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U.S. NUCLEAR REGULATORY COMMISSIONRegion I

50-245/85-02Report Nos. 50-336/85-03

50-245 DPR-21Docket Nos. 50-336 License Nos. OPR-65 Category C

Licensee: Northeast Nuclear Energy Company

Post Office Box 270

liertford, Connecticut 06141-0270

Facility: Millstone Nuclear Power Station

Inspection At- Millstone Unit 1 & 2

Inspection D.ites: January 14, 1985 through February 24, 1985

Inspectors: CL M Q , f.-, 11 u,lerJohn T. Shedlosky, Seriior Resident Inspector Date

fS4 bM, b 7 h.6 f er *Martin H. D. McBride, Resident Inspector, Pilgrim Date

(January 28 through February 1, 1985)

Approved By: 28, NO 3l16f fr 5E. C. McCabe, Chief, Reactor Projects Section 38 Date

Inspection Sunnary: Routine NRC resident inspection (178 hours) of plant opera-tions, equipment alignment and readiness, radiation protection, physical security,fire protection, plant operating records, maintenance and modifications, surveil-lance testing and calibration, and reporting to the NRC. In addition, the inspec-tor reviewed a Unit I reactor recirculation system jet pump flow anomaly and thepreparations for a Unit 2 refueling / maintenance outage.

Results: Three violations were identified: failure to perform the 90 percentset-down APRM high flux calibration surveillance test on Unit 1 (Detail 2.c);failure to keep an isolation zone clear (Detail 12); and failure to obtain therequired RWP before entering a radiological contaminated area in the Unit 2 con-tainment (Detail 6.b). Additionally, a concern was identified about the tolerancesplaced on the acceptable APRM channel gain (Detail 2.a).

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8504040330 850329PDR ADOCK 05000245G PDR

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DETAILS

1. Plant Status

Unit 1:

The reactor operated at full power except for planned power reductions forsurveillance testing and preventive maintenance.

Unit 2:

The reactor core reached the end of full power life at 1730, January 23, andwas in a power coast-down to 88% power until the beginning of a refueling /maintenance outage on February 16.

2. Average Power Range Monitor Calibration - (Unit 1)

The inspector reviewed the licensee program for calibrating and testing theaverage power range monitors (APRM) described in procedures:

SP404C, "APRM Calibration," Revision 4, dated March 30, 1984;SP1040, "APRM Calibration using Heat Balance," Revision 2, dated September1, 1982; and, .

RE 1002, " Core Heat Balance," Revision 8, dated September 1, 1982.

The following were noted:

a. APRM Channel Gain Adjustments (Millstone 1)

(1) Periodic Surveillance

The program did not ensure that the APRM high flux scram trip set-tings are below the Technical Specification Limiting Safety SystemSettings (LSSS) 2.1.2A. The inspector found no coordination betweencalibration of APRM channel gain and the APRM trip settings for theReactor Protective System. Specifically, Procedure SP1040 allowsthe APRM gain adjustment factor (AGAF) to be set as high as 1.03.AGAF is the ratio of rated power determined by heat balance to theactual APRM reading. At Millstone 1, AGAF is a calculated value

j which is not specifically required to be used to correct the corepower instrumentation error. Procedure SP404C allows the high fluxscram trip levels to be set almost as high as the LSSS values (117%

, t 2.5% vs. 120%). If the AGAF and the high flux trip setpoint were' both high, the LSSS limits could be exceeded prior to a trip of the

channel involved.!

On January 29 and 30, 1984, process computer P1 program output dataindicated that one AGAF was 1.03, one was 1.02, and four were 1.01.The most recent APRM high flux scram trip calibration, dated January

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3,1985, indicated that the actual trip levels were set low enoughto compensate for the high AGAFs. Therefore, no exceeding of therequired LSSS actually existed at this time.

