IR 05000245/1979002
| ML19276G657 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/16/1979 |
| From: | Mccabe E, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19276G652 | List: |
| References | |
| 50-245-79-02, 50-245-79-2, NUDOCS 7908020099 | |
| Download: ML19276G657 (22) | |
Text
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U.S. NUCLEAR REGULATOP.Y COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT t
Region I 50-245/79-0?
Report No.
50-336/79-01 50-245 Docket No.
50-336 DPR-21 Category C
License No.
DPR-65 Priority
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Licensee:
Northeast Nuclear Eneray Company P. O. Box 270
_ Hartford, Connecticut 06101 Facility Name:
Millstone Nuclear Station Units 1 and 2
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Inspection at:
Waterford, Connecticut 06385 Inspection conducted:, January 6 - February 9, 1979
/4 / 77 Inspectors:
NM'Se'
dl@
A
,
J. T. Shedloskp R'esident InspecYo~r" date signed
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date signed date signed Approved by:
80 bO 1 3llt.I'7i 3 \\
E. C. McCabe, Chief, Reactor Projects date signed Section No. 2, RO&NS Branch Inspection Summary:
Inspection on January 6 - February 9,1979 (Combined Report Nos. 50-245/79-02, 50-336/79-01)
Areas Inspected:
Routine, onsite, regular, weekend and backshift inspection by the resident inspector (103 hours0.00119 days <br />0.0286 hours <br />1.703042e-4 weeks <br />3.91915e-5 months <br />, Unit 1; 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br />, Unit 2) of:
accessible portions of the Unit 1 reactor, turbine, and radwa'ste buildings, and the containment drywell; the Unit 2 auxiliary and turbine buildings, primary containment, and the condensate polishing facility; radiation protection; physical security; fire protection; plant operating records; monthly operating reports; and licensee event followup, including a security access incident, a through wall crack in the Unit 1 Reactor Water Cleanup System return line, inadvertent Unit 1 safety /
relief valve operation, and a stuck Unit 1 control rod.
Noncompliances: one (Infraction -facility access control inadequacy).
7 9 0 8 0 2 009cl,,
Region I Form 12
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(Rev. April 77)
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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 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
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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.
Pipe Crack - Reactor Water Cleanup System Return Line (Unit 1)
On January 5,1979 the plant experienced difficulty in operating the Drywell Equipment Sump containment isolation valves.
The reactor was shut down and a primary containment entry was made to facilitate repairs.
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On January 6,1979 during the related drywell inspection, water leakage in the vicinity of the Reactor Water Cleanup System return line was observed.
At 1:30 p.m. that day, the leakage was attributed to a circumferential crack in the heat affected zone (HAZ) of a weld in the Reactor Water Cleanup System (RWCU) return line (weld nunber CUBJ-11).
At the time the reactor was in hot standby.
The crack was 0.75 inches long externally.
Radiography revealed a 5 to 6 inch crack internally and a second internal crack, not through wall, on the opposite side of the pipe and about one inch long.
The subject piping was eight inch, schedule 80, type 304 stainless steel.
The crack occurred in a weld joint between the containment outer isolation valve and the inner isolation check valve.
There was a 0.6 gpm increase in unidentified leakage about one month before the crack
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was discovered.
Prior to shutdown unidentified drywell leakage was about 1.7 gpm.
The 0.6 gpm increase was consistent with a valve packing leak.
Following repairs and return to power, drywell unidentified leakage stabilized at 0.6 gpm.
The licensee conducted ultrasonic examinations of that wold and 13 of the 17 welds on the RWCU return line inside primary containment and 9 of the 13 welds on the RWCU supply line inside primary con-tainment.
The inspector noted that the second, not through wall, crack at weld CUBJ-11 was also independently identified by ultrasonic testing.
There were no unacceptable conditions identified except at weld CUBJ-11.
Four welds on the RWCU supply line were not examined because of difficulties in removing insulation and the radiation level in the area.
Four welds on the RWCU return line were not examined because the erection of scaffolding would interfere with the work at CUBJ-ll.
These actions we e reviewed and accepted by the Plant Operations Raview Conmittee.
