IR 05000245/1978041
| ML19270G031 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/20/1979 |
| From: | Mccabe E, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19270G030 | List: |
| References | |
| 50-245-78-41, 50-336-78-38, NUDOCS 7906010047 | |
| Download: ML19270G031 (24) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
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0FFICE OF INSPECTION AND ENFORCEMENT Region I 50-245/78-41 Report No.
50-336/78-38 50-245 Docket No.
50-336 DPR-21 Category C
License No.
DPR-65 Priority
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Licensee:
Northeast Nuclear Energy Company P. O. Box 270 Hartford, Connecticut 06101 Facility Name:
Millstone Nuclear Power Station, Units 1 and 2 Inspection at:
Waterford, Connecticut Inspection conducted:
November 6 - December 7,1978 Inspectors:
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"1 87 77 @ 2
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J. T. Shedidsky, Re'sident Insoector date signed'
date signed date signed Approved by:
0 0 A M.I'-
311./99 E. C. McCabe, Chief, Reactor Projects date signed Section No. 2, R0&NS Branch Inspection Summary:
Inspection on November 6 - December 7,1978 (Combined Reoort 50-245/78-41 and 50-336/78-38)
Areas Inspected:
Routine, onsite, regular, weekend and backshift inspection by the resident inspector (31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />, Unit 1; 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br />, Unit 2).
Areas inspected included: accessible portions of the Unit 1 reactor, turbine and radwaste buildings, the Unit 2 auxiliary and turbine buildings and the condensate polisrdng facility; radiation protection; physical security; fire protection; plant operating records; and licensee event followup.
Results:
No items of noncompliance were identified.
f~
m 3 c"'t 3 ccd
\\g Region I Form 12
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(Rev. April 77)
790601009/ :
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DETAILS 1.
Persons Contacted The personnel listed below were among those contacted:
Licensee Contacts 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 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 Other Contacts B. Douton, Fire Chief, Goshen Fire Department D. Peabody, Fire Marshall, Town of Waterford 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 controi room, reactor, turbine and radioactive waste buildings, the intake structure, and the Unit 2 control room, auxiliary, and turbine buildings, the condensate polishing area and the intake structure.
During this inspection, activities in progress 2263 244
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were normal plant power operations and surveillance testing.
The inspector observed operations in the control room including shift turnovers, back shift 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 confonnance with technical specifi-cation requirements.
No unacceptable conditions were identified.
b.
Annunciator Alanns 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 equipment associated with various alarms.
No unacceptable conditions were identified, c.
Shift Mannina The operating shifts were observed to be staffed to meet the operating requirements of Technical Specifications Section 6 both to the number and types of licenses.
Control room and shift manning were observed to be in conformance with the 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 con-ditions identified.
e.
Plant Housekeepino Conditions 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 identified.
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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.
No unacceptable conditions were identified.
g.
Control of Eouipment 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 on caution logs. An independent comparison was made of selected instruments.
No unacceptable conditions were identified.
i.
Equipment Lineuos The inspector examined the breaker positions on all switchgear and motor control centers in accessible portions of the plant.
Equipment conditions were found in conformance with Technical Specification and operating procedure requirements.
3.
Review of Plant Operations - Loos 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 Admin-istrative procedure requirements.
Included in the review were:
Shift Supervisor's Log Plant Incident Reports Jumper and Lifted Lead Log Maintenance Requests and Job Orders n7 9f-2 e u,f g c4O Safety Tag Log o
Scram Report Log Plant Recorder Traces Plant Process Computer Printed Output Key Control Log
Several enicies in these logs were the subject of additional review and discussion with licensee personnel.
No unacceptable conditions were identified.
Unit 1:
On October 24, 1978, it was found that the Standby Liquid Control (SLC) packing teflon follower became mushroomed, preventing packing adjustment. The pump was repacked and new teflon followers were installed in accordance with Job Order 423-78.
The licensee is evaluating the addition of metal followers to contain and prevent the deformation of the teflon followers.
On October 24, 1978, a leak was found in the salt water service water piping on the discharge of the "B" service water pump.
The piping is located in the intake structure. The leak is located in a lined carbon steel pipe adjacent to a wall. Temporary repairs have been made.
