IR 05000245/1979004
| ML19269E123 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 04/16/1979 |
| From: | Mccabe E, Raymond W, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19269E120 | List: |
| References | |
| 50-245-79-04, 50-245-79-4, 50-336-79-02, 50-336-79-2, NUDOCS 7906260551 | |
| Download: ML19269E123 (22) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
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50-245/79-04 Report No.
50-336/79-02 50-245 Docket No.
50-336 DPR-21 License No. nPR-M Priority Category C
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Licensee:
Northeast Nuciar Eneroy Company P. O. Box 270 Hartford, Connecticut 06101
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Facility Name:
Millstone Nuclear Station Units 1 and 2 Inspection at: Waterford, Connecticut.06385 Inspection conducted,: February 10 - March 16, 1979 Inspectors: _ h M/len I
77 c. T. Shedlosfy, Resitent InspYctor date signed ulk 2 M dsh,
-W. J. Raymond,Aftactor/ Inspector date signed date signed Approved by:
M
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4.[t[1 E. C; McCabe, Jr., Chfer, Reactor Projects date signed Section No. 2, RO&NS Branch Inspection Summary:
Inspection on February 10 - March 16,1979 (Combined Report Nos. 50-245/79-04 and 50-336/79-02 Areas Inspected: Routine, onsite regular, backshift, and weekend inspection by the resident and one regioi, cased inspector (60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> Unit 1; 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br /> Unit 2).
Areas inspected included: accessible portions of the Unit I reactor; turbine and radioactive waste buildings; the Unit 2 enclost re, auxiliary and turbine buildings and the condensate polishing facility; radiation protection; physical security; fire protection; plant operating records; component calibration; maintenance, core power distribution limits; safety review and audit; fuel inspection and fuel modifications.
Resul ts : No items of noncompliance were identified.
2133 320 Region I Form 12-(Rev. April 77)
7 906260 ff/
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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 M. Griffin, Station Security Supervisor
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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 d. Romberg, Un.c 1 Operations Supervisor 3. 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 inspection and observation during routine power operations.
No unacceptable conditions were identified.
Inspections were conducted of the accessible portions of the Unit 1 control room, reactor, turoine and radioactive waste buildings, the intake structura, and the Unit 2 control room, enclosure, auxiliary and turbine buildings, the condensate polishing area and the intake structure.
During this inspection, activities in progress were normal plant power operations and surveillance testing. The inspector observed operations in the control room including shift turnovers, backshift activities and activities on a weekend.
Inspections were made of fire protection equipment and fire barriers.
a.
Instrumentation Control room process instruments were observed for correlation between channels and for conformance with the Technical Specifi-cation requirements.
No unacceptable conditions were identified.
2133 T21
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b.
Annunciator Alarms The inspector observed various alarm conditions that were 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
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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 to the number and type of licenses.
Control room and shift manning were observed to be in conformance with the Technical Specifications and site administrative procedures.
d.
Radiation Protecticn Control 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 were inspected. There were no unacceptable conditions identified.
e.
Plant Housekeeping Conditions St: cage of material and corrionents was observed with respect to pnvention of fire and saf ty hazards. Plant housekeeping was enluated with respect to controlling the spread of surface and a" borne contamination.
There were no unacceptable conditions ieintified.
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 their fire barriers were found intact.
Cable trays were clear of debris.
g.
Control of Equipment During plant inspections, selected equipment under safety tag control were examined.
Equipment cond'tions were consistent with information in plant control logs.
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h.
Instrument Channels Instrument channel checks were reviewed on routine logs. An independent comparison was made of selected instruments.
No unacceptable conditions were identified.
1.
Equipment Lineups The inspector examined the breaker positions on all switchgear and motor control centers in access 1* le portions of the plant.
u Equipment conditions were found in conformance with the 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. The review was governed by the Technical Specifications and administrative procedure requirements.
Included in the review were:
Shift Supervisor's Log
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Plant Incident Reports
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Jumper and Lifted Lead Log
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Maintenance Requests and Job Orders
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Safety Tag Log
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Scram Report Log
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Plant Recorder
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Plant Process Computer Printed Output
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Key Control Log
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Several entries in these logs were the subject of additional review and discussion with licensee personnel.
No unacceptable conditions were identified.
Unit 1 On January 4, the licensee found that the reactor head flange pen of the twc pen control room recorder was reading outside of tolerances required by procedure. This recorder monitors reactor vessel shell to vessel head flange differential temperature by recording these two parameters on each of the two pens.