The licensee has comitted to the examination of those remaining joints during the Spring 1979 refueling outage (0penitem 245/79-02-04).
Nondestructive examination procedures used were plant inservice inspection program procedures.
The licensee's corrective action included removal of a 16.5 inch section of pipe (8 inch, Sh 80, 304 ss) from the side of weld CUBJ-11 where the cracking occurred to the next pipe weld, CUBJ-10.
Those original weld joints were made with 308 weld material.
The weld preparation was made in the 308 ss weld material on a fitting at CUBJ-ll and pipe at CUBJ-10.
During weld preparation, the licensee found an additional crack in the HAZ on the inside diameter of the fitting at CUBJ-ll by liquid penetrant testing requested by a region-based NRC inspector.
That indication was of a crow's foot shape, longitudinal in orientation, about 0.25 inch long and was successfully removed by grinding and buffing. Minimum wall thickness was maintained.
The removed section of pipe was replaced with a section of 8 inch schedule 100, type 316L stainless steel pipe.
Counterboring and weld preparation were in accordance with a repair procedure.
No discrepancies from ASME Section III requirements were identified by the inspecto The inspector observed weld preparation for the installed piping and the replacement spool.
The replacement spool was installed using 316L ss weld material.
The repair weld was between the replacement 316L ss spool and the original 308 ss weld material.
Nondestructive examination included liquid penetrant and radiographic inspection of the root and second pass and visual, liquid penetrant, radiographic examination, and hydro-static testing of the completed welds.
Final radiographic examination revealed a concavity in the inside diameter of the weld at CUBJ-10.
Resolution of this defect included the addition of weld material at that area, to the maximum crown size allowed by ASME Section III.
Nondestructive and hydrostatic testing was again performed.
Radiographic examinations met with the approval of the Level III reader and Code Inspector.
The NRC resident inspector examined the weld preparation and fitup of the replacement spool, and witnessed the QC examination of fitup.
The repair and weld procedures were Detail Wald Procedure DWP-103, Pro-cedure for Performing Butt Welds on Stainless Steel Plate, Pipe and Fittings using the GTAW Process, Revision 1, dated August 3,1978, and OWP-104, Procedure for Performing Butt Welds on Stainless Steel Plate, Pipe and Fittings using the GTAW/SMAW process, Revision 1, dated August 1978.
During repairs, inspection checks were made to assure that the licensee had taken steps to minimize worker radiation exposure.
Inspections were made of drywell conditions and for conformance with the stated requirements of RWP's.
The licensee has contracted for detailed metallurgical analyses of the removed pipe section.
Final corrective action is based on the results of that examination (0 pen item 245/79-02-05).
The inspector observed the implementation of personnel radiation protection procedures on a daily basis during the repairs. These included: the review by licensee committee of the work area and work procedures to establish personnel dose rates as low as reasonably achievable; the installation of temporary shielding; instructions and posting to keep workers out of high radiation fields; the use of additional protective clothing to avoid skin contamination; and a high degree of involvement of health physics technicians.
The inspector verified the effectiveness of these actions by conducting surveys himself and the daily review of radiation exposures as recorded-on Radiation Work Pennits.
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3.
Inocerable Control Rod Drita Mechanism (Unit 1)
During weekly control rod drive operability surveillance testing on January 25, 1979, control rod 22-07, which had been fully withdrawn at position 48, became stuck between positions 46 and 48.
Technical Specification 3.3.A. 2 requires that the reactor be shut-down within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if a partially or fully withdrawn control rod drive cannot be moved with drive or scram pressure unless it is demonstrated that the cause of the failure is not due to a failed control rod drive mechanism collet housing.
The licensee and his vendor evaluated data and concluded that the collet assembly was operating in a normal manner.
Pressure traces following a withdraw comand demonstrated a pressure decay, which indicates collet piston movement.
When the collet piston is moved upward by withdrawal r essure, it is forced downward by the collet spring, once pressure has terminated.
The force of the collet piston acting on the drive water changes the pressure decay rate, which is observed in recordings of drive water pressure.