Final repairs are scheduled for the Spring 1979 refueling outage.
Nondestructive examination indicates that the leak was localized and probably due to a flaw in the protective liner.
On October 27, 1978, a leak occurred in the Service Water header where supply is drawn for the B-Emergency Service Water keep full line. The keep full line is a 2.5 inch line equipped with check valves preventing the loss of ESW.
The circumstances of this occurrence were similar to that of October 24, 1978.
On November 15, 1978, a mechanic was sprayed with Sulphuric Acid while dismantling a demineralized water makeup Demineralizer Regeneration Acid Pump. The work was being performed under a Maintenance Request (MR 2982-78).
The mechanic disassembled the flange on the pump suction side, drained the acid and rinsed the piping with water. He then repeated this for the discharge flange piping.
Assuming that the pump was depressurized he removed his face shield. As he removed the first bolt of the pump discharge head, acid sprayed out of the disconnected discharge flange and struck him in the face. The mechanic used a local eye wash / shower
'and received medical attention on site and at the hospital.
An investigation into che cause of the incident concluded that the 2263 247
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acid pump discharge check valve stuck closed, trapping pressure inside the pump.
During the disassembly the check valve may have been jarred free and released the pump's contents into the discharge line which had the flange coupling broken.
The licensee's corrective action included additional personnel instruction, changes to administrative controls and proposed system modifications.
On November 22, 1978, while performing the functional test of the Isolation Condenser Actuation logic, the system actuated when the condensate return containment outer isolation valve (1-IC-3) opened.
The cause of the occurrence was an inadequate test procedure in that it did not require the logic to be reset following testing of each initiating pressure switch.
The immediate corrective action taken by the control room operators included resetting the actuation logic and closing valve 1-IC-3.
The isolation condenser shell side water temperature did not reach boiling. The licensee has imple-mented a procedural change to procedure 77-1-6, " Isolation Condenser Actuation Instrument Functional Test," Revision 0, Change 1, dated November 22, 1978. This change includes verification of actuation relay state and the resetting of actuation logic at appropriate times.
On November 22, 1978, an indicating lamp socket for the generator lube oil DC pump failed when replacing the bulb. The gas turbine was taken out of service during repairs which required opening the pump output breaker.
Unit 2:
On October 20, 1978, the intake structure chlorine gas monitor was found inoperable. This unit is not required by the operating license.
Redundant chlorine gas monitors in the control room ventilation are required. The monitor was repaired.
On November 3, 1978, a smoke detector in zone 40, the 54 foot 6 inch elevation, 4160 volt switchgear room, did not operate.
Hourly surveillance was conducted.
The unit was found to need adjustment of relay contacts and was repaired within the fourteen day TS action statement.
On November 7, 1978, detectors in zone 38 failed to alarm in the control room.
Again, misadjusted relay 2268 248
contacts were the cause.
The licensee inspected and adjusted all fire annunciator relay contacts.
Specification 3.3.3.7, Reporting Requirements, was met.
On November 6,1978, CEA 63 position indication on the metrascope became erratic.
The position reed switch assembly power lead was determined to be making intermittent contact.
The licensee incor-porated a temporary indication system using the two remaining RSPI leads and a resistance to voltage converter.
This modification was performed in accordance with a Plant Design Change Request (PDCR 2-157-78). The modification will remain in place until the Spring 1979 refuel outage.
On November 7,1978, the "C" Reactor Building Closed Cooling Water (RBCCW) System was found to be operating cooler and the Service Water Temperature Control valve did not respond.
A sheared pin between the eighteen inch butterfly valve and its operator was discovered.
Following repairs on November 8,1978, the containment average air temperature was found to be 120.10 F for readings taken at 2200 and 2300.
This is above the Technical Specification limit 0 F.
It of 1200 F.
The RBCCW system temperature was reduced to 80 was discovered that, while troubleshooting the system, the tempera-ture controller was set high.
After the shear pin was replaced, the controller was not readjusted and RBCCW temperature increased.
On November 14, 1978, the intake structure seismic instrument was found out of specification.
The instrument is a Time History Accelerograph measuring transverse offset.
