U.S. NUCLEAR REGULATORY COMMISSION-

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0FFICE OF INSPECTION AND ENFORCEMENT

Region I50-245/78-41

Report No. 50-336/78-3850-245

Docket No. 50-336DPR-21

Category CLicense No. DPR-65 Priority --

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: [ h / "1 87 77 @ 2 %_ Y 8 C/J. T. Shedidsky, Re'sident Insoector date signed'

date signed

date signed

Approved by: 0 0 A M.I'- 311./99E. 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 and50-336/78-38)Areas Inspected: Routine, onsite, regular, weekend and backshift inspectionby the resident inspector (31 hours, Unit 1; 22 hours, Unit 2). Areasinspected included: accessible portions of the Unit 1 reactor, turbine andradwaste buildings, the Unit 2 auxiliary and turbine buildings and thecondensate polisrdng facility; radiation protection; physical security;fire protection; plant operating records; and licensee event followup.Results: No items of noncompliance were identified.

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Region I Form 12'

(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 3P. Callaghan, Unit 1 Maintenance SupervisorF. Dacimo, Station QC SupervisorE. C. Farrell, Superintendent, Unit 2M. Griffin, Station Security SupervisorH. Haynes, Unit 2 Instrumentation and Control SupervisorR. Herbert, Superintendent, Unit 1J. Kelly, Unit 2 Operations SupervisorE. J. Mroczka, Superintendent, Plant ServicesJ. F. Opeka, Station SuperintendentR. Place, Unit 2 Maintenance SupervisorP. Przekop, Unit 1 Engineering SupervisorW. Romberg, Unit 1 Operations SupervisorS. Scace, Unit 2 Engineering SupervisorF. Teeple, Unit 1 Instrumentation and Control Supervisor

Other Contacts

B. Douton, Fire Chief, Goshen Fire DepartmentD. Peabody, Fire Marshall, Town of Waterford

2. Review of Plant Operations - Plant Inspections

The inspector reviewed plant operations through direct inspectionand observation during routine power operations. No unacceptableconditions were identified.

Inspections were conducted of the accessible portions of the Unit 1controi 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 theintake structure. During this inspection, activities in progress

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were normal plant power operations and surveillance testing.The inspector observed operations in the control room includingshift 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 correlationbetween channels and for confonnance with technical specifi-cation requirements. No unacceptable conditions were identified.

b. Annunciator Alanns

The inspector observed various alarm conditions that werereceived and acknowledged. These conditions were discussedwith shift. personnel, who were knowledgeable of the alarmsand actions required. During plant inspections, the inspectorobserved the condition of equipment associated with variousalarms. No unacceptable conditions were identified,

c. Shift Mannina

The operating shifts were observed to be staffed to meetthe operating requirements of Technical Specifications Section 6both to the number and types of licenses. Control room andshift manning were observed to be in conformance with theTechnical Specifications and site administrative procedures.

d. Radiation Protection Controls

Radiation protection control areas were inspected. RadiationWork Permits in use were reviewed and compliance with thosedocuments as to protective clothing and required monitoringinstruments was inspected. There were no unacceptable con-ditions identified.

e. Plant Housekeepino Conditions

Storage of material and components was observed with respectto prevention of fire and safety hazards. Plant housekeepingwas evaluated with respect to controlling the spread ofsurface and airborne contamination. There were no unacceptableconditions identified.

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f. Fire Protection / Prevention

The inspector examined the condition of selected pieces offire fighting equipment. Combustible materials were beingcontrolled and were not found near vital areas. Selectedcable penetrations were examined and their fire barrierswere found intact. Cable trays were clear of debris. Nounacceptable conditions were identified.

g. Control of Eouipment

During plant inspections, selected equipment under safety tagcontrol was examined. Equipment conditions were consistentwith information in plant control logs.

h. Instrument Channels

Instrument channel checks were reviewed on caution logs. Anindependent comparison was made of selected instruments. Nounacceptable conditions were identified.

i. Equipment Lineuos

The inspector examined the breaker positions on all switchgearand motor control centers in accessible portions of the plant.Equipment conditions were found in conformance with TechnicalSpecification and operating procedure requirements.

