IR 05000245/1992033

Insp Repts 50-245/92-33,50-336/92-35 & 50-423/92-31 on 921223-930202.No Violations Noted.Major Areas Inspected: Plant Operations,Radiological Controls,Maint,Surveillance, Security,Outage Activities,Licensee self-assessment & Repts

ML20034G152
Person / Time
Site:	Millstone
Issue date:	03/03/1993
From:	Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20034G143	List: IR 05000245/1992033 ML20034G142
References
50-245-92-33, 50-336-92-35, 50-423-92-31, NUDOCS 9303090130
Download: ML20034G152 (25)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report / Docket:

50-245/92-33; 50-336/92-35; 50-423/92-31

l License Nos.:

DPR-21; DPR-65; NPF-49 Licensee:

Northeast Nuclear Energy Company-l l-P. O. Box 270 l

Hartford, CT 06141-0270

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l-l Facility:

Millstone Nuclear Power Station, Units 1, 2, and 3

Inspection at:

Waterford, CT Dates:

December 23,1992 - February 2,1993 Inspectors:

P. D. Swetland, Senior Resident Inspector

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A. A. Asars, Resident Inspector K. S. Kolaczyk, Resident Inspector, Unit 1

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D. A. Dempsey, Resident Inspector, Unit 2

R. J. Arrighi, Resident Inspector, Unit 3

/P(AR 3/3!13

Approved by:

oMW Lawrence T. Doerflein, Chief Date

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Reactor Projects Section No. 4A Scone: NRC resident inspection of core activities in the areas of plant operations, radiologi-cal controls, maintenance, surveillance, security, outage activities, licensee self-assessment,

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and periodic reports.

l The inspectors reviewed plant operations during periods of backshifts (evening shifts) and deep backshifts (weckends, holidays, and midnight shifts). Coverage was provided for 60

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hours during evening backshifts and 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> during deep backshifts.

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Results: See Executive Summary l

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FXECUTIVE SUMMARY j

Millstone Nuclear Power Station

Combined Inspection 245/92-33; 336/92-35; 423/92-31 l

i Plant Operations Unit 1 operated at full power during the inspection period with the exception of power reductions for routine preventive maintenance and testing. Technical Specification relief was

requested and granted to prevent spurious plant shutdowns as a result of anomalous reactor protection system spikes during the changeover of condensate deminerahzers.

I Unit 2 continued the preparations for plant startup following completion of the Cycle l'

refueling and steam generator replacement outage. Startup began on January 5 and 100

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percent power was achieved on January 24. There was a power reduction to 65 percent on

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February 1-3 to repair a feedwater system leak. The licensee identified that operators had not properly completed remedial actions for two incoerable accident monitoring systems

during the startup. Enforcement discretion ms exercised for this failure to compensate for

inoperable equipment. Poor housekecping conditiom in the Unit 2 enclosure building

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remained unresolved pending NRC review of the lics.nsee's housekeeping program l

requirements. Also, several discrqa.cies in the Fmal Safety Analyses Report description of l

safety injection tank design assumptions need to be resolved.

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t Unit 3 operated at 50 percent power while a failed motor driven feedwater pump was

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undergoing repairs. Full power was achieved on January 6, and maintained with the exception of short power reductions for maintenance and testing.

Maintenance / Surveillance f

i The maintenance and surveillance activities observed during this inspection were conducted acceptably. There was good preparation and control of Unit 2 ground isolation activities for a DC bus ground. Licensee evaluation of an intermittent 4160 volt circuit breaker failure on E

Unit 1 identified several potential deficiencies in breaker preventive maintenance.

J Unresolved issues were opened to address NRC's assessment of the Unit 1 breaker i

preventive maintenance program and its effect on other circuit breakers; as well as, the cause I

and corrective action for a Unit 2 surveillance procedure discrepancy identified during l

containment sump isolation valve testing.

Engineering and Technical Support j

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The licensee identified a series of discrepancies with proper overlap testing of Unit 3 l

instrumentation channels. Several instances have occurred where complete testing from the l

detector to functional output was not achieved. In no instance did the lack of testing result j

in an unknown instrument malfunction. The licensee has several continuing corrective action commitments to verify the adequacy of testing overlap.

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Safety Assessment / Quality Verification j

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The licensee identified and corrected two small feed water flow transmitter miscalibrations I

which were causing actual reactor power to exceed the license limit by 0.6 percent,

Enforcement discretion was exercised for this licensee identified problem because the indicated power deficit was bounded by the plant safety analyses and prompt, adequate

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corrective actions were taken prior to the conclusion of this inspection.

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SUMMARY OF FACILITY ACTIVITIES j

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Unit 1 i

Millstone Unit 1 operated at 100% power for the majority of the report period. On l

December 29, main steam line high radiation alarms were received in the Unit I control

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room when the 'G' condensate demineralizer was placed into service.. The licensee believes

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that the momentary increase in radioactivity was caused by activation of oxygen or resin j

initially entrained in the demineralizer effluent. On January 15, 1993, the licensee received a j

waiver of compliance from the Office of Nuclear Reactor Regulation (NRR) to bypass the

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main steam line high radiation monitor trip function for two hours while valving in

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condensate demineralizers. This waiver was provided to minimize the possibility of an l

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unnecessary plant trip if the main steam line radiation monitors spiked again when other demineralizers are valved into service. Power reductions to 60% were performed on January 8 and 27 for turbine stop valve testing and on January 21 and 22 to repair a leak in the 'A'

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condenser waterbox.