The unit was replaced.
On November 15,1978, valve 2-MS-2739, a normally open main steam line drain, was identified as having a possible defect.
This type of valve had failed at another nuclear plant when the disc separated from the stem.
The NRC informed NNECO after being notified that one valve was shipped to Millstone Station.
This valve will be addressed during the Spring 1979 outage (336/78-39-02).
Separation of the valve disc and stem is not of safety significance in the installation at Millstone.
On November 20, 1978, an apparently discarded cigarette started a minor fire in a waste container in the spent fuel pool of the auxiliary building.
There was no damage to plant equipment and there were no other flammable materials close to the container.
Plant personnel were informed of this occurrence.
22b3 2bh
On November 22, 1978, charging header flow was noted to be reduced.
One of the three charging pumps was determined to have a cracked suction check valve.
The licensee added the replacement of charging pump check valves to the Preventive Maintenance Program.
During the trenching construction for security system modifications, part of the as built Scour Protection Pad was removed.
The pad was built with Unit 2 to prevent erosion.
The as built size of the pad exceeded the size on drawing 25203-11225.
A Plant Design Change Request (PDCR 2-172-78) was initiated to insure that the excavated portions met design requirements.
This was accomplished by back filling with concrete to the top of existing stone after conduit installation and then filling with 5 inches of processed gravel tamped to 100 percent compaction and blacktopped.
The engineering design review concluded that this design exceeded the 1,000 pound quarry stone requirement.
The inspector witnessed portions of this repair.
On November 27, 1978, during a primary containment entry, a leak was found on a 1.5 inch relief valve (2-SI-466) on the 2 inch Safety Injection Tank Recirculation header to the refueling water storage tank.
Repairs were made under Maintenance Request 78-2866 and Job Order R80336.
The cause was apparently due to the backing off of flange mounting nuts due to piping vibration.
There were no previous problems with this valve.
On November 30, 1978, during power operation, the control room operators noted that output indication of the channel B core protec-tion calculator was drifting, relative to the other channels.
The investigation revealed the failure of a portion of the logic power supply which is the source of power to the core protection calcula-tor analog channels.
The loss of this supply resulted in potentially nonconservative trip points for Channel B high power, thermal margin / low pressure and local power density instruments.
The power supply was replaced under a Job Order (R80339).
No noncompliances were identified in the review of the preceding.
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4.
Licensee Event Reports (LER's)
The inspector reviewed the following LER's to verify that the details of the event were clearly reported, including the accuracy of the description of cause and adequacy of corrective action.
The inspector detennined whether further infomation 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 in conformance with the Technical Specification limits.
Unit 1:
78-20, "A" Condensate Demineralizer capacity less than 30 pounds Chloride. The licensee retracted this LER on October 11, 1978, one day after it was reported.
The circumstances concerning this event were reviewed.
Technical Specification 3.6.5.1 requires that a condensate demin-eralizer resin charge be regenerated before its unused capacity reaches a minimum value of 30 pounds of active chloride ions.
The 30 pounds of remaining capacity provides a buffer for plant shutdown, assuming 50 percent depletion of resin.
Quarterly analysis is performed on anion resins in condensate demineralizers for salt splitting capacity.
From this analysis salt splitting capacity is converted to total chloride capacity in pounds.
The 30 pound minimum capacity is converted to an equivalent percentage of bed capacity.
Daily, the plant instrument readings of integrated units of condensate conductivity are taken.
By dividing the time bctween readings the average conductivity is determined.
This is converted to ppm chloride.
By using integrating flow instruments the pounds of chloride introduced to each demineralizer are calculated.
Based on that demineralizer's analyzed chloride capacity, the percentage of lost capacity is recorded on a daily basis.
2M B 251
On October 10, 1978, an incorrect time interval for integrated conductivity was used. This resulted in a higher calculated conductivity of 0.417 u mho (vs 0.313) and greater percent deple-tion (2.74 percent vs 2.06 percent).
This error resulted in a tabulated bed capacity of 31.02 percent vs the allowed capacit of 31.53 percent (equivalent to 30 pounds chloride capacity).'y Using the correct time interval for integrated conductivity, 31.7 percent bed capacity was remaining.