Technical Specification 3.6. A.2 establishes a thermal limitation of 1400F. The calibration was performed in accordance with a program to surveil instruments 21331323
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used to verify compliance with Technical Specification parameters.
The charts for reactJr heatup and Cooldowns since the last Calibra-tion were reviewed and compliance with the Technicd Specifications was verified.
On January 5, the primary containment drywell equipment drain sump could not be pumped.
It was found that the sump pump discharge contaiament isolation valves were inoperable. The valves are two inch air operated open, spring shut valves.
In addition to the rubber diaphragm in the air motor the valve disk is a rubber diaphragm which provides a zero leakage seal at a weir in the valve body.
The failure involved the separation of the valve diaphragm from its operating shaft. Following replacement of the valve diaphragm operating shaft assembly the failure recurred during tes ting.
It was then found that the air motor shaft sealing 0-Rings had hardened allowing actuating air to leak into the valve bonm and pressurize that area.
Both the diaphragm in the air motor and ;.ne diaphragm in the valve were subjected to actuating air pressure. This resulted in the separation of the diaphragm from the operating shaft and air pressure forcing the valve diaphragm on the valve weir stopping flow.
This type of valve normally has an open vent in the valve bonnet to prevent this failure. The valves involved are containment isolation valves.
To maintain containment integrity in the event of a failure of the valve diaphragm, the vent is plugged.
The valves were rebuilt and placed on a preventive maintenance schedule to include the replacement of diaphragms and 0-Rings every three years.
Additionally, a plant design change has been implemented and a normally open manual isolation valve placed in the line between the containment and the two air operated valves. This valve provides a maintenance s top.
These repairs were accomplished under Job Orders R028-79, R029-79, R030-79 and R031-79.
No unacceptable conditions were identified.
On January 5, and January 31, with the reactor at 98% and 100% power respectively Recirculation Pump 18 speed was runback to minimum speed.
The control room operators matched pump speeds, locked up the 1B Recirculation pump MG Set scoop tube and took manual control. Sub-sequent investigation failed to disclose the cause.
A high resistance relay contact was suspected of interrupting the control signal causing the speed controller to fail at a minimum speed condition.
Relay 104B in the pump control logic was replaced under Maintenance Pequest 63-79.
The inspector reviewed control room chart records of this event.
Reactor plant parameters were in conformance with expected values published in the Safety Analysis Report and the limitations of the Technical Specifications.
2133 T24
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On January 6, while surveillance testing the bellows integrity monitoring system, the bellows integrity test system, of MSIV l-MS-3A failed to operate properly.
Technical Specification 3.6.E.1 requires that the safety / relief valves be operable. Specification 4.6.E.3 requires continuous monitoring of the integrity of the safety /
relief valve pilot valve bellows and Specification 4.6.E.4 requires the demonstration of the operability of the bellows monitoring system once every three months. This demonstration is accomplished remotely by pressurizing the bellows monitoring circuit with air through a solenoid operated valve. That valve was found to have failed.
This work was performed under Job Order R008-79.
Following the inspectors' reviews, it was concluded that the failed solenoid operated valve may have prevented early detection of bellows failure on this valve. The failure was detected during testing with the reactor shutdown and the containment accessible.
There were no unacceptable conditions identified.
On January 7, while decreasing reactor vessel level with the reactor shutdown, the "A" Standby Gas Treatment System (SGTS) did not start and one of two drywell floor drain sump containment isolation valves (1-SS-4) did not isolate.
Investigation revealed that the movable contact cover on a nonnally energized CR120A relay was misaligned.
This prevented the relay contacts from changing state when the relay was deenergized. When reactor water level reached the low level trip point this normally energized relay did not change state and the two components, SGTS-A and 1-SS-4, did follow to their post accident condition. The relay contact cover was repositioned and all other CR120A relays at Unit 1 were inspected.
The inspection revealed that five relays did not have the snap-in contact retainer set in the relay perfectly, but that the contact retainer did not interfere with relay operation.
The inspector randomly inspected several dozen relays in control room panels, found none in questionable condition, and had no further questions on this item.
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On January 10, heat tracing on the Standby Liquid Control (SLC) pumps suction line was lost due to a failed power transformer. The trans-former was replaced and secondary loads balanced to insure uniform c
heat dissipation in the transfonner windings.
Surveillance Test 661.4 "SLC Pump Opertional Readiness Test" was performed for both pumps to verify that the boron solution had not crystalized.
Repairs were performed under Maintenance Request 106-79 and Job Order R024-79.