The licensee is presently using an off-line computer program tocalculate reactor core power. This procedure for a core heat bal-ance, RE 1002, uses a relationship between turbine first stagepressure and steam flow developed in ASME Turbine Performance Test-ing. Steam flow replaces the feedwater flow measurements otherwiseused to perform a heat balance, and is used to provide a more accu-rate calculation of core power. SP 1040 is then used to adjust,

overall APRM channel gain to an AGAF accuracy of 3L

The inspector discussed coordinating the allowable AGAF and highflux scram trip settings with the licensee. If SP404C specifiedtrip setpoints which provided a margin that assured that the tripsetpoints corrected by the AGAF did not exceed the maximum allowablesetting, the identified potential for exceeding the LSSS would beeliminated.

(2) Accuracy of Process Computer Displayed AGAFs

The process computer provides AGAFs as part of its periodic reportoutput data. These AGAFs are the result of the on-line computercalculated core heat balance. This calculation uses different inputdata than the RE 1002 heat balance and can suffer the inaccuraciesof feedwafer flow measurements. The difference between APRM channeloutput and the digital value used in the process computer is re-flected as an error on the computer calculated AGAFs. However,since the periodic report data is available to the control roomoperators as an aid to monitoring nuclear instrumentation perform-ance, additional considerations can be applied to determining an,

acceptable range of process computer AGAF values. Such considera-tions could include the accuracy of the thermal power calculation

' and the accuracy of the APRM input to the digital process computeras well as the actua! high flux trip settings per SP404C.

| After a review of data sheets associated with SP404C, the inspectori noted that, during calibrations of the APRMs, the recorded computer| value differed with each channel set at full power. Although the| computer displays APRM values to one-hundreth of one percent power,! the tolerance in the acceptance criterion is only 2.5 percent. This

is the difference between the APRM channel test current and computeri digital value. This error is reflected directly in the computer| calculated AGAFs. Inspector observations during operation showed| that APRM channels with larger differences between computer digital

values and local APRM indication also had higher computer calculatedAGAFs.

! For example, an output from process computer program 00-3 run at| 1402, February 5, was compared to the APRM local indication:|

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Channel Reading APRM Local Output Process Computer AGAF

1 99.5 99.02 1.0092 98.5 98.33 1.0163 98 98.17 1.0174 99 97.33 1.0265 98 98.33 1.0166 99 98.99 1.009

The apparent difference in Channel No. 4 was confirmed when review-ing the SP404C data sheets. In general, the channels with largedifferences between APRM channel analog values and the process com-puter digital values also tended to have the highest computer cal-culated AGAFs.

The resolution of these matters is unresolved (245/85-02-01) pendingfurther inspector review.

b. APRM Clamped 120 Percent Flux Trip

Inspector review identified no inadequacies in the setting of the 120% !

flux trip. Procedure SP404C verified that the APRM high flux trip isless than 120 percent at 100 percent recirculation flow but it did notclearly specify a test of the trip at higher flow rates. The inspectorasked about the value of specifically requiring verification of the ac-curacy of the 120 percent clamp on the flow biased flux trip. The lic-ensee initiate'd procedural changes to SP4048, "APRM Functional Test,"and SP404C. These include testing the 120 percent clamp at flows above100%. Proper operation was verified on February 13; all channels were'

found within specification using the revised procedures. The inspectorhad no further questions on this item.

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c. APRM 90 Percent Power Set Down

The APRM trip functions are defined in Technical Specification 3.1.A,Tables 3.1.1 and 2.1.2A. The trip point set-down function is associatedwith the 100 percent generator load reject feature. The licensee did

! not require that the 90 percent set-down of the APRM flow-biased high| flux trip be calibrated quarterly. Licensee records indicate that thei 90 percent set-down trip was last calibrated in November 1982. That

violates Technical Specification 4.1.A and Table 4.1.2, which requiresthat APRM flow biased trips be calibrated quarterly (245/85-02-02).,

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, The licensee has issued changes to SP404B and SP404C (SP4048, Revision| 1, Change 3 and SP404C, Revision 4, Change 1), both dated February 8,| 1985. These changes added steps to verify the operation of the APRM

set-down function. Testing conducted with the revised procedure onFebruary 13 verified that the 90 percent power set-down operated withinspecifications.