The licensee revised his procedures in this area to establish an additional limit of percent capacity which is equivalent to four pounds reserve chloride capacity above the Technical Specification limit of 30 pounds. This additional working margin is to prevent exceeding Technical Specification limits.
A better calculator program has been written to use clock time and calendar days in the daily calculations of condensate demineralizer loss per day.
This will tend to eliminate mistakes in converting to inservice times. Condensate demineralizers in service during a plant shutdown are not used during startup but are regenerated prior to being placed back in service. The inspector reviewed the cir-cumstances concerning this event and the calculations involved.
Additionally, daily logs of condensate demineralizer capacity were reviewed for the time period of August 17 through December 6, 1978.
For all seven demineralizers an adequate margin to the minimum allowed capacity was maintained.
78-21, Tripping of gas turbine output breaker.
On September 14, T97 E the unit emergency gas turbine generator output breaker tripped during surveillance testing. The licensee's investigation revealed that one set point, generator overspeed, would drift downward as the environment temperature was increased.
All other set points functioned properly. The electronic control for that single trip function was replaced, and the unit successfully tested. The licensee is planning a design modification to replace the present speed switch with an improved control.
78-22, Failure of primary containment isolation valve to close fully.
Following the venting of the primary containment drywell, on September 14, 1978, an isolation valve in a two inch bypass line around the eighteen inch ventilation exhaust line from the drywell was observed to be not fully in the closed position.
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The valve is a normally closed, fail closed air operated open valve. The licensee took manual control of the valve and placed it in the closed position. The other valves in this system, in-cluding the valves in the eighteen inch exhaust line, closed normally.
Primary containment integrity was maintained.
Investi-gation of the event resulted in finding some contamination of the air operator solenoid valve seats.
That contamination allowed some instrument air pressure to remain on the valve operator, preventing the valve from fully closing.
(DeZurk 9009256 two inch valve and operator and Asco 8302C527RF solencid operated airvalve.) The dirt and scale is believed to have originated in the carbon steel air piping.
Plant operators have been blowing down this header daily.
Prior to this occurrence the air header was blown down twice a week. As this event had occurred on two previous occurrences (76-16 and 77-4), the installation of in line air filters is being considered.
The air header of concern supplies operating air to 1-AC-7, the isolation valve in the 18 inch exhaust line from the drywell, 1-AC-8, the isolation valve in the 18 inch combined torus, drywell exhaust to the ventilation stack, 1-AC-9, the two inch bypass valve, subject of this event, and 1-AC-10, the isolation valve in the 12 inch combined torus, drywell exhaust to the Standby Gas Treatment System.
All valves fail closed and are air operated open. Because of the past problem with this air operator and since both inner and outer isolation valves are supplied from the same air header, this is considered to '.aan open item pending the results of the licensee's study (50-245/78-41-01).
78-23, Set point drift of one of four drywell high pressure switches. The switch functions for RPS and group two containment isolation logic. The switch was found to trip at 2.85 psig on October 11, 1978.
The Technical Specifications required 2 psig.
The licensee's investigation attributed the failure to dry lubricant and set point drift. The three remaining instruments operated satisfactorily. The subject switch was cleaned, calibrated and tested satisfactorily.
2?68 253
78-24, Set point drift of one of four drywell high pressure switches.
The switch functions to initiate Emergency Core Cooling Systems equipment.
The switch was found to trip at 2.3 psig on October 11, 1978. The Technical Specifications required 2 psig.
This switch is in an entirely separate instrument channel as that referenced in LER 78-23.
Each event involved switches which were from different manufacturers and are used in separate instrumentation channels.
The licensee is trending the results of future surveillance testing to detennine if additional action is required.
78-25, Inadvertent Initiation of the Isolation Condenser System.
The Isolation Condenser initiated by the automatic opening of the condensate return, containment outer isolation valve on October 19, 1978. This valve is automatically opened when reactor pressure reaches 1085 psig (also the RP5 scram set point) and remains at that pressure for at least 15 seconds.
The reactor pressure high instruments are in one out of two taken twice for initiation.