There were no unacceptable conditions identified.
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On January 17, during excavation for a security system CCTV Camera pole, a leak occurred in a nearby 8 inch fire main.
The apparent cause was metal fatigue causing a flange failure when topsoil was excavated. The leak rate was such that the fire system fockey pump kept up with the leak rate which did not cause starting of the main fire pumps. The line which supplies the warehouse area was isolated and repaired under Maintenance Request 222-79 and Job Order 2-032-79.
In isolating the leak at valve 2-FIRE-95 the automatic wet pipe sprinkler of warehouse 4 and hose station HS-37 were removed from service.
Compliance with the Technical Specification limits was verified by the inspector.
An Engineering Work Request (EWR-554) was initiated to update the Fire Protection System Drawings.
The line involved was found not to be located as shown on plant drawings.
This item is open pending completion of drawing review (79-04-01).
On January 24, power was lost to the met tower and outfall temperature instruments when high winds blew down a power line.
Plant personnel manually recorded inlet and outlet water temperature during the two hour power outage.
There were no unacceptable conditions identified.
On January 24, a large roll-up door to the Gas Turbine Building was found with one side blown out of its track.
Security Officers dis-covered the condition when responding to an intrusion alarm on that door. High winds caused the failure.
The licensee posted a security officer at the door and shored up the door.
Following repairs strong backs were installed to preveer recurrence.
No unacceptable conditions were identified.
On February 3, Fire Detection Station One alarmed in two locations, 4KV switchgear zone number 5, zone 1 and 480V switchgear number 2, zone 4.
A fire detection system heat sensing wire was found to be broken. On February 10, the cable valt smoke detection system, smoke detector zone 9 alarmed.
The cause was a faulty detector.
These zones were repaired and placed back in service.
Hourly patrols were made until the zones were operational.
The inspector verified, on a random basis, that the patrols were being made.
Technical Specification requirements were met.
On February 14, at 11:10 a.m. the Isolation Condenser Steam Line
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inner containment isolation valve (1-IC-1) failed to operate.
This occurred during surveillance testing of the Isolation Condenser steam line high flow differential pressure switches (SP4122).
First indication of a problem was blown control power fuses.
Following fuse replacement the valve motor was determined to be running, but unloaded.
This placed the plant in the fifteen day action statement of Specification 3.5.E.2.
The Technical Specifications required the daily testing of the Fuel Water Injection automatic 2133 326
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actuation logic, Emergen::y Condensate Transfer Pump and the Emergency Gas Turbine Generator daily.
During testing the Gas Turbine failed to start when tested at 2:00 p.m. on February 14.
The unit failed to complete its starting sequence, jet flame was lost at 3,000 RPM generator speed.
The condition of the gas turbine placed the plant in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement.
Preparations for plant shutdown were made.
Tests of the starting logic failed to reveal the nature of the problem.
The unit had last been run on February 13, for monthly surveillance testing.
It is suspected that the protective features of the electronic speed switch caused the problem.
That switch is used to control the starting sequence and provide overspeed protection.
The speed switch presently in use has been the cause of past problems.
The most significant is that its tachometer generator operates at a relative low speed. Trip points at the generator end are 10.55, 59.82 and 68.5 Hz, and at the gas turbine end are 8.5, 31.05 and 70.17 Hz. Several are very close to 60 Hz and all are relatively low.
A small amount of noise or 60 Hz power line influence could have a large effect on the electronic switch.
A replacement switch with tachometer setpoints of 1266, 7178 and 8220 Hz at the generator and 1200, 3168 and 8420 Hz at the turbine is being considered for use.
On February 14, testing failed to disclose the cause for the jet shutdown.
Normal and fast start testing was successful.
The third test was completed by 5:00 p.m. on February 14.
The gas turbine generator tested satisfactorily during daily surveillance through a plant shutdown on February 21.
The resident inspector witnessed surveillance testing performed in accordance with Surveillance Procedure SP 668.2 " Gas Turbine Emergency Fast Start," Revision 1, dated August 2, 1978.
The machine was started without outside power by opening the 4160 supply breaker to the unit auxiliaries then simulating high drywell pressure in the start logic. There were no unacceptable conditions identified.
The resolution of the problems experienced with the unit speed switch will be reexamined (245/79-04-02).
On February 22, the unit was shutdown and the 'l-IC-1. actuator replaced. A failed level gear housing of the Teledine/ Crane T40 valve operator was found on inspection in the drywell.