3. Review of Plant Operations - Loos and Records

During the inspection period, the resident inspector reviewedoperating 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 LogPlant Incident ReportsJumper and Lifted Lead LogMaintenance Requests and Job Orders n7 9f-2 e u,f g c4OSafety Tag Log oScram Report LogPlant Recorder TracesPlant Process Computer Printed OutputKey Control Log

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Several enicies in these logs were the subject of additionalreview and discussion with licensee personnel. No unacceptableconditions were identified.

Unit 1:

On October 24, 1978, it was found that the Standby Liquid Control(SLC) packing teflon follower became mushroomed, preventing packingadjustment. The pump was repacked and new teflon followers wereinstalled in accordance with Job Order 423-78. The licensee isevaluating the addition of metal followers to contain and preventthe deformation of the teflon followers.

On October 24, 1978, a leak was found in the salt water servicewater piping on the discharge of the "B" service water pump. Thepiping is located in the intake structure. The leak is locatedin a lined carbon steel pipe adjacent to a wall. Temporary repairshave been made. Final repairs are scheduled for the Spring 1979refueling outage. Nondestructive examination indicates that theleak was localized and probably due to a flaw in the protectiveliner.

On October 27, 1978, a leak occurred in the Service Water headerwhere supply is drawn for the B-Emergency Service Water keep fullline. The keep full line is a 2.5 inch line equipped with checkvalves preventing the loss of ESW. The circumstances of thisoccurrence were similar to that of October 24, 1978.

On November 15, 1978, a mechanic was sprayed with Sulphuric Acidwhile dismantling a demineralized water makeup DemineralizerRegeneration Acid Pump. The work was being performed under aMaintenance Request (MR 2982-78). The mechanic disassembled theflange on the pump suction side, drained the acid and rinsed thepiping with water. He then repeated this for the discharge flangepiping. Assuming that the pump was depressurized he removed hisface shield. As he removed the first bolt of the pump dischargehead, acid sprayed out of the disconnected discharge flange andstruck 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

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acid pump discharge check valve stuck closed, trapping pressureinside the pump. During the disassembly the check valve may havebeen jarred free and released the pump's contents into the dischargeline which had the flange coupling broken.

The licensee's corrective action included additional personnelinstruction, changes to administrative controls and proposed systemmodifications.

On November 22, 1978, while performing the functional test of theIsolation Condenser Actuation logic, the system actuated when thecondensate return containment outer isolation valve (1-IC-3) opened.The cause of the occurrence was an inadequate test procedure inthat it did not require the logic to be reset following testingof each initiating pressure switch. The immediate corrective actiontaken by the control room operators included resetting the actuationlogic and closing valve 1-IC-3. The isolation condenser shell sidewater temperature did not reach boiling. The licensee has imple-mented a procedural change to procedure 77-1-6, " Isolation CondenserActuation Instrument Functional Test," Revision 0, Change 1, datedNovember 22, 1978. This change includes verification of actuationrelay state and the resetting of actuation logic at appropriate times.

On November 22, 1978, an indicating lamp socket for the generatorlube oil DC pump failed when replacing the bulb. The gas turbinewas taken out of service during repairs which required opening thepump output breaker.

Unit 2:

On October 20, 1978, the intake structure chlorine gas monitorwas found inoperable. This unit is not required by the operatinglicense. Redundant chlorine gas monitors in the control roomventilation are required. The monitor was repaired.

On November 3, 1978, a smoke detector in zone 40, the 54 foot6 inch elevation, 4160 volt switchgear room, did not operate.Hourly surveillance was conducted. The unit was found to needadjustment of relay contacts and was repaired within the fourteenday TS action statement. On November 7, 1978, detectors in zone 38failed to alarm in the control room. Again, misadjusted relay

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contacts were the cause. The licensee inspected and adjusted all fireannunciator relay contacts. Specification 3.3.3.7, Reporting Requirements,was met.