The licensee attempted to move the control rod with normal and increased drive sater pressure, and attempted to scram the control rod, withoi and with the scram accumulator d
valved inservice.
There wr no control rod motion.
It is the licensee's conclusion that a foreign object is probably wedged between the control rod velocity limiter and the control rod guide tube.
Further investigation is deferred until the refueling outage.
The inspector observed the pressure curves and reviewed the licensee's analysis and its basis.
He had no unresolved questions.
Technical Specification 3.3.A also requires that, in the event of finding a stuck control rod, the rod pattern shall provide greater than 0.33 percent delta-K shutdown margin with the strongest operable control rod in its full-out position, and with all other operable control rods fully inserted at the most reactive condition.
The analysis performed by the licensee's nuclear steam system supplier Mcated that, with all control rods inserted except the stuck F.ro'i rod (22-07), the reactor would be subcritical by 3.2 per $ i lta K.
With all control rods inserted except 22-07 and
%m reactive control rod,18-07, the reactor would be subcritical ( C.) u cent delta K.
With 18-07 fully iaserted, the worst coacition is with 22-07 and 26-07 full out, resulting in. _ _-- -
"
O
percent delta K shutdown margin.
Additional data was provided to indicate that with 22-07 stuck full out, control rod 18-07 could stick as far as notch position 16, at a core exposure of 4200
=
MWD /T, and the shutdown margin would be 0.33 percent delta K.
The licensee programmed the Rod Worth Minimizer to prevent control rod 18-07 from being withdrawn beyond notch position 14.
The rod a
worth minimizer power cutout setpoint was run up to place that instrument in service at 100 percent reactor power.
The licensee
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has reviewed the shutdown margin data and has established operating restrictions requiring the rod worth minimizer to be in operation, and has positioned control rod 18-07 at notch position 14.
Addit'onally, that control rod has been Caution Tagged on the full core display, with instructions that it not be withdrawn beyond notch position 14.
These operating conditions have been reviewed by the Plant Operations Review Committee.
The inspector reviewed the results of the licensee's nuclear steam system supplier's core shutdown margin calculations, the licensee's testing of the stuck control rod and the administrative controls concerning the allowed position of control rod 18-07.
There were no unacceptable conditions identified.
4.
Inadvertent Ooeration of Target Rock Safety /Reliaf Valve (Unit 1)
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At 4:14 a.m. on January 18, the "A" Target Rock Safety / Relief valve i
operated momentarily.
The reactor was at 1020 psig and at steady xt state at about 75 percent power.
The control room operators received
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indication of a problem from the valve discharge pipe high tempera-
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ture alarm.
The channel remained above the instrument setpoint of 2600F for about two minutes and 30 seconds.
The multi-point recorder for safety / relief valves indicated one point at about 5200F and
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then decayed to a steady state valve of about 165oF.
(Valve "A" had a recorded temperature of about 1750F, which was about average, prior to the transient.).
A review of the temperature recordings for the time preceding the event did not inJicate evidence of oilot valve seat leakage.
The inspector reviewed recorder tr'ces of suppression chamber water level and temperature.
These plant parameters were not affected by the transient.
The recorder traces of reactor power, generator output and reactor pressure were also reviewed.
These were normal prior to the event and confirmed relief valve operation.
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The setpoint for this relief valve is 1095 +/- 12 psig.
The licensee's imediate corrective action was to reduce reactor pressure to about 950 psig, although the valve shut at about a 20 psi blow down from 1020 psig. An examination was conducted of the external surfaces of the suppression chamber.
No problems were identified. The inspector reviewed the results of this inspection.
Suppression chamber water temperature was not affected by this transient and remained at about 750F, which is well below the action points in Technical Specifications 3.7.A.1 and 4.7.A.1.b.
The licensee examined the condition of the electrical circuits which provide operation of the valve through the Automatic Pressure Relief Subsystem and manually.
Conditions were found to be normal. The licensee commenced a reactor shutdown on January 19 for replacement of the Safety / Relief valve upper works consisting of the pilot valve and the first stage of the valve.
The original valve was rebuilt on site.
