IR 05000245/1979022
| ML19290D960 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 01/10/1980 |
| From: | Keimig R, Shedlosky T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19290D954 | List: |
| References | |
| 50-245-79-22, 50-336-79-23, NUDOCS 8002290565 | |
| Download: ML19290D960 (10) | |
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h U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF If1SPECTION AND ENFORCEMENT Region I 50-245/79-22 Report No.
50-336/79-23 50-245 Docket No.
50-336 DPR-21 License No.
DPR-65 Priority
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Category C
Licensee:
Northeast Nuclear Energy Company
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P. O. Box 270 Hartford, Connecticut 06101 Facility Name: Millstone Nuclear Power Station. Units 1 & 2 Inspection at: Waterford, Connecticut 06385 Inspection conducted:
S e r' + ^.ber 2 - Oct ber 2, 1979 Inspectors:
@W 2 Y
/- /d - /d J. T. Shedlosky, s1 nt Inspector date signed date signed date signed
-' N
/ a - /d Approved by-
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,. R. Keimig, Chi Reactor Projects date signed Section No. 1,
&NS Branch Insoection Summary:
Inspection on September 2 te October 2, 1979 (Comoined Report Nos. 50-245/79-22 and 50-336/79-23)
Areas Insoected:
Routine, onsite, regular and backshift inspections by the resident inspector (40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />, Unit 1; 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />, Unit 2). Areas inspected included:
the control rooms and the accessible portions of the Unit I reactor, turbine, radioactive waste, gas turbine generator, and intake buildings; the Unit 2 enclosure, auxiliary, turbine and intake buildings, and the condensate polishing ~
facility; radiation protection; physical security; fire protection; plant operating records; surveillance testing; calibrations; maintenance; core power distribution limits; and, reporting to the NRC.
e Region I Form 12 (Rev. April 77)
8002200
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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 J. Kelly, Unit 2 Operations Supervisor 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 Inspections The inspector reviewed plant operations through direct inspections and observations during power operations of Units 1 and 2 and a maintenance shutdown of Unit 1.
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 enclosure, auxiliary, turbine and intake buildings.
During this inspection, activities in progress at Unit 1 were routine power operations and shutdown on September 5 and 6, or maintenance on equipment located in the primary containment; at Unit f
2, routine power operations including the implementation of commitments in an NRC letter to Northeast Utilities, dated August 25, 1979, involving the instrumentation installed on Steam Generator Feedwater lines.
The inspector observed operations in the control room including shift turnover and backshift activitie 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 stated in an NRC letter to Northeast Utilities, dated August 25, 1979.
The instrumentation was found within the stated acceptance criteria of special procedure 79-2-11, Revision 0, change 2, dated August 29, 1979.
The inspector determined that operations personnel monitored 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 unacceptable conditions were identified.
c.
Shift Manning The operating shifts were observed to be staffed to meet the operating requirements of Technical Specifications, Section 6, both in 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 identi fie f.
Fire Protection / Prevention The inspector examined the condition of selected 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 independent comparison was made of selected instruments.
No unacceptable conditions were identified.
i.
Equipment Lineups The inspector examined the breaker position on all switchgear and motor control centers in accessible portions of the plant.
Equipment conditions were found in conformance with Technical Specifications 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 Techncial Specifications and administrative procedure requirements.
Included in the review were:
Shift Supervisor Log - 9/2 to 10/2 Plant Incident Reports - 9/2 to 10/2 Jumper and Lifted Leads Log - all active entries Maintenance Requests and Job Orders - all active entries Safety Tag Log - all active entries Plant Recorder Traces - daily during control room surveillance Plant Process Computer Printed Output - daily during control room surveillance Key Control Log - 9/2 to 10/2 Night Orders - daily during control room surveillance Plant Incident Reports - daily during control room surveillance
The logs and records were reviewed to verify that:
entries were properly made; entries involving abnormal conditions provide sufficient detail to communicate equipment status, deficiencies, corrective actions, restoration and testing; records are being reviewed by manage-ment; operating orders do not conflict with the Technical Specifica-tions; logs and incident reports detail no violations of Technical Specification or reporting requirements; logs and records are maintained in accordance with Technical 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.