At the time of this occurrence the reactor was at 90 percent power.
Reactor pressure was normal at about 1028 psig.
There was no RPS trip during this transient.
Following initiation the system was secured by the control room operator, who shut the condensate return containment outer isolation valve.
The isolation condenser steam line containment isolation valves and the condensate return containment inner isolation valve remained open.
The system remained in standby and could be initiated by the control room operator remotely.
The licensee's investigation resulted in finding that the system had experienced set point drift of two switches in one channel and the set point drift of one switch in the second channel.
The subject switches were all replaced during the Spring 1978 refueling outage.
Ageing of the switches may have accounted for the set point drift in the conservative direction. All four of the pressure switches were calibrated and satisfactorily tested prior to being returned to service.
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Technical Specificaticn section 3.5.E requires that the Isolation Condenser System be operable with reactor pressure above 90 psig and irradiated fuel in the reactor vessel.
Specification 4.5.E establishes surveillance to verify system operability.
The technical specifications do not address the in.trument set points for the 1085 psig initiation instrumentation and 15 second channel timers.
The licensee surveillance tests these instruments during the system simulated automatic actuation and functional system testing required each refueling outage and following major system repairs.
78-26, Set point drift of one of four drywell high pressure switches.
The switch functions for RpS and group two containment isolation logic.
The switch was found to trip at 2.1 psig vs the Technical Specifications required 2 psig on November 6,1978.
The other switches with this safety function tested satisfactorily.
This switch was of the same trip function and manufacturer as the switch referred to in LER 78-23.
This occurrence involved a switch which was from the opposite trip system as that in LER 78-23.
The licensee calibrated and tested the switch.
As previously stated, the Technical Specification trip value for this switch is less than or equal to 2 psig.
Containment integrity requirements specify a one pound differential pressure between the primary containment drywell and suppression chamber.
This usually results in the drywell pressure being at least 1 psig.
The licensee has established a procedural acceptance range when checking these switches of 1.7 to 1.9 psig, including the requirement to recalibrate the switch if it has been found to have its set point drift by one half of the allowable set point range or 0.05 psi for these switches.
78-27, Set point drift of one of four Reactor Low Low Water Level instruments. This instrument functions to initiate Emergency Core Cooling System actuation logic.
The level switch was recalibrated and tested satisfactorily.
The three other switches were found operable, with trip set points within Technical Specifications limits of 79 to 83 inches above the top of active fuel.
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Unit 2:
78-01, Updated Report and 78-22, Enclosure Building Filtration System Charcoal filter methyl iodide removal efficiency.
Event Report 78-01 reported that the methyl iodide removal efficiency of the Enclosure Building Filtration System (EBFS) charcoal filters was less than the Technical Specification allowable of 90 percent.
Samples from filter beds had a removal efficiency of 82 to 84 percent when tested on November 29, 1978. The licensee had additional testing performed to determine the cause of the observed degradation. That analysis indicated the presence of an Ester chemical on the charcoal.
The licensee's conclusion was that the most probable source of the contamination was from painting in areas ventilated by the EBFS. The licensee informed Operations Department personnel of this occurrence.
Painting is controlled by a Maintenance Request. These documents will be reviewed and an approval issued by the control room operations personnel prior to any maintenance activities. Those people will then be aware of activities which may degrade filter performance.
The inspector verified that signs have been placed at the entrance to the Enclosure Building requiring that, prior to the use of any process emitting fumes, the shift supervisor must be contacted.
'ollowing this occurrence at Unit 2, Unit 1 sampled the charcoal in the Standby Gas Treatn.ent System, as there had been a good deal of painting in the Reactor Building. Test results concluded that the charcoal met the Technical Specification requirements.
Additionally, the paint used at the station for large areas is now a water based epoxy.
Samples of charcoal taken from Unit 2 on September 6, 1978, resulted in the finding that the "A" EBFS train had a methyl iodide removal efficiency of 85%, again below the specified 90%.
The "B" EBFS tested at 91% removal efficiency. The charcoal in the "A" bed was replaced.
Laboratory analysis indicated that the charcoal was depleted but not contaminated. The charcoal in question was put in service in January 1978.