No defects were found in the pilot valve, valve first stage or air solenoid.
The inspector had no further questions on this item.
5.
Primary to Secondary Steam Generator Leak (Unit 2)
On January 18 the licensee determined that a primary to secondary leak might exist in the Number 2 Steam Generator.
Iodine 131 at 1.2 E-5 microcuries per ml was found in the Steam Generator secondary riater (the primary concentration of I-131 was 9 E-2 microcuries per ml). Steam jet air ejector exhaust contained Xe-133 at 1.36 E-5 microcuries per ml.
By January 22 primary activity was 2 E-2 microcuries per ml and Number 2 Steam Generator activity 1.9 E-6 microcuries per ml of I-131.
This translated to a calculated leak rate of 0.004 to 0.007 gpm.
The inspector reviewed the licensee's program to insure that release paths are monitored.
Gaseous release from the Steam Jet Air Ejectors is via the Plant Vent Stack.
Discharges are monitored by the stack sample system and are recorded in the Unit I control room.
Samples of condensate and condensate from steam leaks were all below minimum detectable radioactivity.
Steam generator blow down from Number 2 Steam Generator has a radiation monitor on the process line.
The release to the environment is from the blowdown quench tank, condensate to circulating water and gases through an enclosure building roof vent.
The inspector had no additional questions at this time. The licensee's actions in addressing this event will be reviewed during future inspections (336/79-01-01).
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6.
NRC Bulletins and Circulars (Unit 1 and 2)
The inspector reviewed the action taken on the following NRC Bulletins and Circulars.. In each case the inspector found that a member of the plant staff had been assigned responsibility for the specified reviews and analyses.
Plant administrative controls were used to track the engineering review and implementation of any required actions.
a.
Bulletin 77-01, Pneumatic Time Delay Relay Setpoint Drift (Unit 1)
The licensee developed a surveillance and calibration program and implemented it during the last refueling outage. The program has established acceptable setpoints for the relay's time delay feature, and has placed the relays in a cyclic surveillance test program. The inspector reviewed the records of program imple-mentation and had.no further comments.
b.
Bulletin 77-02, Potential Failure Mechanisms in Certain Westinghouse AR Relays with Catch Attachments (Unit 1 As stated in the licensee's response, although Westinghouse Type AR relays are used at the station in high speed relaying schemes, the Type AR latching relay is not used.
c.
Bulletins 77-05, & SA, Electrical Connector Assemblies Unit 1 - The licensee responded that no electrical connectors of any type were used in accident mitigating systems subject to accident conditions.
During an NRC inspection (50-245/78-10 of March 22-28,1978), it was found that cable splices were used in conjunction with accident mitigating systems at the containment penetrations.
There were no records available concerning the environmental qualifications of these cable splices.
The plant had subsequently replaced those splices with a splice for which qualification data was available.
This action has been reviewed during an additional inspection (50-245/78-27 of July 18-19,1978).
This topic will be reviewed during future inspections following up NRC Circular 78-08, Environmental Qualification of Safety Related Electrical Equipment (Inspection 50-245/78-31 and 50-336/
78-27 of August 1 and 2,1978 were the initial inspections in this area), and inspections following up Bulletin 79-01, Envir-onmental Qualification of Class IE Equipmen Unit 2 - The licensee reported that the only electrical connectors associated with safety systems exposed to a post LOCA environment are 16 coaxial connectors associated with eight power range nuclear detectors.
Electrical connections at containment pene-trations are made inside the penetration enclosure.
This area will be reviewed during the followup of NRC Circular 78-08 and Bulletin 79-01.
d.
Bulletin 77-06, Potential Problems with Containment Electrical Penetration Assemblies Unit 1 - The plant was built with GE types NS02, NS03 and NSO4 containment penetrations.
The penetrations were reportedly qualified to post LOCA containment environment.
This area will be reviewed during the followup of NRC Circular 78-08 and Bulletin 79-01.
Unit 2 - The problem with electrical failure in penetrations first occurred at Millstone Unit 2.