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 cause and adequacy of corrective action.
The inspector determined 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 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 79-25 - Required total peaking factor for 8x8R fuel determined to be more restrictive than that stated in Technical Specification 2.1.2.A.l.
NEDE-25074, the " Nuclear Design Report" used a more restrictive peaking factor for 8x8R fuel used in Reload 06.
Technical Specification 2.1.2.A.1 establishes limits for only 7x7 and 8x8 fuel; they are 3.08 and 3.04 respectively.
This became apparent on September 13 when a copy of NEDE-25074, which was first transmitted to the site on July 10, 1979 was reviewed.
A review was conducted of the recorded maximum total peaking factors for this operating cycle.
The most limiting fuel was 8x8 with a value of 2.9.
The required total peaking factor for 8x8R fuel of 3.01 was not exceeded.
A change to the Technical Specifications has been initiate.
79-26 - The failure of a single bus tie breaker, with power supplied from off-site through the Reserve Station Service Transformer, could cause the loss of power to both safeguards buses without causing an automatic start of the Emergency Diesel Generator and Emergency Gas Turbine Generator.
This condition was discussed during a routine review of the plant electrical distribution system on site.
This situation is not specifically considered in the Safety Analysis Report or the Technical Specifications.
With station loads being supplied from the reserve station service trans-former (RSST), opening breaker 52-A601 would de-energize 4160V buses 14C, 140, 14E and 14F. The logic which senses a loss of normal power and starts the emergency power sources requires that breakers supplying 14A, 148, 14C and 14D busses be opened. The logic accepts that 52-A601 may open in place of 14C and 14D.
Although the opening of breaker 52-A601 will de-energize buses 14C and 140, which supply safeguards buses 14E and 14F, buses 14A and 14B would not be de-energized.
Therefore, there would be no automatic start signal to the on-site emergency power sources from the loss of normal power logic.
The licensee's immediate corrective action was to install jumpers which cause the loss of normal powcr logic to assume that the supply to buses 14A and 148 from the reserve station service transformer has been lost.
Therefore, power on these buses would not interru:
the initiation of emergency power sources on safeguards buses.
This change was completed at 8:30 p.m., September 14, 1979.
The problem would not be duplicated if the station service supply remained the normal station service transformer.
After the inspector's review, the following concerns were identified relative to the present design:
1.
If the normal or reserve supply to 140 or from 14D to 14F was tripped, safeguards bus 14F would de-energize and the emergency diesel generator would not automatically start.
In a similar manner, bus 14E may be de-energized by opening the supply to 14C and the gas turbine generator would not start:
2.
Sensing the loss of power to these buses is partially dependent on the proper operation of 4160 volt breaker auxiliary contacts.
Mechanical misalignment may prevent proper operation of breaker auxiliary contacts.
As both channels of the loss of normal power logic use auxiliary contacts in the same breaker, this does not allow separation and redundancy.
3.
In the event of a supply undervoltage condition, operator action is required to transfer safeguards loads to emergency power source.
The licensee is following up on these concerns and this has been identified as an unresolved item (245/79-22-01).
79-27 - Failure to perform a semi-annual surveillance, functional test of the cable spreading area fire detection system.
The licensee had failed to enter this test on the surveillance schedule.
79-28 - Failure of primary containment isolation valve to close.
The two inch suppression chamber vent bypass valve (1-AC-12) failed to close due to rust and scale on the valve disc pivot mechanism.
The valve was disassembled, inspected, cleaned and reassembled.
The valve operated satisfactorily after this maintenance action.
Unit 2 79-23 - Station battery "B" was declared inoperable when seismic bracing was removed to allow the replacement of two cells.
This condition existed for three hours.
79-24 - RPS Channel D thermal margin / low pressure and local power density trips failed in the tripped condition.