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3. Reactor Racirculation System Jet Pump n ow Anomaly - (Unit 1)

A change in jet pump performance occurred on January 14 when recirculationflow decreased after a condensate booster pump was placed on line. The reac-tor had been at full power since 1610, January 13. Power was reduced by 5%by decreasing the speed of both recirculation pumps to provide a margin fora potential suction pressure transient when starting another condensate boos-

i ter pump (C8P). After starting the booster pump, recirculation pump speedwas returned to its original value, but reactor power did not return to itsoriginal value until recirculation loop flow was increased an additional 7percent.

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.a. C_ompliance with the Licensing Bases.

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The licensee's initial response was to investigate the potential for afailed jet pump as required by Technical Specification 3.6.G and 4.6.G.This specification, along with NRC Bulletin 80-07, " Jet Pump AssemblyFailure," establishes limits on reactor operation if certain parametersindicate a jet pump failure. These include changes in recirculation pump

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speed-flow character stics, changes in power-core flow relationships,7

j and changes in jet pump differential pressure.,

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The licensee also evaluated jet pump integrity in reviewing the perfor-mance monitoring which was recommended in General Electric SIL No. 330'

dated June 9, 1980. A plot for each jet pump has been maintained daily,^

since the SIL yas issued. A jet pump or jet pump pair with a degradednozzle or riser would trend away from the average value. The data, whichincluded plots of individual jet pump flow as a percentage of normalizedjet pump flow, remained unchanged before and during this event.

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In addition, jet pump differential pressure transmitter outputs were ob-| served for noise level. Each transmitter output was recorded and com-

pared with traces on file which were taken during single recirculationloop operation. In single loop operation, the idle loop is in flow re-versal. A jet pump or jet pump pair with a damaged nozzle or riser wouldbe in flow-reversal. The flow turbulance noise indicated that each pumpwas in forward flow operation, and not in flow-reversal. i

This data is presently under additional review by General Electric.t

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| The inspector followed the licensee investigations to verify jet pumpintegrity. These actions were observed to be taken promptly.

b. Jet Pump Efficiency

A measure of overall jet pump operation is indicated by the ratio of jetpump driven flow to drive flow, or the jet pump M-ratio. Prior to Janu-ary 14, the M-ratio at full power was 1.23. Using daily station perfor-

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! mance log data, the calculated M-ratio began to decrease with the 1400| hourly entry. (The condensate booster pump has been placed on line about

1345.) Based on total core flow (C202) and total recirculation loop flow

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(D205), calculations made by the inspector indicated that the M-ratiocontinued to decrease to a minimum value of 1.107 at 1700 on January 15.This reflected an increase in recirculation loop flow of about 2.3 MLB/HRto maintain full core flow. From that low point, the M-ratio recoveredto 1.22 on February 13.

c. Condensate Booster Pump Repair

The jet pump flow anomaly occurred in conjunction with a 5 percent powerreduction needed to place the "A" CBP in service. This pump had beensecured on December 25, 1984 due to an increase in thrust bearing temper-ature. Erosion damage of the pump casing was repaired, bearings and wearrings were replaced, and the pump was returned to service on January 14.

The inspector had observed portions of the casing repair and pump over-haul, which were performed by plant personnel and a technical representa-tive. The work involved sand blasting the casing with a low dust silicasand and cleaning by vacuum cleaner. Also, a spray foaming cleaner wasused; the surfaces were wiped with a rag. The casing was repaired witha proprietary ceramic compound for use in metal repair. The pump wasreassembled using silicone grease on "0" rings and silicone gasket mate-rial between the casing halves. The work was controlled. It receivedmanagement supervision and appropriate levels of cleanliness were main-tained.

No unacceptable. conditions were identified during the repair.

d. Discussion

This event was compared to a particulate intrusion at another BWR on Aug-ust 18, 1982 when about 100 cubic feet of powdered resin were injectedinto the reactor recirculation system from the reactor water cleanupsystem. The resin intrusion was accompanied by water chemistry changesas an increase in condectivity to 18 micromho per cm. That event is

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described in NUREG/BR-0051, " Power Reactor Events," January-February'

1983, Volume 5, No. 1. As discussed in NUREG/BR-0051, studies associatedwith the resin intrusion confirmed that polymer particle injection intoturbulent water flow reduces drag substantially. This would increaserecirculation flow in a turbulent system without an increase in pumpspeed.