This work was accomplished under Job Orders R057-79 and R057A-79.
The licensee contacted the vendor for recomendations for action to prevent reoccurrence.
The inspector will followup on corrective action (245/79-04-03).
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The inspector reviewed the implementation of the radiation protection program during this outage.
The following RWP's were reviewed:
790736, work on IC-1; 790725, Torus Plug Top Plate; 790738, Torus scaffolding; 790741, Removal of Torus cover on February 22. On February 23, RWP's 790756, drywell MSIV; 790755, APR-A; and 790748, IC-1 work were reviewed.
The inspector found them properly executed, workers were complying with the provisions of the RWP and the recorded actual exposures agreed with the survey resu!ts.
On February 26, at 2:05 a.m. and 96% reactor power the "F" Target Rock safety / relief valve (1-MS-38) operated and blew down reactor pressure. The plant had been at steady state following a reactor startup.
Reactor pressure had been 1032 psig, generator output dropped from 660 to 590 mwe and torus water level and "F" - APR discharge pipe temperature instruments alarmed.
The valve had been
operating at 180 F, which was higher than the average of 1600F.
At 2:10 a.m. control room operators decreased power using recirculation flow and at 2:12 a.m. man =lly scrammed the reactor.
T 5"5c
'i"9 was started at 2:25 a.a.; peak torus temperature was 110 F at 3:25 a.m.
The valve shut at 2:30 a.m. when reactor pressure reached 305 psig. Torus temperature was below 900F at 5:45 a.m..
Maximum Rate of Change.of reactor temperature, as monitored at tge recirculation system, was 1050F per hour during the blowdown (530 F to 4250F as measured over the one hour period 1:30 a.m. to 2:30 a.m.).
The inspector reviewed plant parameters and verified that operator action was in conformance with the Technical Specifications and Unit operating procedures.
This event was classified as a licensee identified item.
The relief valve 9115 valve and first stage operator were replaced under Job Orders 064-70 and 034-79.
Subseouent investigation indicated that the pilot valve may have operated.
Plans are to replace the valves with an improved design during the Spring 1979 outage.
The inspector conducted further review of the implementation of the radiation protection program during the outage.
The following RWP's for work on 1-MS-3F were reviewed - 790792 and 790788.
The inspector found them properly executed, workers complying with the RWP requirements and that recorded exposures agreed with the survey results. There were no unacceptable conditions identified.
Unit 2 On January 3, B Emerrecy Diesel Generator tripped during surveillance testing following preve ive maintenance.
The cause of the trip was found to be an isolat ' Mw jacket cooling water pressure switch.
The switch had 19
,ertently been left isolated by a 2133 328
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technician following an instrumelt calibration.
The instrument was placed in service and the engine tested satisfactorily.
The licensee reviewed this event with department personnel.
The inspector reviewed the circumstances of this event.
During an emergency start of the engine, that switch would not have caused an engine shutdown. The mistake was found during surveillance testing necessary to qualify the machine as being in an operable standby status.
The inspector had no additional questions at this time.
On March 8, radioactive contamination was found at the Auxiliary steam condensate return from the Unit degassifier.
At the time Unit 2 was receiving auxiliary steam from Unit 1 auxiliary steam boilers.
Unit 2 Reboiler was out of service (preparations for feedwater heater replacement were in progress). On finding evidence of a leak, auxiliary steam to Unit 2 vas secured, the degassifier was secured and the auxiliary steam condensate was dumped to Unit 2 radioactive waste through the condenser pit area sump.
The analysis of the condensate from the auxiliary steam feedwater surge tank yielded dissolved gases (Xe-133,135, r,r-85, 87 and Ar 41). The licensee assumed that all of the dissolved gases were released to
- he atmosphere in the Unit 1 auxiliary boiler deaerated feed tank (no activity was found in the Unit i auxiliary steam boilers) or from a leak in the condensate return line from Unit 2 to Unit 1.
The leak was assumed to have existed frcm the time the degassifier was placed in service on March 7, until found on March 8.
The leak rate at the degassifier was not known.
The licensee assumed that all dissolved fission gases were released from the auxiliary steam system which was returning contaminated condensate at the maximum rated ptmp rate (120 gpm) of the auxiliary steam deaerated feedwater pumps.
The sample of maximum activity was assumed to be representative of the average activity.
Additionally the volume of water with dissolved fission gases was increased by 5,000 gallons to account for draining and flushing the system.
The calculated discharge was 0.108 Ci.