However, records indicate that it was stored in sealed trays in the warehouse for the last four years.
It is the licensee's conclusion that the older charcoal depleted at a rate greater than expected.
The licensee is replacing all the stored charcoal for Unit 2 with newly procured activated charcoal.
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78-20, Steam Driven Auxiliary Feedwater pump.
On August 8, 1978, a ground on the "B" station battery led to the discovery that the motor windings of the steam driven auxiliary feedwater pump were wet. Water had dripped through the annulus of a removable floor plug above the pump. The water was due to personnel washing walls of the turbine building prior to painting. When the ;aotor ground was found, the licensee removed that auxiliary feedwater pump from a standby status.
Two motor driven auxiliary feedwater pumps remained in operable standby status.
The motor windings were dried out and a protective cover installed over the motor. Also, the floor plug was sealed at deck level.
The inspector examined the area above the auxiliary feedwater pumps. They are located in a below grade area of the turbine building, near large sources of water which could be the source of flooding. However, the entrances to the area are protected by floor dams. The area is located adjacent to the very large con-denser hotwell pit which would be capable of accepting a large amount of runoff from the deck above the auxiliary feedwater pumps.
78-21 and 78-27, CEA pulse counting position indication out of service.
On August 27 and October 23, 1978, plant process computer malfunctions required removal from service. When the computer was out of service core power distribution limits of linear heat rate were computed using the excore detector monitoring system.
All reed switch position indicator channels were operable during these events.
The inspector reviewed log and plant records concerning these events.
Plant operation was in compliance with specification 3.1.3.3.d.
78-23, Failed spent fuel storage ventilation. gaseous radiation monitor.
The failure was due to an electrical fault in a local alarm horn causing a blown power supply fuse. Technical Specifi-cation 3.3.3.1 and Table 3.3-6 require that, if this monitor is out of service, daily grab sampling be initiated.
The monitor was returned to service with its local horn disconnected.
The inspector reviewed these actions.
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78-24, Set point drift Channel B, RPS reactor coolant low flow trip. This trip point was found to be 91.7% of 370,000 gpm four pump rated flow. The instrument was recalibrated :nd tested satisfactorily. The licensee revised Surveillance Procedure 240lG to require that the reactor coolant low flow trip unit set point be reset to the value specified in the procedure regardless of the deviation from the procedure required set point.
The inspector reviewed SP240lG, RPS Sistable Trip Test, Revision 0, dated February 24, 1978, and approved by PORC at meeting 78-96.
A change has been made to I&C form 240lG-1 page 2, Revision 1, dated November 8, 1978, step 7.2.7, requiring that, regardless of the as found deviation, the as left bistable trip value is to be set to specified trio value (92.87 percent flow).
During the period since this increase in required set point accuracy, in-strument performance has been stable.
The inspector reviewed the licensee's analysis of the set point history for these instrument channels and had no additional questions.
78-25, Daily Surveillance of Nuclear Power Level High RPS Functional Unit not performed on October 7, 1978.
Technical Specification 4.3.1.1.1, Table 4.3-1, items 2.a and b require that daily, when the reactor is above 15% of rated thermal power, Nuclear Power level instruments " Nuclear Power Calibrate" potentiometers be adjusted to make the nuclear power signals agree with calorimetric calculations and " Differential Temperature Calibrate" potentiometers be adjusted to null the Nuclear Power differential temperature reading. The specification allows these channel calibrations to be suspended during physics tests described in Chapter 13 of the FSAR, authorized under the provisions of 10 CFR 50.59 or approved by the NRC. This surveillance was omitted by operations personnel as the reactor power had been reduced to 50% from full power and it was assumed that performance of a calibration of nuclear instru-ments during a Xenon transient would result in an improper calibration.
Plant management ir,structed all Shift Supervisors and Supervisory Control Operators in writing (Memos MP-Z-1028, dated October 20, 1978, Unit Superintendent to Operations Supervisor, and Memo dated October 27, 1978, Operations Supervisor to Control Room Operators)
that this surveillance is to be performed regardless of Xenon transients, and emphasized the importance of completing required Surveillance Testing.
The inspector had no additional questions.