In the case of the Millstone flow anomaly, there were no changes inreactor water chemistry or radiochemistry. Conductivity and chloridesremained low, pH unchanged, filtered samples normal, and radio-isotopicanalyses unchanged. Additional recirculation pump speed (7%) and power(13%) were required to restore 100% power core flow.

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e. Licensee Actions

The flow biased APRM trip point is determined using recirculation loopflow. Since Technical Specification 2.1.2.A.1.a defines 100 percent de-sign flow as the recirculation flow needed to achieve 100 percent coreflow, the APRM flow converters were re-calibrated as jet pump efficiencychanged.

In an effort to remove otherwise undetected impurities from the reactorcoolant, a second demineralizer was placed in sevice and Reactor WaterCleanup System flow was increased from 0.15 to 0.23 MLB per HR on January18. Increased flow was maintained through February 3. At that time thejet pump M-ratio had increased to 1.2.

Restoration of the previous M-ratio over time was accompanied by restor-ation of the pre-event recirculation pump speed for 100% power. Recir-culation pump power input also decreased as the M-ratio was restored.However, that power input did not return to its pre-event value but toan about 8% increase over that value (3.65 MW before, 3.90 MW after).Recirculation pump temperatures and seal pressures are not logged, butoperators stated that they had detected no changes in these parameters.Also, the licensee stated that the indicated recirculation pump powerinput change was not significant considering the instrumentation charac-teristics.

f. Conclusions_

No basis was found for concluding that the jet pump flow anomaly was re-lated to jet pump degradation, to an instrumentation or common instrumentpower supply problem, or to normal operation of a third condensate boos-ter pump.

Since the reduction in jet pump performance accompanied the starting ofthe "A" Condensate Booster Pump, there is a strong probability that thecause of the condition was the injection of a particulate or surfactantmaterial into the primary system when that pump was placed on line.

No unacceptable nuclear safety conditions were identified in regard tothis event.

4. Unusual Event - Loss of Pcwer to the Emergency Operations Facility

An Unusual Event was in effect from 1855 to 1925, February 12, because com-mercial power to the Emergency Operations Facility (EOF) was interrupted dur-ing a winter storm and the EOF diesel generator did not start. The Millstonepower plants were not affected by this power outage, and the Unusual Eventwas terminated upon restoration of the commercial power supply.

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Failure of the EOF diesel was attributed to a failure of the starting battery(two 12 volt batteries in series). Two cells of one 12 volt battery were

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found shorted. The diesel was " jump started" with portable power packs whichremained at the EOF until battery replacement was accomplished on February13.

The EOF diesel generator and its batteries are included in a preventive main-tenance program. That program includes a weekly test run of the diesel andbattery surveillance. Prior to the failure, the machine tested satisfactorily,

on February 7.

The license has changed the preventive maintenance program to include replac-ing the starting batteries every two years. In addition, the diesel generatorwill receive a full load test yearly using a vendor supplied load bank.

The licensee is considering installing a heated battery enclosure or reloca-tion of the batteries into the EOF as a long term corrective measure. Sincethe EOF is onsite but remote from the control rooms, an annunciator may be

: installed to. indicate an interruption in commercial power to the EOF diesel.

No unacceptable conditions were identified.

5. Small Break LOCA Analysis Error - (Unit 2)

.The licensee and the NSSS vendor discovered that an error had been made inthe input parameters to the current small break LOCA analyses. This resultedin a Technical Specification which allowed less conservative plant operation

; than the supporting analysis specified. Reanalysis with corrected parameters'

resulted in the small break LOCA calculation of peak clad temperature (PCT)increasing by 64F (from 1971F to 2035F). The 10 CFR 50.46 and 10 CFR 50Appendix K PCT limits are 2200F.

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The e.*ror is associated with Technical Specification 3.2.6,. Table 3.2-1 andi Figure 3.2-4. That specification involves power distribution limits which

maintain DNB margin by establishing operating limits on cold leg temperature,primary pressure, reactor coolant flow, and an acceptable region of axial fluxfor the fraction of rated power. The present technical specification (TS)was issued under Amendment No. 52 dated May 12, 1979.