On November 6,1978, CEA 63 position indication on the metrascopebecame erratic. The position reed switch assembly power lead wasdetermined to be making intermittent contact. The licensee incor-porated a temporary indication system using the two remaining RSPIleads and a resistance to voltage converter. This modification wasperformed in accordance with a Plant Design Change Request (PDCR 2-157-78). The modification will remain in place until the Spring1979 refuel outage.

On November 7,1978, the "C" Reactor Building Closed Cooling Water(RBCCW) System was found to be operating cooler and the ServiceWater Temperature Control valve did not respond. A sheared pinbetween the eighteen inch butterfly valve and its operator wasdiscovered. Following repairs on November 8,1978, the containmentaverage air temperature was found to be 120.10 F for readings takenat 2200 and 2300. This is above the Technical Specification limit

0 F. Itof 1200 F. The RBCCW system temperature was reduced to 80was 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 wasfound out of specification. The instrument is a Time HistoryAccelerograph measuring transverse offset. The unit was replaced.

On November 15,1978, valve 2-MS-2739, a normally open main steamline drain, was identified as having a possible defect. This typeof valve had failed at another nuclear plant when the disc separatedfrom the stem. The NRC informed NNECO after being notified thatone valve was shipped to Millstone Station. This valve will beaddressed during the Spring 1979 outage (336/78-39-02). Separationof the valve disc and stem is not of safety significance in theinstallation at Millstone.

On November 20, 1978, an apparently discarded cigarette started aminor fire in a waste container in the spent fuel pool of theauxiliary building. There was no damage to plant equipment andthere were no other flammable materials close to the container.Plant personnel were informed of this occurrence.

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On November 22, 1978, charging header flow was noted to be reduced.One of the three charging pumps was determined to have a crackedsuction check valve. The licensee added the replacement of chargingpump 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 wasbuilt with Unit 2 to prevent erosion. The as built size of the padexceeded the size on drawing 25203-11225. A Plant Design ChangeRequest (PDCR 2-172-78) was initiated to insure that the excavatedportions met design requirements. This was accomplished by backfilling with concrete to the top of existing stone after conduitinstallation and then filling with 5 inches of processed graveltamped to 100 percent compaction and blacktopped. The engineeringdesign review concluded that this design exceeded the 1,000 poundquarry stone requirement. The inspector witnessed portions of thisrepair.

On November 27, 1978, during a primary containment entry, a leakwas found on a 1.5 inch relief valve (2-SI-466) on the 2 inchSafety Injection Tank Recirculation header to the refueling waterstorage tank. Repairs were made under Maintenance Request 78-2866and Job Order R80336. The cause was apparently due to the backingoff of flange mounting nuts due to piping vibration. There were noprevious problems with this valve.

On November 30, 1978, during power operation, the control roomoperators noted that output indication of the channel B core protec-tion calculator was drifting, relative to the other channels. Theinvestigation revealed the failure of a portion of the logic powersupply which is the source of power to the core protection calcula-tor analog channels. The loss of this supply resulted in potentiallynonconservative trip points for Channel B high power, thermalmargin / low pressure and local power density instruments. The powersupply 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 thedetails of the event were clearly reported, including the accuracyof the description of cause and adequacy of corrective action. Theinspector detennined whether further infomation was required, andwhether generic implications were involved. The inspector alsoverified that the reporting requirements of Technical Specificationsand Station Administrative and operating procedures had been met,that appropriate corrective action had been taken, that the eventwas reviewed by the Plant Operations Review Committee and that thecontinued operation of the facility was conducted in conformancewith the Technical Specification limits.