This event has been reviewed during NRC inspections 50-336/77-29 on November 16-18, 1977, 50-336/77-33 on December 19,1977,50-336/78-02 on January 3-6, 1978,50-336/78-07 on February 15-17, 1978 and 50-336/78-08 on April 13-20, 1978.
This area will be further reviewed during the followup of NRC Circular 78-08 and Bulletin 79-01.
e.
Bulletin 77-08, Assurance of Safety and Safeguards During an Emergency - Locking Systems Units 1 and 2)
The inspector reviewed the licensee's response to this Bulletin.
Discussions were conducted with plant personnel and records were reviewed.
Inspections of the facility confirmed the information presented to the NRC in the licensee's response dated February 13, 1978.
The inspector had no further questions on this iten.
f.
Bulletin 78-1, Flammable Contact Arm Retainers in GE CR120A Relays (Units 1 and 2 The licensee developed and completed a program for replacing all Celcon contact arm retainers with Valox parts.
The inspector had no further questions on this ite g.
Bulletin 78-02, Terminal Block Qualification (Units 1 and 2)
The licensee's survey and analysis found no unprotected terminal blocks on safety related systems required to function in the post LOCA environment. The resident inspector confirmed the licensee's findings by checks of the Unit 1 and 2 containments and had no further questions on this item.
h.
Bulletin 78-03, Potential Explosive Gas Mixture Accumulations Associated with BWR Off Gas System Operation (Unit 1 This Bulletin was issued as the result of hydrogen explosions at Unit 1 on December 13, 1977. The licensee's corrective action was detailed in letters dated December 22, 1977, December 27, 1977 and April 21, 1978.
These actions were reviewed during NRC inspections 50-245/77-33 on December 13-23,1977 and 50-245/78-10 on March 22-28, 1978. The inspector had no additional questions in this area.
i.
Bulletin 78-04, Environmental Qualification of Certain Stem Mounted Limit Switches in Reactor Containment Units 1 and 2)
The licensee determined that NAMC0 type D2400X or EA-170-302 Snap Leck switches are not utilized in safety-related applications inside primary containment. This item will be addressed during the followup of NRC Circular 78-08 and Bulletin 79-01.
j.
Bulletin 78-05, Malfunctionino of Circuit Breaker Auxiliary Contact Mechanism - General Electric Model CR10SX (Units 1 and 2)
As reported by the licensee, the GE CR105X auxiliary contact mechanism is not used at Unit 2.
This mechanism is used in Unit I controllers and the problem described in the circular were experienced during plant startup testing. When this problem was discovered the armatures of these devices were removed and polished to remove any surface imperfections.
A review of plant maintenance actions indicates that the GE CR105X contactors have operated properly for at least the last two years. The inspector had no additional questions on this ite k.
Bulletin 78-06, Defective Cutler-Hammer Type M Relavs with DC Coils (Units 1 and 2)
As reported by the licensee, Cutler-Hamer Type M, DC relays, catalog number D23MRD are not used at Units 1 or 2 in safety-related systems.
The inspector had no additional questions at this time.
1.
Bulletin 78-09, BWR Drywell Leakage Paths Associated with Inadequate Drywell Closures (Unit 1 This Bulletin was issued as a result of an event at Unit 1 during the Fall 1976 refueling outage.
The corrective actions discussed by the licensee in the response to Bulletin 78-09 were also addressed during previous inspections (50-245/78-09 on March 17-22, 1978, and 50-245/78-25 on June 21-23,1978).
The licensee will verify drywell head and manway closure tightness procedures during the next CILRT scheduled for the Spring 1979 refueling outage. This issue will be addressed during future inspections of CILRT procedure preparation and of test perfomance.
m.
Circular 77-05, Fluid Entraoment in Valve Bonnets (Unit 1)
The inspector reviewed the results of the licensee's analysis.
Twelve split or double disc valves were identified, six of which are located in the recirculation system and six in the feedwater system. All valves are subject to temperature changes during operation.
The licensee found that all valves :ad been installed in positions to prevent the accumulation of fluids in valve bonnets.
The inspector had no additional questions on this
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item.
n.