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The error involved the input parameters for the analysis whica establish theAxial Shape Index (ASI) limits reflected in TS Figure 3.2-4. ,The originalanalysis assumed an ASI range of -0.14 to 0.21 at 100 percent power and -0.34to 0.36 at 80 percent power and below. Figure 3.2-4 allows operation from--0.10 to 0.15 at 100 percent power and -0.30 to 0.30 at 80 percent power andbelow. Since the assumed uncertainty in the analysis was 0.06 ASI units (SERSection 2.1.4), this would allow operation at 100 percent power with an ASIof -0.16. This is not bounded by the -0.14 ASI input to the small break LOCAmodel.

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The licensee was informed of a potential analysis problem on January 18, in-cident to NSSS vendor review. Operation was restricted aaministratively onJanuary 18 from points with less than -0.08 ASI at 100 percent power and lessthan -0.28 ASI at 80 percent power and below. This restored the margin ofthe original safety analysis.

The re-analysis was complete on January 23 and still predicted the 64F in-crease in PCT; all results were within the 10CFR50, Appendix K limits. Thiswas reported as LER 85-001.

The error resulted in an incorrectly stated peak clad temperature of 1971Fin the Safety Evaluation Report, Section 2.8.3, which was associated withLicense Amendment No. 52. This is an Unresolved Item (336/85-03-01) pendingits correction.

6. Radiation Protection

a. Small Source Surveys

The inspector asked health physics personnel about a seeming lack of re-sponse of radiation survey instruments to physically small sources. The

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licensee indicated that the response of commonly used radiation surveyinstruments to small-sized sources had been determined and that this in-formation would be added to the health physics technician training pro-gram prior to the Unit 2 refueling outage. Contract technicians willreceive this training. This will be reviewed during a future inspection

7(IFI 336/85-03 02).

b. Compliance with Radiation Protection Requirements

At 0715, February 21, the inspector saw a worker step under a barrierinto an area posted as " Contaminated-RWP Required". The area, which hassince been decontaminated, is located in the Unit 2 containment, 14 foot6 inch elevation, North side. A radiation protection technician surveyedthe individual, who was not wearing protective clothing or in possessionof an appropriate RWP. No contamination was found on the individual.The entry into a posted contamination area without an RWP for that entry,

violated Radiation Protection requirements (336/85-03-03).

d. Unmonitored Discharge Path to Sanitary Sewer System

On January 30, licensee personnel cleaned out a blockage in the drainpipe from shower and locker room drains in a non-radioactive, uncontami-nated area. These drains were not designated for disposal of radioactivematerial. This is not a monitored discharge path and was not part ofthe licensee's sampling program. The drain is directed to the sanitarysewer system. It is routine practice for licensee personnel to checkmaterial for radioactivity, and a frisker check of the material removedidentified radioactivity in this case.

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The following isotopic concentrations were identified in the sludge:

Mn - 54 9.2E-7 microcuries per gmCo - 60 3.04E-5 microcuries per gmCo - 137 5. 6 E-6 microcuries per gm

An NRC Region I radiation specialist reviewed this event with licenseepersonnel and concluded that the concentrations in the blockage materialdid not indicate a release to unrestricted areas in excess of 10 CFR 20limits on such releases. The primary source of the material is believedto be a utility sink in which floor wash water is disposed. Floors ofhigh traffic areas outside of but adjacent to radiation areas are washed.That wash water is disposed of in the utility sink. No previous blockageof this line was identified by questioning of licensee personnel. Norecords of blockage of such drains are required or kept.

The sink has been posted to forbid dumping of potentially radioactivematerial or wash water from radiation areas. The licensee is evaluatingpotential entry points to the sanitary sewer system.

The licensee's evaluation and corrective actions are not complete. Thisis an Unresolved Item (245/85-02-03) pending licensee re-evaluation tothe guidelines of NRC Bulletin 80-10, " Contamination of NonradioactiveSystems and Unmonitored Radioactive Release," and NRC Information Notice84-94, Reconcentrations of Radionuclides in Discharges to Sanitary SewageSystems.

