failure of CEA Motion Inhibit Circuit due to a Loss of Metrascope Indica, tion of CEA Position.
All CEA's were maintained fully withdrawn and the CEA drive system mode switch was maintained off.
Failure was due to a failed operational amplifier in the
'ock amplifier circuit.
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79-32, During the Period of Repairs to the Metrascope (79-31), CEA 6 and
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TiiIShutdown Group "B" Indicated Low Readings on the Backup Digital Scanner.
A plant shutdown was commenced in accordance with TS 3.0.3.
Faulty input operational amplifiers for CEA 6 and 7 caused a reduced signal to the Backup Scanner and resulted in low readings for these CEA's with the Metrascope de-energized for repairs.
The Metrascope was re-en-ergized allowing proper readings on CEA's 6 and 7 until the input opera-
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tional amplifiers were replaced.
This allowed the normal backup scanner indication with the Metrascope de-energized for repairs.
Total time for loss of indication from CEA 6 and 7 was 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 10 minutes.
79-33, Through-Wall Chloride Stress Corrosion Cracking of Recovered Boric Acid Pump Suction Line.
Cracking was in a three inch, 304 stainless steel, schedule 10S pipe and on the pipe side of the pipe to pump weld.
A repair was made.
The cause of the failure is the presence of chlorides from salt water leakage into the aerated waste syster drains.
79-34, Excessive Leakage of Primary Containment Personnel Access Hatch during Local Leak Rate Testing.
Leakage was through loose mounting bolts on the exterior door operating rod packing gland.
79-35, Setpoint Drift of RPS Channel "A" High Power Level Minimum Trip
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Setpoint.
79-36, Loss of Containment Integrity due to the Opening of Containment Personnel Air Lock Inner and Outer Doors.
The doors were opened by individuals entering and leaving the containment.
Both doors were open i
for about 30 seconds.
A bent operating shaft on the outer door allowed the interlock system to fail.
Following the failure, the air lock was i
maintained locked shut or an operator was stationed at the air lock.
Excessive door swing is suspected tt, have causad the bent operating shaft.
At the time of the event, the reactor us shutdown and the plant was being cooled to cold shutdown conditions.
5.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed by the inspector.
This review included the following considerations:
the report includes the information required to be reported by NRC require-
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ments; test results and/or supporting information are consistent with design predictions and performance specifications; the planned corrective action is adequate for resolution of identified problems; the determin-ation whether any information in the report should be classified as an abnormal occurrence; and, the validity of reported information. Within the scope of the above, the following periodic reports were reviewed by the inspector:
Monthly Operating Report - October, 1979 6.
Plant Maintenance During the inspection period, the inspector frequently observed various maintenance and problem investigation activities.
The inspector reviewed i
these activities to verify:
compliance with regulatory requirements,
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including those stated in the Technical Specifications; compliance with the administrative and maintenance procedures; compliance with applicable codes and standards; required QA/QC involvement; proper use of safety tags; proper equipment alignment and use of jumpers; personnel qualiff-cations; radiological controls for worker protection; fire protection; retest requirements; and, to ascertain reportability as required by Technical Specifications.
The following activities were included during this review:
Unit 1 Failure, in closed position, of containment isolation valve 1-AC-9.
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Failure to perform functional test and calibration of stack gas
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monitor within the prescribed time interval, exceeding administrative requirements but within Technical Specification requirements.
Emergency diesel generator service' water piping seismic supports.
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FWCI subsystem emergency condensate trer:sfer seismic supports.
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Failure of LPCI injection valves, 1-LP-108.
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j Leak in underground fire header (12" FP10) at 90 elbow flange
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Floor drain sample tank "B" exceeded Environmental Technical Speci-
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fication limit for total curie content.
Unit 2 Loss of CEA position indication failure during ST2619H.1.
CEA 6 and
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7 in shutdown group "B" indicated 157 steps.
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Replacement of all cells in station batteries "A" and "B".
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Cracking identified in charging pump "B" valve block.
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PORV 2-RC-402 inoperable, setpoint drift of 200 psi in low mode.
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Containment door damage to interlock and door swing mechanism.
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Control room atmosphere chlorine monitor.
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Containment personnel access hatch measured leakage exceeded 0.025%
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per day.
Water issue from "A" containment spray header nozzles during sur-
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veillance of containment spray header check valve operability test.
Failure of RCP "D" seal.
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Failure of RCP "0" speed sensor.
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Failure to obtain LLRT data prior to valve maintenance on 2-RB-28.38,
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2-RC-001, 2-RC-002, 2-RC-003, 2-RC-045, and 2-RB-28.28.
Inspection and repairs to steam generator 1 and 2 feedwater piping
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i due to cracking discovered at steam generator safe end to pipe weld and pipe to first elbow weld.
During this activity the inspector measured the depth cf the crack in the number 1 steam generator safe end to pipe weld as 0.249 inches prior to weld repair.
7.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to' discuss the inspection scope and findings.
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