Unit 1:

78-20, "A" Condensate Demineralizer capacity less than 30 poundsChloride. The licensee retracted this LER on October 11, 1978, oneday after it was reported. The circumstances concerning this eventwere reviewed.

Technical Specification 3.6.5.1 requires that a condensate demin-eralizer resin charge be regenerated before its unused capacityreaches a minimum value of 30 pounds of active chloride ions. The30 pounds of remaining capacity provides a buffer for plant shutdown,assuming 50 percent depletion of resin.

Quarterly analysis is performed on anion resins in condensatedemineralizers for salt splitting capacity. From this analysissalt splitting capacity is converted to total chloride capacity inpounds. The 30 pound minimum capacity is converted to an equivalentpercentage of bed capacity. Daily, the plant instrument readingsof integrated units of condensate conductivity are taken. Bydividing the time bctween readings the average conductivity isdetermined. This is converted to ppm chloride. By using integratingflow instruments the pounds of chloride introduced to each demineralizerare calculated. Based on that demineralizer's analyzed chloridecapacity, the percentage of lost capacity is recorded on a dailybasis.

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On October 10, 1978, an incorrect time interval for integratedconductivity was used. This resulted in a higher calculatedconductivity of 0.417 u mho (vs 0.313) and greater percent deple-tion (2.74 percent vs 2.06 percent). This error resulted in atabulated bed capacity of 31.02 percent vs the allowed capacitof 31.53 percent (equivalent to 30 pounds chloride capacity).'yUsing the correct time interval for integrated conductivity,31.7 percent bed capacity was remaining.

The licensee revised his procedures in this area to establish anadditional limit of percent capacity which is equivalent to fourpounds reserve chloride capacity above the Technical Specificationlimit of 30 pounds. This additional working margin is to preventexceeding Technical Specification limits. A better calculatorprogram has been written to use clock time and calendar days inthe daily calculations of condensate demineralizer loss per day.This will tend to eliminate mistakes in converting to inservicetimes. Condensate demineralizers in service during a plantshutdown are not used during startup but are regenerated priorto being placed back in service. The inspector reviewed the cir-cumstances concerning this event and the calculations involved.Additionally, daily logs of condensate demineralizer capacitywere reviewed for the time period of August 17 through December 6,1978. For all seven demineralizers an adequate margin to theminimum allowed capacity was maintained.

78-21, Tripping of gas turbine output breaker. On September 14,T97 E the unit emergency gas turbine generator output breakertripped during surveillance testing. The licensee's investigationrevealed that one set point, generator overspeed, would driftdownward as the environment temperature was increased. All otherset points functioned properly. The electronic control for thatsingle trip function was replaced, and the unit successfullytested. The licensee is planning a design modification to replacethe present speed switch with an improved control.

78-22, Failure of primary containment isolation valve to closefully. Following the venting of the primary containment drywell,on September 14, 1978, an isolation valve in a two inch bypassline around the eighteen inch ventilation exhaust line from thedrywell was observed to be not fully in the closed position.

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The valve is a normally closed, fail closed air operated openvalve. The licensee took manual control of the valve and placedit in the closed position. The other valves in this system, in-cluding the valves in the eighteen inch exhaust line, closednormally. Primary containment integrity was maintained. Investi-gation of the event resulted in finding some contamination of theair operator solenoid valve seats. That contamination allowedsome instrument air pressure to remain on the valve operator,preventing the valve from fully closing. (DeZurk 9009256 twoinch valve and operator and Asco 8302C527RF solencid operatedairvalve.) The dirt and scale is believed to have originatedin the carbon steel air piping. Plant operators have been blowingdown this header daily. Prior to this occurrence the air headerwas blown down twice a week. As this event had occurred on twoprevious occurrences (76-16 and 77-4), the installation of in lineair filters is being considered. The air header of concern suppliesoperating air to 1-AC-7, the isolation valve in the 18 inch exhaustline from the drywell, 1-AC-8, the isolation valve in the 18 inchcombined 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 exhaustto the Standby Gas Treatment System. All valves fail closed andare air operated open. Because of the past problem with this airoperator and since both inner and outer isolation valves aresupplied from the same air header, this is considered to '.aan openitem pending the results of the licensee's study (50-245/78-41-01).