Circular 77-09, Improper Fuse Coordination in BWR Standby Liquid Control Circuits (Unit 1)
The licensee examined the fusing of the SLC circuit and found it as specified in the plant control wiring drawings and in confomance with the recommendations of Circular 77-09.
Independent inspector checks verified this component usage.
The inspector had no further questions on this ite o.
Circular 77-10, Vacuum Conditions Resulting in Damage to Liquid Process Tanks Unit 1 The inspector discussed the details of a program implemented to address the concerns of this Circular.
All tanks were surveyed, and all were found to be adequately vented to prevent collapse during pump down.
Ne tank was found which could cause an unmonitored release of radioactive material if it failed.
Additionally, the licensee established a surveillance program to inspect the condition of plant tanks.
That program will include nondestructive testing to determine wall thickness, liner integrity, and paint condition. The inspector had no additional questions on this item.
p.
Circular 77-13, Reactor Safety Sionals Negated During Testing (Unit 1 The inspector reviewed the licensee's analysis of the material contained in this Circular. BWR trip logic design and plant operating procedures are formulated so that testing is accom-plished in one channel of a trip system at a time and that channel is restored to an operable status prior to testing subsequent channels. This was confirmed by the inspector during a check of a random sample of instrument surveillance procedures.
The material of the Circular was promulgated to the members of the I&C Department. The inspector had no further questions on this item.
q.
Circular 77-14, Separation of Contaminated Water Systems from Noncontaminated Plant Systems (Unit 1 The licensee conducted a survey to identify interfaces between radioactivity contaminated and clean systems.
Two points were found. The condensate transfer pumps may take a suction on the condensate storage tank (CST) or the demineralized water storage tank (DWST). A check valve in the line from the DWST events contamination from the CST. As a result of the licensee's t.ady, a manual isolation valve in that line was also locked shut.
This was verified by the inspector.
Tile second interface point is the house heating boiler surge tank emergency makeup from the domestic water system. A single manual valve isolates this line.
The licensee has initiated a Plant Design Change Request (PDCR)
to improve this situation. This item (79-02-06) will be reexamined upon resolution of the PDC r.
Circular 77-15, Degradation of Fuel Oil Flow to the Emeraency Diesel Generator Unit 1 The licensee inspected the Emergency Diesel Generator fuel oil transfer system and conducted a special surveillance test to measure fuel oil transfer rate.
It was determined that the transfer occurred at at least. 24 gpm.
The diesel generator consumes 3.3 gpm at rated power.
The inspector had no further questions on this item.
s.
Circular 77-16, Emergency Diesel Generator Electrical Trip Lockout Features (Unit 1)
The licensee reviewed the protective features for the unit Emergency Diesel Generator. Although the function of the pro-tective features is in accordance with the license application of the FSAR, differences were documented between the 2 Unit 2 Diesel Generators and the Unit 1 Diesel Generator. An Engi-neering Work Request has been initiated to investigate these differences.
At Unit 1 a diesel shutdown occurs on: generator differential current, generator voltage restraint overcurrent, generator reverse power and generator loss of field.
At Unit 2, diesel engine shutdown occurs on low lubricating oil pressure (2 out of 3 logic), engine overspeed, and generator differential current and the generator output breaker is tripped on generator voltage restraint overcurrent. The results and recommendations of the EWR will be reviewed when completed (79-02-07).
t.
Circular 78-02, Proper Lubricating Oil for Terry Turbines Units 1 and 2 Unit 1 - There are no Terry Steam Turbines in use at Unit 1.
The licensee reviewed the lubricating oil usage for the fire water pump diesel engine with the vendors involved. The unit was being lubricated with Mobil Guard 412 then 443. The unit is presently being lubricated with Mobil Guard 445, which meets the vendor's reconinendations.
The inspector had no further questions on this item.
Unit 2 - The auxiliary feedwater pump Terry Turbine governor is lubricated with Mobil Vaportec Light.
This meets the vendor's recommendations. The inspector had no further questions on this ite u.
Circular 78-03, Packaging Greater than Type A Quantities of Low Specific Activity Radioactive Material for Transport Units 1 and 2)
The licensee's procedures for handling LSA material cause the waste to be segracated.