22GB 258
78-26, Non Seismic Mounting Brackets associated with the Channel A Steam Generator Level Transmitters.
From information provided by the licensee's NSSS it was discovered on October 25, 1978, that the Channel "A" Steam Generator Level Transmitter which functions in the RPS low water level trip had been mounted with brackets of a non seismic design. The licensee complied with Specification 3.3.1.1, Table 3.3-1, Action Statement 2, by considering that channel inoperative ud placing it in a bypassed condition. This results in operation with a two out of three trip logic.
The inspector verified compliance with this specification at various times during this inspection.
Corrective action will be reviewed during a future inspection (50-336/78-39-01).
78-28, Improper Setpoints, Spent Fuel Pool Ventilation Radiation Monitor.
The licensee detennined, during a procedure review, that the spent fuel pool ventilation radiation monitor set points exceeded the set points stated in Technical Specification 3.3.3.1, Table 3.3-6, Instruments 2.c and 2.d.
This occurred due to a procedural error. The calibration procedure required that the instrument trip point be corrected for background.
This caused the instrument to be set above the specified value by a factor less than measured background.
The calibration procedure has been changed.
The licensee reviewed other radiation monitors listed on Table 3.3-6 and found that their set points were in conformance with the Technical Specifications.
The inspector reviewed Surveillance Procedure 2404I, Spent Fuel Pool Ventilation Particulate Radiation Monitor Functional Test and SP 2404J, Spent Fuel Pool Ventilation Gaseous Radiation Monitor Functional Test, both Revision 0, dated November 15, 1978, and accepted by PORC in meeting 78-120.
Step 7.3.2 of 2404I requires the particulate monitor to be set at a trip value of 6,500 +/- 1,000 CPM, vs the Technical Specification limit of 13,000 CPM; step 7.3.2 of 2404J requires the gaseous monitor to be set at a trip value of 800 +/- 350 CPM, vs the specified limit of 835.
The inspector noted that the problem with the gaseous monitor is that it is in a high background area and normally indicates 750 CPM on its logarithmic scale.
The licensee submitted a Technical Specification Change Request to the NRC concerning these set points.
2263 259
78-29, Instrument Channel Ground. On October 25, 1978, during surveillance testing, a ground was identified on the "A" pressurizer pressure input to the RPS core protection calculator.
That channel supplies inputs for the Pressurizer Pressure High and Thermal Margin / Low Pressure RPS trips.
The ground was traced to the primary containment. The licensee followed Specification 3.3.1.1 action statement two and placed these two trips in Instrument Channel A in bypass. A Plant Design Change Request (PDCR 2-150-78)
and a Job Order (R-80-321) were initiated to implement interim corrective action. A unitary gain isolation amplifier has been installed between the grounded portion and the rest of the instru-ment channel. The amplifier is located in control room panel C03R. Wiring to the amplifier is properly identified and entered in the jumper records.
The inspector observed that Channel A closely tracked the three other safety channels, and two control channels, A-2275 psi, B-2275, C-2270, D-2265, X-2270, and Y-2270.
5.
Fire Protection Training An unannounced fire drill was conducted on November 28, 1978.
The drill simulated a crankcase explosion and fire of the Unit 2
"A" Emergency Diesel Generator. Outside assistance was requested and provided by the Town of Waterford Fire Department.
During the drill the Goshen Fire Department Fire Chief, the Town of Waterford Fire Marshall, and the NRC resident inspector were observers.
Fire Brigades responded with full equipment. The Deluge System was not engaged.
Fire hoses were broken out but not charged.
Affected plant equipment was not placed out of service; simulated response was taken.
In summary:
the Fire Brigade arrived at the scene within two (2)
minutes of the drill commencement, access was achieved and outside assistance requested in five (5) minutes, the unit 1 (backup) fire brigade was requested in twelve (12) minutes. The first fire truck arrived at the scene in sixteen (16) minutes, the second in twenty (20) minutes and the third in twenty six (26) minutes.
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The licensee critiqued the drill with participants and observers.