78-23, Set point drift of one of four drywell high pressureswitches. The switch functions for RPS and group two containmentisolation logic. The switch was found to trip at 2.85 psig onOctober 11, 1978. The Technical Specifications required 2 psig.The licensee's investigation attributed the failure to dry lubricantand set point drift. The three remaining instruments operatedsatisfactorily. The subject switch was cleaned, calibrated andtested satisfactorily.

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78-24, Set point drift of one of four drywell high pressure switches.The switch functions to initiate Emergency Core Cooling Systemsequipment. The switch was found to trip at 2.3 psig on October 11,1978. The Technical Specifications required 2 psig. This switchis in an entirely separate instrument channel as that referenced inLER 78-23. Each event involved switches which were from differentmanufacturers and are used in separate instrumentation channels.The licensee is trending the results of future surveillance testingto detennine if additional action is required.

78-25, Inadvertent Initiation of the Isolation Condenser System.The Isolation Condenser initiated by the automatic opening of thecondensate return, containment outer isolation valve on October 19,1978. This valve is automatically opened when reactor pressurereaches 1085 psig (also the RP5 scram set point) and remains atthat pressure for at least 15 seconds. The reactor pressure highinstruments are in one out of two taken twice for initiation. Atthe time of this occurrence the reactor was at 90 percent power.Reactor pressure was normal at about 1028 psig. There was no RPStrip during this transient. Following initiation the system wassecured by the control room operator, who shut the condensatereturn containment outer isolation valve. The isolation condensersteam line containment isolation valves and the condensate returncontainment inner isolation valve remained open. The system remainedin standby and could be initiated by the control room operatorremotely.

The licensee's investigation resulted in finding that the systemhad experienced set point drift of two switches in one channel andthe set point drift of one switch in the second channel. Thesubject switches were all replaced during the Spring 1978 refuelingoutage. Ageing of the switches may have accounted for the setpoint drift in the conservative direction. All four of the pressureswitches were calibrated and satisfactorily tested prior to beingreturned to service.

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Technical Specificaticn section 3.5.E requires that the IsolationCondenser System be operable with reactor pressure above 90 psigand irradiated fuel in the reactor vessel. Specification 4.5.Eestablishes surveillance to verify system operability. The technicalspecifications do not address the in .trument set points for the1085 psig initiation instrumentation and 15 second channel timers.The licensee surveillance tests these instruments during the systemsimulated automatic actuation and functional system testing requiredeach 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 isolationlogic. The switch was found to trip at 2.1 psig vs the TechnicalSpecifications required 2 psig on November 6,1978. The otherswitches with this safety function tested satisfactorily. Thisswitch was of the same trip function and manufacturer as the switchreferred to in LER 78-23. This occurrence involved a switch whichwas from the opposite trip system as that in LER 78-23. The licenseecalibrated and tested the switch. As previously stated, the TechnicalSpecification trip value for this switch is less than or equal to 2psig. Containment integrity requirements specify a one pounddifferential pressure between the primary containment drywell andsuppression chamber. This usually results in the drywell pressurebeing at least 1 psig. The licensee has established a proceduralacceptance range when checking these switches of 1.7 to 1.9 psig,including the requirement to recalibrate the switch if it has beenfound to have its set point drift by one half of the allowable setpoint range or 0.05 psi for these switches.