This allows for the scheduling of a certified shippi..g cask of the proper type when needed.
It is the licensee's position that he is complying with 10 CFR 71.12 and DOT regulations.
This item (79-02-08) will be reviewed during future NRC inspections.
v.
Circular 78-04, Installation Errors that Could Prevent Closing of Fire Doors (Units 1 and 2 The licensee determined that neither sliding fire doors nor Mesker D and H Pyromatic door closers are used at the plant.
The inspector had no further questions on this iten.
w.
Circular 78-05, Inadvertent Safety Injection During Cooldown Unit 2 The nuclear steam supply system emergency safeguard actuation system does not use the Main Steam Line low pressure signal.
The only Tctuation during cooldnwn is pressurizer pressure low.
Annunciators alert the control room operator at 150 psi above the actuation point. This allows the pressurizer pressure low input signal to be manually bypassed.
By procedure, it is not normal to cooldown by using the steam dumps.
The inspector had no further questions on this item.
x.
Circular 78-06, potential Common Made Flooding of ECCS Equipment Rooms at BWR Facilities Units 1 and 2 Unit 1 - Each ECCS equipment room (reactor building cornerroom)
has its own sump which is isolated from other sumps and the torus area.
Unit 2 - Area drains from Enginee ed Safeguard Rooms A, B, and C are serviced by individual sumps with their own pumps.
Back flooding through the common pump discharge header is prevented by check valves.
Equipment drains are normally isolated and may be placed in service when the equipment is running.
The inspector had no further questions on Circular 78-06.
B
7.
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 9ecifications and Station Admin-istrative and operating procedures had been met, that appropriate corrective action had been taken, that the event was reviewed by the Plant Operations Review Comittee, and that the continued operation of the facility was conducted within the Technical Specification limits.
Unit 1 78-30, Suppression Chamber Oxygen content discovered higher than allowed by Technical Specifications.
The plant was returned to power operations (the mode switch placed in run) at about 3:30 a.m. on December 14, 1978.
At about 2:30 a.m. on December 15 it was found that, although the Drywell Oxygen concentration was less than 5 percent, the Suppression Chamber Oxygen concentration was 4.5 percent. The licensee's cor-rective action was to increase nitrogen purge flow. All areas of the containment were within the 5 percent limit by 4:30 a.m. December 15.
The licensee discussed this event with members of the operations department who were instructed in the importance of monitoring plant parameters.
The inspector had no further questions on this item.
78-31, A Nuclear Review Board Audit identified that the Reduced High Flux APRM surveillance was being performed prior to a plant startup.
The proper surveillance was scheduled to be performed monthly as part of the Flow Biased High Flux APRM surveillance.
The inspector noted that, although the survei; lance was not performed as required prior to startup, the monthly surveillance had a trouble free history. The surveillance schedule has been corrected.
The inspector had no further questions on this item.
78-32, An Operations Department Audit identified that the Diesel Fire Pump fuel oil sampling was not listed on the surveillance schedule and had not been performed in September 1978 as required. Technical Specification (T.S. ) 4.12.A.l.g.2 requires the fuel oil be sampled once every 92 days.
Fuel oil testing was conducted in June and December of 1978.
Those samples met the requirements of ASTM-D975-74, Table 1, (viscosity, water content and sediment).
Required sampling has been incorporated in routine scheduling and samples are now being taken as required.
The inspector had no further questions on this ite.
79-01, Through wall crack in Reactor Water Cleanup System return line.
(See paragraph 5)
79-02, Failure of Two Safeguards Components in one channel to activate.
While decreasing reactor water level for maintenance with the reactor shutdown, a low reactor water level signal failed to start the "A" train of the Standby Gas Treatment System and failed to provide an isolation signal to one of two drywell floor drain sump isolation valves.
The cause was identified as a misaligned contact retainer on a General Electric CR120 relay.
In response to NRC Bulletin 78-01, the licensee replaced Celcon contact arm retainers with Valox retainers for these relays.
Apparently, during that replacement, the retainer on relay 595-134 located in CRP-904 for the stacked on section chafed the relay armature.