Included in those observations were that:
There was only one access to the station;
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A malfunction in a vital area security door impeded access
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to the area during the simulated emergency; Evaluations will continue on upgrading the paging system
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(progress has been made in this area since the drill);
One smoke removal fan does not have an explosion proof fitting;
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Fire brigade communications have been a problem (radios have
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been added to fire equipment lockers since the drill);
Delays were experienced in allowing the second fire truck
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through the security control point; Directions should be provided on the access road to members
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of the Town Fire Department as they arrive.
The licensee has begun to address these observations and is effecting an upgrade of the fire protection program. This area will be re-examined during regular review of the fire protective measures.
6.
Plant Modifications - Fuel Storage Racks (Unit 1)
The inspector reviewed the engineering analysis and installation procedures associated with the replacement of the irradiated fuel storage pool fuel storage racks.
These original storage racks are being replaced with a new design allowing a high fuel density in the pool.
This is accomplished through the use of boron-carbide plates in the rack structure.
This plant modification has been reviewed and approved by the licensee's safety coninittees and has been accepted by the NRC (NRR).
The inspector observed the work associated with the removal of the original fuel racks and the cleanup of the storage pool.
Compliance with Radiation Work Permit requirements and health physics practices was verified.
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The inspector observed the site fabrication operations and the installation of the first high density storage racks. The licensee had perfonned neutron " blackness" tests of the new storage racks.
These test results were discussed.
No noncompliances or unacceptable conditions were identified in the review of the preceding..
7.
Fire Barriers On June 6, 1978, during a site visit for an evaluation of the fire protection program, it was noted that there were unsealed penetrations in fire barriers.
Penetrations in the ceiling of the emergency diesel generator room were unsealed.
They comunicate with the diesel day tank rooms and an area outside the day tank rooms comon to both diesel generators.
The inspector verified that these penetrations had been sealed with materials specifically evaluated by the licensee for that applica-tion.
The inspector had no additional questions on this item.
8.
Feedwater Pumo Trip on Reactor Vessel Hiah Water Level (Unit 1)
The licensee has addressed his position concerning this modification in a letter to NRR dated March 7,1978. He intends to design and engineer this feature and install it during the 1979 refueling outage. The inspector had no additional questions at this time.
9.
Reactor System Decontamination (Unit 1)
Information available to the inspector indicated that chemical decontamination solutions have not been used. The inspector had no additional questions at this time.
10.
Failures of 120VDC Relays in Safety Related Motor Control Centers Unit 1 The inspector discussed a problem which had occurred at another power reactor concerning General Electric type IC 2820A200-A3-E relays with coil number 393B-209-GE.
These relays are not used in safety related Motor Control Centers at Unit 1.
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11. Agastat Relay Seismic Locking Sprinas (Unit 1)
The inspector discussed a problem which had occurred at another power reactor concerning the lack of seismic locking springs on plug-in type Agastat Relays type GPBC 757 and GPDG.
These relays are not used in safety related circuits at Unit 1.
12. Slow Control Rod Scram Times (Unit 1)
The inspector discussed a problem which had occurred at another power reactor concerning exceptionally long scram times.
These long scram times were due to the presence of water in the station instrument air header.
Information available to the inspector indicated that this control rod problem has not occurred at Unit 1.
The plant has not had water problems with the instrument air headers.
The inspector had no additional questions on this item.
13.
Low Pressure Safety Injection (LPSI) Pumo Imoeller Locking System Unit 2 The licensee has reviewed the vendor's documents which proposed an alternate method of locking the LPSI pump impellers.
This would involve an impeller keyed to a washer and the washer locked to the impeller nut. The original method was to torque a jamb nut to 215 ft-lb then torque a cap nut to 215 ft-lb.
The vendor is con #ieent that this original method of locking the impeller is satisfactory.
He has supplied an alternate method as one power plant experienced loosening of the impeller lock nut during preoperational testing.
The licensee has discussed the problem with his vendor and concluded that it is valid to continue to use the original locking method, as the installation practices on the failed impeller locking devices are in question.
The inspector had no additional questions on this item.
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THIS PAGE, CONTAINING 10 CFR 2.790 INFORMATION, NOT FOR PUBLIC DISCLOSURE, IS INTENTIONALLY LEFT BLANK.
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16.
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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