In accordance with Technical Specification Action Statement 3.3.1.1, Table 3.3-1, 2.b, these trips were bypassed.
A failed computation module was replaced.
This condition existed for seven hours.
79-25 - One of two pressurizer power operated relief valves was made inoperable while performing maintenance on a 480 volt load center supply transformer.
The reactor was shutdown.
PORV 2-RC-402 was isolated and disabled August 10 and 11; PORC 2-RC-404 was isolated and disabled August 15 - August 17, 79-26 - Fluctuation in safety injection tank number 3 level indication resulted in exceeding Technical Specification 3.5.1.b maximum level by 1.0%.
The cause of erratic transmitter operation was not determined.
The transmitter was replaced.
79-27 - Discovering on September 24, at 8:30 a.m., that a piping and exhaust ducting passing over portions of both station batteries was not supported in accordance with design drawings.
Concurrent with implementing the conditions of Technical Specification Action Statement 3.0.3, the inadequately supported drain piping and ducting located in the vicinity of the battery was removed.
Station battery B was declared operable at 12:50 p.m., September 24; station battery A at 2:00 p.m., September 2 A hydraulic snubber, located on the 8 main steam line atmospheric dump valve was found inoperable due to a damaged fluid reservoir.
The camage occurred during the reinsulation of an adjacent steam line.
licensee has increased the inspection frequency to once per 12 months per Technical Specification 4.7-3.
5.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee purruant to Technical Specification 6.9.1 and 6.9.2 were reviewed by the inspector.
This review included the following considecations:
the report includes the information required to be reported by NRC requirements; test results and/or supporting information are consistent with design predictions and performance specifications; planned corrective action is adequate for resolution of identified problems; 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 of the inspector:
Monthly Operating Report - August, 1979 September, 1979 6.
Review and Audit On September 11, the inspector attended, as an observer, a joint meeting of the Unit 1 and Unit 2 Plant Operations Review Committee and the Site Operations Review Committee.
The meeting was conducted to review Revision 1 to the Millstone 1 and 2 Radiological Effluent Technical Specifications and the Offsite Dose Calculation Manual in addition to review and approval of several health physics and security procedures.
The inspector verified that the conduct of the meeting was in accordance with Technical Specifi-cations 6.5.1 and 6.5.2.
Subsequent to the meeting, the minutes were reviewed and were found to reflect the committee's actions.
There were no unacceptable conditions identified.
7.
Plant Maintenance During the inspection period, the inspector frequently observed various maintenance and problem investigation activities.
The inspector reviewed these activities to *erify compliance with regulatory requirements, 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 qualifications; radiological controls for worker protection; fire protection; retest requirements and ascertain reportability as required by Technical Specifi-cations.
The following activities were included during this review:
Unit 1 Primary containment isolation valve (1-AC-12) maintenance.
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Primary containment isolation valve (1-lC-1), isolation condenser
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steam inlet from reactor maintenance.
Modification to 4160 volt bus loss of normal power logic.
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Trip of reserve station service transformer feeder breaker to 4160
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volt bus 140.
A terminal on a control panel bulb socket for "open" indication of breaker 153-14D-2 contacting a terminal on the " closed" indication of breaker 2153-140-2, opening 2153-140-2.
Repairs to turbine building service water discharge piping.
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Failure of MSIV position indication system to indicate full open.
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Failure of fuse F4 on EDG local control panel due to a short in the
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coolant low temperature lamp.
Unit 2 Repairs of hydraulic snubber 405388.
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Emergency diesel generator A exhaust line smoke detector failure
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resulting in an area 14 fire alarm and fire pump start.
Spurious trip of #1 RPS-MG set output contactor.
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Failure of water quality monitor, circulating water inlet tempera-
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ture element.
Failure of water quality monitor, spray discharge temperature element.
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Loss of power to channel ESAS actuation modules due to failed 15V
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power supply overvoltage protector.
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Loss of metrascope CEA position indication.
There were no unacceptable conditions identifie.
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.