This prevented the relay from spring returning in its deenergized position.
'.ie licensee surveyed all CR120A relay contact retainers at Unit '. to ensure that there were no problres with contact retainers interfering with the relay armature operation.
The survey revealed 5 retainers not set perfectly in their seat, however, in no case were conditions found which would interfere with normal operation.
This has been documented by memo from the Production Te.
- artment(PT-5-79, dated January 15, 1979).
The inspector *.:
o further questions on this item.
79-03, Setpoint drift of one of four Group I Reactor Low Pressure switches.
The switch (261-300) was found at 877 psig vs its Technical Specification limit of 880 psig.
The other three switches operated properly.
Resetting of the switch within limits was evaluated as acceptable corrective action in this case.
The inspector had no further questions on this item.
Unit 2 79-01, Static Inverter Power Supply Failure interrupting 120 volt power to RPS an ESAS Channel D components.
The power surge following a delayed transfer to the alternate source caused the failure of several components in the protective channels.
The delay was caused by the nature of the inverter failure.
The static switch will not shift when the two power supplies are out of synchronization.
The failed power supply capacitors changed inverter frequency and it was not until the inverter reached an undervoltage condition that the transfer occurred.
Frequency and voltage transients resulted in component failures in current loops in the RPS and ESAS.
Faulty components were replaced and proper performance restored.
The inspector had no further questions on this ite.
78-33, Low Cooling Water Flow,12U Emergency Diesel Generator.
This occurred during surveillance testing and was due to heat exchanger clogging with mussel shells.
Weekly inspections are made of the heat exchangers.
Those inspections did not result in the identification of any problems for a period of 17 weeks before through 3 weeks after the event.
The 12U unit was last cleaned one week before the date of this occurrence. This item (79-01-02) will be reexamined for necessity and adequacy of corrective action.
78-34, Failure of Service Water Isolation Valve 2-SW-3.2A to close.
The valve failure was due to blockage in the air solenoid valve (ASM Model 834481).
This air operated butterfly valve isolates ser, ice water supply from one of two redundant supply headers to the Turbine Building Closed Cooling Water (TBCCW) heat exchangers in the event of a safety injection actuation signal (SIAS). The isolation valve on the redundant service water supply header was operable. That header would supply the cooling water flow required for core and containment cooling through the Reactor Building Closed Cooling Water (RBCCW) heat exchangers.
Also, in the event of a SIAS signal as TBCCW loads reduce, following turbine trip, temperature control valves on the outlet of the TBCCW or heat exchangers would throttle back on service water flow diverting more to the RBCCW heat exchanger. The inspector had no further ques-tions on this item.
78-26, Non-Seismic Mounting of One Channel of Steam Generator Level Instrumentation.
The licensee's NSSS informed him that, through information supplied by an equipment vendor, two of his Steam Generator Level Transmitter Brackets were not of proper seismic design and construction.
These brackets were replaced with brackets of a seismic design and construction during the January 14-17, 1979 maintenance outage.
The installation was inspected by the NRC resident inspector and was in conformance with the PDCR package.
The inspector also witnessed liquid penetrant testing of instrument lines following the removal of a freeze seal needed for this maintenance and design change function.
During the period from determining that the brackets were non-seismic until replacement, the reactor was operated with Channel A Steam Generator low level in bypass resulting in a two out of three trip logic.
This was required by Action Statement 2, Table 3.3-1, Technical Specification 3.3.1.1.
This condition was verified by the inspector who had no further questions on this ite.
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THIS PAGE, CONTAINING 10 CFR 2.790 INFORMATION, NOT FOR PUBLIC DISCLOSURE, IS INTENTIONALLY LEFT BLAN.
THIS PAGE, CONTAINING 10 CFR 2.790 INFORMATION, NOT FOR PUBLIC DISCLOSURE, IS INTENTIONALLY LEFT BLAN.
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THIS PAGE, CONTAINING 10 CFR 2.790 INFORMATION, NOT FOR PUBLIC DISCLOSURE, IS INTENTIONALLY LEFT BLANK.