The inspector reviewed the licensee's actions concerning this event. The calculations appeared to be conservative.
The maximum
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continuous rated pumping rate was assumed in a system with pumps which normally cyclic pump from a surge tank against system flow head.
The licensee has a program for sampling potentially contaminated systems.
However, an in line radiation monitor and the auxiliary steam condensate return line from the degassifier was not in service.
This was due to a temperature element, used for detector protection, being out of service.
Resolution of this is considered to be an open item (336/79-02-01).
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(b) Standards Laboratory Certificate (File No.11560)
for Model 600 llahl Thermometer,1/17/79 (c) Standards Laboratory Certificate (File No.11561)
for Model 600 Wahl Thermometer,1/17/79 (d)
I&C Fonn 21008, Custody Record Control, Revision 0, 12/16/76 (e)
IC 1101A, Digital Multimeter Calibration, Revision 0, 2/8/79, SORC 79-5 (f) StandaMs Laboratory Certificate (File No.10367)
for instrument SN 1010, 12/22/78 (g) Standards Laboratory F tificate (File No. 05308)
for instrument SN 194L 5/5/78 (h) RFL Certificate for Model 829G AC-DC Calibration Standard, SN 1949, 1/23/79 (4)
Findings: no items of noncompliance were identified.
b.
Witness of Calibration The inspector observed plant equipment calibrations in progress during the week of February 12, 1979 to verify conformance with technically adequate procedures.
Unit 1 The inspector witnessed the calibration of isolation condenser isolation switches DPIS-1349A, B and DPIS-1350A, B (located on Rack 2257) on February 14, 1979, completed in accordance with SP 412L, Isolation Condenser Isolation Instrument Functional and Calibration Test, Revision 0, PORC 77-53.
The inspector noted that prerequisites and initial conditions were established, required shift supervision approvals were obtained, OA test instruments were employed, measured switch trip points were found to be within the specified tolerances, and that the calibration was conductad in accordance with SP 412L.
No items of noncompliance were identified.
t 2133 351
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Unit 2 The inspector witnessed the calibration of charging pump header flow transmitter channal F-212 on February 15, 1979, completed in accordance with IC 2429A, Calibration of Instrumentation Not Covered by Technical Specifications But Used to Satisfy Technical Specification Requirements, Revision 0, PORC 76-174.
The inspector noted that prerequisites and initial conditions were established, required shift supervision approvals were obtained, QA test instruments were employed, and that the cali-bration was conducted in accordance with IC 2429A.
The inspector had no further questions on the performance of the calibration.
Preliminary test results from the calibration indicated that FT-212 is faulty as exhibited by output drif t (for a fixed input)
on the order of 20 to 30 milliamps at the high and low levels of the range.
Licensee personnel recalibrated FT-212 output to within procedural tolerances and PIR 79-637 and MR 624-79 were issued to replace tha transmitter. The transmitter was deemed adequate for continued use until a replacement is made.
In that the changing system will be a required ECCS System for stretch power operating, the inspector stated that completion of the FT-212 repair would be subsequently reviewed by NRC:RI (50-336/79-02-02).
5.
Witness of Maintenance Activities a.
Scope Selected maintenance activities in progress on both Units 1 and 2 during the week of February 12, 1979 were observed to ascertain that maintenance on safety-related systems is conducted in accordance with approved procedures and regulatory requirements.
Where applicable, the following specific items were verified for the activities witnessed:
(1) Administrative approvals were obtained prior to starting work; (2) Maintenance was accomplished using approved and technically adequate procedures; 2133 332
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(3) Maintenance activities were inspected by the licensee in accordance with internal procedures; (4) Systems affected by the maintenance were functionally tested and calibrated prior to being declared operable; (5) Appropriate QC records were available; (6) QC hold points were observed; (7) Maintenance was accomplished by qualified personnel; (8) Materials and/or replacement components were certified as required by procedures; (9) Appropriate radiological, fire protection and housekeeping controls were established and maintained; (10) Circumstances associated with the maintenance were reviewed against Tech Spec reportability requirements; (11) Plant status controls and tagging operations were reviewed for conformance with established procedures; and, (12) Associated Tech Spec LC0's were satisfied.
b.
References:
(1) MP 2708A, Electrical Valve Operator Repair, Rev.1, PORC 77-130 (2) SF 203 for MF 2708A (3) SF 218 for MP 2708A (4) RWP 790208, dated 2/14/79 (5) SF 207 for MP 2708A (6) Job Order 2-056-79,MP2-2316,2/13/79 (7) MR 568-79 (8)
Red Tag Control No. 380-79-1 for Bkr 6202 SF 201 for MP 2708A
) Retest Form SF 202 for MP 2708A
) SP 780.1, Switchyard and Station Battery Weekly Tests, Rev.1, PORC 77-32 c.