78-27, Set point drift of one of four Reactor Low Low Water Levelinstruments. This instrument functions to initiate Emergency CoreCooling System actuation logic. The level switch was recalibratedand tested satisfactorily. The three other switches were foundoperable, with trip set points within Technical Specificationslimits 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 FiltrationSystem Charcoal filter methyl iodide removal efficiency. EventReport 78-01 reported that the methyl iodide removal efficiencyof the Enclosure Building Filtration System (EBFS) charcoalfilters was less than the Technical Specification allowable of90 percent. Samples from filter beds had a removal efficiencyof 82 to 84 percent when tested on November 29, 1978. Thelicensee had additional testing performed to determine the causeof the observed degradation. That analysis indicated the presenceof an Ester chemical on the charcoal. The licensee's conclusionwas that the most probable source of the contamination was frompainting in areas ventilated by the EBFS. The licensee informedOperations Department personnel of this occurrence. Painting iscontrolled by a Maintenance Request. These documents will bereviewed and an approval issued by the control room operationspersonnel prior to any maintenance activities. Those people willthen be aware of activities which may degrade filter performance.

The inspector verified that signs have been placed at the entranceto the Enclosure Building requiring that, prior to the use of anyprocess emitting fumes, the shift supervisor must be contacted.

'ollowing this occurrence at Unit 2, Unit 1 sampled the charcoalin the Standby Gas Treatn.ent System, as there had been a gooddeal of painting in the Reactor Building. Test results concludedthat the charcoal met the Technical Specification requirements.Additionally, the paint used at the station for large areas isnow a water based epoxy.

Samples of charcoal taken from Unit 2 on September 6, 1978, resultedin the finding that the "A" EBFS train had a methyl iodide removalefficiency of 85%, again below the specified 90%. The "B" EBFStested at 91% removal efficiency. The charcoal in the "A" bedwas replaced. Laboratory analysis indicated that the charcoalwas depleted but not contaminated. The charcoal in question wasput 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 depletedat a rate greater than expected. The licensee is replacing allthe stored charcoal for Unit 2 with newly procured activatedcharcoal.

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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 themotor windings of the steam driven auxiliary feedwater pump werewet. Water had dripped through the annulus of a removable floorplug above the pump. The water was due to personnel washing wallsof the turbine building prior to painting. When the ;aotor groundwas found, the licensee removed that auxiliary feedwater pump froma standby status. Two motor driven auxiliary feedwater pumpsremained in operable standby status.

The motor windings were dried out and a protective cover installedover the motor. Also, the floor plug was sealed at deck level.The inspector examined the area above the auxiliary feedwaterpumps. They are located in a below grade area of the turbinebuilding, near large sources of water which could be the sourceof flooding. However, the entrances to the area are protected byfloor dams. The area is located adjacent to the very large con-denser hotwell pit which would be capable of accepting a large amountof runoff from the deck above the auxiliary feedwater pumps.

78-21 and 78-27, CEA pulse counting position indication out ofservice. On August 27 and October 23, 1978, plant process computermalfunctions required removal from service. When the computer wasout of service core power distribution limits of linear heat ratewere computed using the excore detector monitoring system. Allreed switch position indicator channels were operable during theseevents.

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 radiationmonitor. The failure was due to an electrical fault in a localalarm horn causing a blown power supply fuse. Technical Specifi-cation 3.3.3.1 and Table 3.3-6 require that, if this monitor isout of service, daily grab sampling be initiated. The monitorwas returned to service with its local horn disconnected. Theinspector reviewed these actions.

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78-24, Set point drift Channel B, RPS reactor coolant low flowtrip. This trip point was found to be 91.7% of 370,000 gpm fourpump rated flow. The instrument was recalibrated :nd testedsatisfactorily. The licensee revised Surveillance Procedure240lG to require that the reactor coolant low flow trip unitset point be reset to the value specified in the procedureregardless 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 ofthe as found deviation, the as left bistable trip value is to beset to specified trio value (92.87 percent flow). During theperiod since this increase in required set point accuracy, in-strument performance has been stable. The inspector reviewed thelicensee's analysis of the set point history for these instrumentchannels and had no additional questions.