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e. Evaluation of Nozzle Dam Improvements

Steam Generator (SG) nozzle dams (2 per nozzle) are installed on theprimary system inlet and outlet nozzles to the SGs to allow SG workwhile the reactor vessel and reactor cavity are filled for refueling.The licensee modified the steam generator nozzle dams and changed the

; radiation worker training program for installation of nozzle dams based| on experience in the 1983 refueling outage. Inspector review identified

the following.i; Use of a constant tension spring device (replacing a block and-

|tackle rig) to support the nozzle dam during installation. .

- Air supply manifolds to allow test inflation of nozzle dam sealsprior to installation.

Individual air supplies with a dedicated regulator for each dam.-

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Back up nitrogen supplies at the control boxes, located in tamper--

proof enclosures.

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A CCTV camera support which does not require personnel entry into-

the SG for camera use.

Nozzle dam modifications including reduced diameter pins for ease-

of installation, beve11ing of sharp edges of nozzle dam sections,a modified circumferential seal retention groove, and rib reliefin cold leg dams for ease of installation.

Modifications to the training program including. training lectures-

with a video tape demonstration, new Steam Generator mock-ups ofthe tent area and obstructions, revised training and installationprocedures, and training which is conducted by licensee personnel.

No unacceptable conditions were identified.

, f. Steam Generator Radiation Surveys

The inspector reviewed the initial survey of the steam generator primarychannel heads, taken on February 24. A significant increase in radiationlevels occurred during the previous operating cycle. Levels were gener-ally higher than those prior to the chemical decontamination which wasperformed during the 1983 refueling / maintenance outage. Although thatchemical decontamination was successful in reducing radiation levels,it apparently also provided a site for deposition of highly contaminatedmaterial. The highest levels were found in the No. 2 Steam GeneratorHot Leg channel head. The table below summarizes the survey; readingsare in Rem per hour:

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No. 1 Steam Generator- No. 2 Steam GeneratorHot Leg Cold Leg Hot Leg Cold Leg:

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highest divider,

| plate reading: 30 20 72 26;

| Highest tube. sheet reading: 30 15 34 18

General Area' Dose rate: 20 12 28 14

| The-inspector followed the licensee's plans for steam generator work in-cluding the ALARA reviews. No unacceptable conditions were identified.An NRC health physics inspection (50-336/85-10) was scheduled to furtherreview the radiation controls associated with this work.

7. Control Room Staffing

-The inspector reviewed ACP 6.01, " Control Room Procedure," Revision 13, datedSeptember 7, 1982. 10 CFR 50.54.m (2)(iii) specifies that, with the reactorin an operational mode, a person holding a senior operator license is required

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in the control room at all times. A second operator is required to be at thecontrols at all times. The Statement of Consideration for this Rule publishedon July 11, 1983 (48 FR 31611) states that the requirement is based on re-stricting the senior operator (SRO) from performing the functions of a reactoroperator (RO), even for a limited time. Otherwise, the SR0 oversight functioncould be degraded. The station administrative procedure does not address theimplementation of the additional requirements stated in the January 1, 1983revision to 10 CFR 50.54.m. Since the Shift Supervisor is designated ActingDirector of Station Emergency Operations when first implementing the StationEmergency Plan, the restrictions which assure his availability need to becoordinated to implement those of 10CFR 50.54.m. Routine resident inspectortours have identified no cases of shift supervisor (an SRO) performance ofRO functions. The adequacy of procedural controls in this regard is Unre-solved (245/85-02-04).

8. NRC Bulletin 84-03, " Refueling Cavity Water Seal" - Unit 2

The inspector reviewed the licensee's NRC Bulletin 84-03 response which wasdated November 29, 1984. This letter addressed the potential for and the

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i consequences of a refueling cavity pool seal failure. The description of thesealing device was found to be accurate. As stated in Attachment No. 5 tothe response, additional reviews were in progress to identify events other '

than a seal failure and implement corrective actions.