Findings Unit 1 - Weekly maintenance of station and switchyard batteries in accordance with SP 780.1 was observed on 2/15/79'.
No items of noncompliance were identified.
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Unit 2 - Inspection and repair of the operator on 2-ftS-202 in accordance with MP 2708A was observed on 2/14/79.
MS-202 is the inlet steam isolation valve to the turbine driven auxiliary feedwater pump from the #2 SG.
No items of noncompliance were identified.
6.
Core Power Distribution Limits Reactor Engineering Records on both Units 1 and 2 were reviewed to verify the plants were operated within licensed power distribution limits.
Unit 1 a.
Scope Plant computer core performance calculations for January 1979 were reviewed, on a sampling basis, to verify that:
(1)
Linear heat generation rates were within TS limits; (2) APRM setpoints were adjusted (if required) for those cases where the core maximum peaking factor is above the design value total peaking factor of 3.05 for 7X7 fuel and 3.08 for 8X8 fuel; and, (3)
Minimum critical power rates and average planar linear heat generation rates were within TS limits.
b.
References 1) TS 3.11.B and 3.11.D 2) OD-6 Thermal Data for 1/5/79 (3)
P-1, Periodic NSS Core Performance Log and OD-6 Option 3,
for 1/17/79 (4)
P-1, OD-6 Option 3,4 for 1/27/79 c.
Findings A summary of epresentative (and most limiting) values of the parameters reviewed is given below:
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Da te_
Parameter Value Limit 1/5/79 LIMLHGR 10.71
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MAPLHGR 7.13
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.666 1.0 CMPF 2.19
>3.0 MFLCPR(8X8)
.924 1.0 CMFLPD
.722 1.0 1/17/79 CMFCP
.997 1.0 CMFLPD
.535 1.0 CMPF 2.84
>3.0 MAPRAT
.552 1.0 MAPLHGR 5.92
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LIMLHGR 10.73
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MFLCPR (7X7)
.836 1.0 1/27/79 CMFLPD
.727 1.0 CMPF 2.376
>3.0 MFLCPR(7X7)
.868 1.0 MFLCPR(8X8)
.972 1.00 LIMHGR 10.77
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MAPLHGR 7.77
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.722 1.0 No items of noncompliance were identified.
Unit 2 a.
Scope Core performance logs ?.nd INCA printouts for November 1978 through February 1979 were reviewed to verify the following:
(1) Axial shape index is maintained within Tech Spec limits; (2) Uncertainty and flux peaking augmentation factors are appropriately included in the incore detector local power density alarms; (3)
INCA calculated hot channel (peaking) factors are within TS limits; and, (4) Azimuthal power tilt is within TS limits.
213b
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b.
References (1) Tilt - RE Form 21014-1, Rev. 2, 4/20/78 for the period 12/4/78 to 2/5/79 (2)
INCORE TILT SURVEILLANCE for 12/4, 12/11, 12/18, 12/26/78 and 1/1, 1/8, 1/18, 1/22, 1/29 and 2/5/79 (3)
Incore Detector Operability - RE Form 21019-1, Rev. O, 1/31/79 for 12/11,12/18,12/26/78 and 1/1,1/8,1/17,1/18, 1/22, 1/29 and 2/5/79 (4) RE Form 21012-1, Rev. 2, 4/E0/78, Total Unrodded Planar Radial Peaking Factor (Fxy, Tq, Fly) for 12/1/78, 1/1 and 2/3/79 (5) RE Form 21012-2, Rev. O, 4/20/78 - Total Unrodded Integrated Radial Peaking Factor for 12/1/78,1/1 and 2/3/79 (6)
INCAprintoutsofFI, Fly,TqandFqfor 11/2,12/1/78, 1/1 and 2/3/79 (7)
Daily Periodic log for the month of January 1979 (ASI)
(8) Tech Spec 3.2 (9)
INCA Fortran Listing of January 1979 c.
Findings (1) Recorded values of ASI were within the limits of -0.15 to 0.20.
(2) The flux peaking augmentation factors of TS Figure 4.2-1, plus uncertainty factors of TS 4.2.1.3.b for measurement -
calculational, engineering, fuel densification, thermal power measurement and water hole peaking are appropriately incorporated in the local power density alarm package, based on a review of the INCA FORTRAN listing.