78-25, Daily Surveillance of Nuclear Power Level High RPS FunctionalUnit not performed on October 7, 1978. Technical Specification4.3.1.1.1, Table 4.3-1, items 2.a and b require that daily, whenthe reactor is above 15% of rated thermal power, Nuclear Powerlevel instruments " Nuclear Power Calibrate" potentiometers beadjusted to make the nuclear power signals agree with calorimetriccalculations and " Differential Temperature Calibrate" potentiometersbe adjusted to null the Nuclear Power differential temperaturereading. The specification allows these channel calibrations tobe suspended during physics tests described in Chapter 13 of theFSAR, authorized under the provisions of 10 CFR 50.59 or approvedby the NRC. This surveillance was omitted by operations personnelas the reactor power had been reduced to 50% from full power andit 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 SupervisoryControl Operators in writing (Memos MP-Z-1028, dated October 20,1978, Unit Superintendent to Operations Supervisor, and Memo datedOctober 27, 1978, Operations Supervisor to Control Room Operators)that this surveillance is to be performed regardless of Xenontransients, and emphasized the importance of completing requiredSurveillance Testing.

The inspector had no additional questions.

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78-26, Non Seismic Mounting Brackets associated with the ChannelA Steam Generator Level Transmitters. From information providedby the licensee's NSSS it was discovered on October 25, 1978,that the Channel "A" Steam Generator Level Transmitter whichfunctions in the RPS low water level trip had been mounted withbrackets of a non seismic design. The licensee complied withSpecification 3.3.1.1, Table 3.3-1, Action Statement 2, byconsidering that channel inoperative ud placing it in a bypassedcondition. This results in operation with a two out of three triplogic.

The inspector verified compliance with this specification atvarious times during this inspection. Corrective action will bereviewed during a future inspection (50-336/78-39-01).

78-28, Improper Setpoints, Spent Fuel Pool Ventilation RadiationMonitor. The licensee detennined, during a procedure review,that the spent fuel pool ventilation radiation monitor set pointsexceeded 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 aprocedural error. The calibration procedure required that theinstrument trip point be corrected for background. This causedthe instrument to be set above the specified value by a factorless than measured background. The calibration procedure has beenchanged. The licensee reviewed other radiation monitors listedon Table 3.3-6 and found that their set points were in conformancewith the Technical Specifications.

The inspector reviewed Surveillance Procedure 2404I, Spent FuelPool Ventilation Particulate Radiation Monitor Functional Testand SP 2404J, Spent Fuel Pool Ventilation Gaseous Radiation MonitorFunctional Test, both Revision 0, dated November 15, 1978, andaccepted by PORC in meeting 78-120. Step 7.3.2 of 2404I requiresthe particulate monitor to be set at a trip value of 6,500 +/- 1,000CPM, vs the Technical Specification limit of 13,000 CPM; step 7.3.2of 2404J requires the gaseous monitor to be set at a trip value of800 +/- 350 CPM, vs the specified limit of 835. The inspector notedthat the problem with the gaseous monitor is that it is in a highbackground area and normally indicates 750 CPM on its logarithmicscale. The licensee submitted a Technical Specification ChangeRequest to the NRC concerning these set points.

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78-29, Instrument Channel Ground. On October 25, 1978, duringsurveillance testing, a ground was identified on the "A" pressurizerpressure input to the RPS core protection calculator. That channelsupplies inputs for the Pressurizer Pressure High and ThermalMargin / Low Pressure RPS trips. The ground was traced to theprimary containment. The licensee followed Specification 3.3.1.1action statement two and placed these two trips in InstrumentChannel A in bypass. A Plant Design Change Request (PDCR 2-150-78)and a Job Order (R-80-321) were initiated to implement interimcorrective action. A unitary gain isolation amplifier has beeninstalled between the grounded portion and the rest of the instru-ment channel. The amplifier is located in control room panelC03R. Wiring to the amplifier is properly identified and enteredin the jumper records.

The inspector observed that Channel A closely tracked the threeother 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 requestedand provided by the Town of Waterford Fire Department.