: The licensee identified the need to provide seismic support for the refuelingcavity drain line ta its first isolation valve. A modification will add 12

| restraints to that line and is to be installed prior to fuel movement. Thelicensee committed to updating the emergency operating procedures to includeresponse to a loss of refueling cavity water inventory. Also, a demonstrationwill verify that the operator actions required by the procedures to placereactor fuel in a safe location can be performed within the time intervalassumed in the analysis. The inspector found that the licensee's submittaldoes not address the potential for or the effects of a failure of the steamgenerator nozzle dam system. That system is in place during refueling toallow steam generator inspection and maintenance to be carried on concurrentwith fuel movement. The inspector understands that the this information willbe included in an additional submittal. These items will be verified duringa future inspection (IFI 336/85-03-04).

A related event occurred at another facility on May 15, 1981. At the timeof that incident, the fuel transfer canal was drained for maintenance on thetransfer mechanism. The gate between the spent fuel storage pool and thetransfer canal was in place with its seal inflated. Air pressure to the sealwas lost, allowing water from the pool to fill the canal at an initial rateof 1000 gpm. An equilibrium level 7 feet below normal pool level resulted. -

If this occured with the fuel transfer tube (FTT) gate valve open and the FTTblank flange removed, water would flow from the transfer canal into the refuelcavity. The additional loss of water could allow the spent fuel storage pool

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to drain to just above the top of active fuel. This was discussed with thelicensee and will be addressed in subsequent followup inspection of NRC Bul-letin 84-03, which remains open.

9. RPS Power Supply to System Isolation Devices

The inspector reviewed PT 1430, "RPS MG Set and Backup Protection Surveil-lance," Revision 1, dated February 4, 1985. This revision corrected pre-viously identified deficiencies in instrument channel functional testing.The test is now performed using an external voltage / frequency source fortesting overvoltage, undervoltage, and underfrequency trip devices; all de-vices can now be properly tested. Inspection item 245/84-27-04 is thereforeclosed.

10. Observation of Surveillance

The inspector observed portions of Unit 1 Emergency Gas Turbine Generatorsurveillance testing on February 5.

11. On-Site Safety Review Committee (Unit 1)

The inspector attended a meeting of the Unit 1 PORC on January 16. The in-spector found that the conduct of the meeting met the requirements of Techni-cal Specification 6.5.1 for committee membership, meeting frequency and ful-fillment of responsibilities. The presentations elicited active questioningand discussions. Committee members presented an informed and critical overviewof plant design and operations.

12. Physical Security Plan Implementation

This paragraph contains Safeguards Information and is exempted from :.ublicdisclosure.

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THIS PAGE CONTAINS SAFEGUARDS

INFORMATION AND IS NOT FOR

PUBLIC DISCLOSURE, IT IS

INTENTIONALLY LEFT BLANK.

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13. Exit Interview -

At periodic intervals during the inspection, meetings were held with seniorlicensee site management to discuss the inspection scope and findings. In-formation which may have been proprietary and which was addressed during thisinspection period was discussed with licensee representatives. No informationidentified as proprietary was included in this report. The following samma-rizes the changes identified in the status of open items:

New Items:

Unit 1

245/85-02-01, Corrective actions to coordinate acceptable range of AGAF withAPRM trip levels (Report Detail 2.a).

245/85-02-02, Failure to perform calibration of APRM 90 percent set down trip(Report Detail 2.c).

245/85-02-03, Unmonitored discharge path through sink drains into the sanitarysewer system (Report Detail 6.d).

245/85-02-03, Revise ACP6.01, " Control Room Procedure," to include bases of10 CFR 50.54.(m) (Report Detail 7).

245/85-02-04, Failure to maintain an isolation zone clear (Report Detail 12).

Unit 2

336/85-03-01, Correct small break LOCA analysis results for PCT (Report De-tail 5).

336/85-03-02, Review radiation protection technician training in survey ofsmall sources (Report Detail 6.a).

336/85-03-03, Failure to observe radiation control barrier (Report Detail6.b).,

336/85-03-04, Verify completion of commitments stated in November 29, 1984response to NRC Bulletin 84-03 (Report Detail 7).

Old Items:

Unit 1

(Closed), 245/84-27-04, corrective actions for proper instrument channelfunctional tests of RPS electrical protection underfrequency devices perSurveillance Specification 4.1.C.1 (Report Detail 9).

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