(3) Azimuthal tilt for the period reviewed was maintained <l.02.
(4) Total Unrodded Planar Radial Peaking Factor for the period reviewed was maintained <1.57.
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(5) Total Unrodded Integrated Radial Peaking Factor for the period was maintained <l.428.
No items of noncompliance were identified.
7.
Review and Audit a.
Scope Onsite and offsite review conunittee activity in 1978 was reviewed for both Units 1 and 2 to verify that committee functions were conducted in accordance with Technical Specifications and regulatory requirements. This audit encompassed the activities of the Units 1 and 2, PORC, the Unit 1 and 2 NRB and the site SORC and SNRB.
The following was verified:
(1) All onsite and offsite comittee meetings were held at the frequency required by TS 6.5; (2) All onsite and offsite committee meetings convened satisfied the quorum requirements of TS 6.5; (3) Proposed tests, experiments and changes that affect nuclear safety or whose performance may constitute an unreviewed safety question were reviewed as required; (4) Violations of facility Technical Specifications were reviewed by the applicable committees; (5) Proposed changes to the Technical Specifications were reviewed as required; and, (6)
Comittee review and audit functions delineated by TS 6.5.1.6, 6.5.2.6, 6.5.3.6, 6.5.3.7 and 6.5.4.8 were conducted.
b.
References (1)
Unit 1 PORC Minutes 78-01 to 78-113 (12/12/78)
(2)
Unit 2 PORC Minutes 78-01 to 78-123 (12/W/78)
(3) SORC Minutes 78-04 to 78-51 (12/29/78)
(4) Unit 1 NRB minutes 78-01 to 79-2 (1/16/79)
.
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.
(5)
Unit 2 NRB minutes 78-01 to 78-15 (12/20/78)
(6) SNRB minutes 78-02 to 79-1 (1/4/79)
(7) NRC: Region I Inspection Reports (MP2) 78-1, 5, 7,12,18, 21, 22, 25, 26, 30, 31, 36 and 37 (8) NO-78-MP2-190,7/3/78, NRB Audit Millstoro Unit No. 2 -
Spring 1978 (9) MP2 NRB Audit Procedure, Rev. 1,9/28/78 (10)NO-78-MP2-349,8/30/78, Preliminary Audit Report: MP2 Spring 1978 NRB Audit (11) N0-78-MP2-486, 10/10/78, Final Audit Report: MP2 NRB Audit 78-1 (12) N0-78-MP2-613, 11/15/78, NRB Audit Assignments: MP2 NRB Audit 78-2 (13)QMI-440/QM2-565,1/8/79, Plant Audit A60311 - Performance, training and Qualifications of Facility Staff (14)NO-79-MPl-17,1/15/79, Preliminary Audit Report NRB-1 78-2 (15) NRB-1, NRB Audit Procedure, Rev. 1,9/12/78 (16) NRB Reactor Engineering Audit dated 12/27/78 (17) GRE-78-252, MP1 NRB Audit Report - Spring 1978, dated 11/28/78 (18) GRE-78-247, Millstone Station - SNRB Emergency Plan Audit, 11/27/78 (19) GRE-78-192, SNRB QA Program Audit, 10/17/78 c.
Findings No items of noncompliance were identified and, except as noted below, the inspector had no further comments in this area.
Preliminary Audit Report N0-79-MPl-17 for Unit 1, Item 4.B.1, identified a noncompliance with TS 3.3.B.2 when, on 4/12/78, the RCS was pressurized to 1015 psig at 0935 hours0.0108 days <br />0.26 hours <br />0.00155 weeks <br />3.557675e-4 months <br /> for the Operational
.
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Leak Test (SP 681), prior to installing the CRD Housing Support System. The CRD Housing Support System was documented as being in place at 1200 hours0.0139 days <br />0.333 hours <br />0.00198 weeks <br />4.566e-4 months <br /> on 4/12/78 per procedure SP 776.1.
Further, the shutdown margin requirements of TS 3.3.A.1 had not been verified.
NUSCO responded to the NRB audit on 2/8/79 in memorandum MP-1-1115 to specify the corrective actions taken by the plant.
The position taken by the plant staff in the audit response to Item 4.B.1 was that TS 3.3.B.2 was complied with by virtue of QA calculations, vendor input to core load procedures and procedural
'
controls in force at the time of the fuel shuffle, which together act to assure the shutdown margin specification is met prior to performance of the shutdown verification procedure.