During the drill the Goshen Fire Department Fire Chief, the Townof Waterford Fire Marshall, and the NRC resident inspector wereobservers.

Fire Brigades responded with full equipment. The Deluge Systemwas not engaged. Fire hoses were broken out but not charged.Affected plant equipment was not placed out of service; simulatedresponse was taken.

In summary: the Fire Brigade arrived at the scene within two (2)minutes of the drill commencement, access was achieved and outsideassistance requested in five (5) minutes, the unit 1 (backup) firebrigade was requested in twelve (12) minutes. The first fire truckarrived 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;-

A malfunction in a vital area security door impeded access-

to the area during the simulated emergency;

Evaluations will continue on upgrading the paging system-

(progress has been made in this area since the drill);

One smoke removal fan does not have an explosion proof fitting;-~

Fire brigade communications have been a problem (radios have-

been added to fire equipment lockers since the drill);

Delays were experienced in allowing the second fire truck-

through the security control point;

Directions should be provided on the access road to members-

of the Town Fire Department as they arrive.

The licensee has begun to address these observations and is effectingan 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 installationprocedures associated with the replacement of the irradiated fuelstorage pool fuel storage racks. These original storage racksare being replaced with a new design allowing a high fuel densityin the pool. This is accomplished through the use of boron-carbideplates in the rack structure.

This plant modification has been reviewed and approved by thelicensee's safety coninittees and has been accepted by the NRC (NRR).

The inspector observed the work associated with the removal ofthe original fuel racks and the cleanup of the storage pool.Compliance with Radiation Work Permit requirements and healthphysics practices was verified.

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The inspector observed the site fabrication operations and theinstallation of the first high density storage racks. The licenseehad perfonned neutron " blackness" tests of the new storage racks.These test results were discussed.

No noncompliances or unacceptable conditions were identified inthe review of the preceding..

7. Fire Barriers

On June 6, 1978, during a site visit for an evaluation of the fireprotection program, it was noted that there were unsealed penetrationsin fire barriers. Penetrations in the ceiling of the emergencydiesel generator room were unsealed. They comunicate with thediesel day tank rooms and an area outside the day tank roomscomon to both diesel generators.

The inspector verified that these penetrations had been sealed withmaterials 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 modificationin a letter to NRR dated March 7,1978. He intends to design andengineer this feature and install it during the 1979 refuelingoutage. The inspector had no additional questions at this time.

9. Reactor System Decontamination (Unit 1)

Information available to the inspector indicated that chemicaldecontamination solutions have not been used. The inspector hadno additional questions at this time.

10. Failures of 120VDC Relays in Safety Related Motor Control CentersUnit 1

The inspector discussed a problem which had occurred at anotherpower reactor concerning General Electric type IC 2820A200-A3-Erelays with coil number 393B-209-GE. These relays are not usedin 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 anotherpower reactor concerning the lack of seismic locking springs onplug-in type Agastat Relays type GPBC 757 and GPDG. These relaysare 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 anotherpower reactor concerning exceptionally long scram times. Theselong scram times were due to the presence of water in the stationinstrument air header. Information available to the inspectorindicated 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 SystemUnit 2

The licensee has reviewed the vendor's documents which proposed analternate method of locking the LPSI pump impellers. This wouldinvolve an impeller keyed to a washer and the washer locked to theimpeller nut. The original method was to torque a jamb nut to 215ft-lb then torque a cap nut to 215 ft-lb. The vendor is con #ieentthat this original method of locking the impeller is satisfactory.He has supplied an alternate method as one power plant experiencedloosening of the impeller lock nut during preoperational testing.The licensee has discussed the problem with his vendor and concludedthat it is valid to continue to use the original locking method, asthe installation practices on the failed impeller locking devicesare in question.

The inspector had no additional questions on this item.

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16. Exit Interview

At periodic intervals during the course of this inspection,meetings were held with senior facility management to discussinspection scope and findings.

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