The inspector discussed this item with licensee personnel and stated that TS 3.3.B.2 had not been complied with, in that the shutdown margin had not been verified in accordance with TS 4.3.A.1 requirements, irrespective of procedural and/or QA controls established.
The proper sequence for the plant evolutions on 4/12/78 would have been to first install the CRD Housing Support System prior to pressurizing the RCS.
The licensee noted the inspector's comments and stated that this sequence would be followed on subsequent refueling outages.
Licensee performance of the shutdown margin test on April 14, 1978 verified that a conservative shutdown margin existed, showing that there had been no safety hazard involved in this licensee identified item.
The inspector evaluated licensee corrective action as adequate.
The licensee's response to Item 4.B.1 specified that the Operation Leak Test Procedure, SP681, will be revised prior to the next outage to include in section 4.0 a prerequisite that the CRD Housing Support System be installed per SP776.1.
This provision had not been incorporated in SP681, inclusive of change 3, at the time of this inspection.
The inspector stated that this item would be unresolved pending revision of SP 681 to incorporate the afore-mentioned controls (245/79-04-04).
8.
New Fuel Inspection - Unit 1 The inspector reviewed the procedures written to prepare new fuel for placement in the fuel storage pool and observed their implementation.
The work was being performed under Job Order R058-79, " Reload 6, Inspection of Fuel, Fuel Channels, Channel Fasteners and Channel Fuel."
Procedures reviewed were: RE 1012, "New Fuel Receipt Inspection,"
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Revision 2, dated December 21, 1978 and accepted by PORC in meeting 78-114; RE 1072, " Channeling Unirradiated Fuel in the Fuel Inspection Stand," Revision 0, dated January 10, 1978 and PORC Meeting 78-2; and RE 1074 "Unirradiated Fuel Channel and Channel Fastner Inspection,"
Revision 0, February 28, 1979, PORC 79-20 were reviewed by the inspector against the requirements of the Technical Specifications Sections 3.10, 4.10 and 6 and ANSI N18.7.
The procedures were in conformance with those documents and implemented the fuel vendor's recomendations for receipt inspection.
The inspector observed the fuel inspection and channeling operations.
A review of the working documents RE 1012-3 Fuel Bundle Inspection Checkoff List, RE 1072, Channel and Fuel Bundle Serial Number Log and, RE 21001, " Materials Transfer Form," Revision 1, dated June 24, 1976, Transfer Number 1-79-010, approved March 3, 1979 were reviewed.
The inspector noted that Item 10 of RE 1012-3 required measurements of the space between fuel rods and spacers.
There is no provision for taking this measurement directly.
That dimension is verified when taking fuel rod / fuel rod spacing.
The fuel spacers are checked visually.
Licensee representatives noted the inspector's coments.
This is an open item (245/79-04-05).
The inspector verified that the requirements of Housekeeping Zone IV and Cleanliness Level B as stated on Station Forms SF201 and SF202 were implemented.
The inspector noted that special calibration tool serial numbers were properly recorded.
The inspector also reviewed the radiation work permit in use (RWP 79-932) and found it properly executed and the work was in compliance with the RWP. The inspector had no further questions in this area.
9.
Control Element Assembly - Guide Tube Sleeving - Unit 2_
The inspector reviewed the procedures written to insert sleeves in the guide tubes of 63 new fuel assemblies, and witnessed portions of this operation.
The modification was performed under Job Order 2-064-79/2303 "CEA Guide Tube Sleeving Cycle 3, Sleeving of 68 new
"E" Fuel Assemblies and vendor procedure 00000-ESS-107, " Procedure for CEA Guide Tube Repair of CE Fuel Assemblies as Modified for use at Millstone 2," Revision 3, dated November 18, 1978, and approved at the Unit 2 PORC meeting 79-13 dated February 13, 1979.
The inspector noted that the procedures complied with tne requirements of the Technical Specifications Section 6 and ANSI N18.7.
It contained contingency procedures in the event of a guide tube / sleeve expansion tool becoming stuck in a fuel assembly and a post quide tube / sleeve expansion elastomer qualification failure.
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observed portions of the guide tube / sleeve expansion, reviewed quality control records at the job site and examined the quality checks on tools and elastomers in use.
There were no unacceptable conditions identified.
10.
Unresolved Items Unresolved items are those items for which more information is re-required to determine whether the items are acceptable or items of noncompliance.
Unresolved items are contained in paragraph 7 of this report, 11.
Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings.
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