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During the report period, the licensee completed testing the first phase of a modification which would improve the reliability of the offsite 345KV transmission system and allow all j

three Millstone Units to operate at 100% of rated thermal power. Prior to installation of the

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modification, the output of Unit 3 was limited when Units 1 and 2 were at full power due to

transmission system grid instability concerns. The modification separates the Unit 1 output from the grid in the event of simultaneous or successive faults on the Millstone-Montville 371 and Millstone-Card 383 transmission lines. Unit I has 100% turbine bypass capability and should not trip on the load reject transient. Following installation of the modification, the inspector reviewed Unit 1 operating procedures to ensure they were revised to reflect the addition of the modification.

I Unit 2 t

At the start of the inspection period, Millstone Unit 2 was in cold shutdown (Mode 5) with the reactor coolant system (RCS) drained to 89 inches abo.'e the hot leg centerline. Major j

activities satisfactorily completed during the period included the containment integrated leak.

rate test, a hydrostatic test of the reactor coolant system, an integrated test of the engineered i

safeguards system, and core physics testing. The RCS was filled on December 30 and

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heatup commenced on January 5,1993. The licensee started up the reactor on January 9 and reached criticality on January 10, 1993. Mode I was entered and the main turbine was l

placed on the grid on January 13. Power ascension and core physics testing were performed

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until January 24 when the plant attained 100% of rated power, officially ending the cycle 12

refueling outage. On February 1, power was reduced to 65% in order to shutdown the 'B'

main feedwater pump to repair a leaking casing vent plug. Full power operation was resumed on February 3.

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Millstone Unit 3 entered the report period at 50 percent power while repairs were being made to the motor driven feedwater pump. These repairs were completed and full power

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operation was resumed on January 6. On January 29, power was reduced to 94 percent due to repeated overpower delta-T alarms. The licensee identified intermittent oscillation of the

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loop 1 cold temperature detector and replaced the resistance temperature detector amplifier

l card. The unit returned to 100 percent power on January 30 and operations continued

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without incident through the end of this mspection penod.

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l 2.0 PLANT OPERATIONS (IP 71707,93702)

e 2.1 Operational Safety Verification (All Units)

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l The inspectors performed selective examinations of control room activities, operability of

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engineered safety features systems, plant equipment conditions, and problem identification systems. These reviews included attendance at periodic plant meetings and plant tours.

i The inspectors made frequent tours of the control room to verify sufficient staffing, operator procedural adherence, operator cognizance of control room alarms and equipment status, j

conformance with technical specifications, and maintenance of control room logs. The inspectors observed control room operators response to alarms and off-normal conditions.

i The inspectors verified safety system operability through independent reviews of system j

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configuration, outstanding trouble and event reports, and surveillance test results. The i

selection of safety systems for review was made using risk-based inspection guidance developed by the NRC. During system walkdowns, the inspectors made note of equipment condition, tagging, and the existence of installed jumpers, bypasses and lifted leads.

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The inspectors toured accessible portions of plant areas on a regular basis. The inspectors j

observed plant housekeeping conditions, general equipment conditions, and fire prevention practices. The inspectors also verified proper posting of contaminated, airborne, and radiation areas with respect to boundary identification and locking requirements. The inspectors also observed selected aspects of security plan implementation including site access controls, implementation of compensatory measures, and guard force response to alarms and i

degraded conditions.

2.1.1 Isolation Condenser Walkdown/ Surveillance Procedure Review - Unit 1

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The inspector performed a walkdown of the isolation condenser (IC) system at Millstone Unit 1 to ensure the system was aligned in its standby condition. The inspecter verified that the IC valves were properly positioned per the applicable valve lineup sheet and that the system drawings accurately reflected the L-installed plant configuration.

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Administrative Control Procedure (ACP) 9.02A, " Surveillance Master Test Control List,"

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identifies the licensee prepared procedures which were developed to meet the test require-ments contained in the Unit I Technical Specifications. The inspector reviewed the

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following licensee prepared surveillance procedures listed in ACP 9.02A to ensure they

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properly tested the IC system at the time intervals required by plant technical speci5 cations.

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627.1 Isolation Condenser Shell Side Water Level and Temperature Check i

e SP412C Reactor Low-Imw Water I2 Vel Functional Test / Calibration

SP412M Isolation Condenser System Automatic Actuation Functional Test

627.3 Isolation Condenser Heat Removal Capability Determination

SP406Z Isolation Condenser Vent Radiation Monitor Functional Test The inspector did not identify any discrepancies during the walkdown or surveillance procedures review.

2.1.2 Containment Isolation Valve Checks - Unit 1 The inspector checked the position of 22 containment isolation and local leak rate test (LLRT) valves located in the torus enclosure. The inspector verified that the valves were positioned as outlined in the applicable system drawings and that they were correctly labeled.

Except as noted below, the inspector also veri 5ed that valves which were required to be locked were listed in the locked valve list 01-10.11.

During the walkdown, the inspector noted three discrepancies. The position of LLRT valve 1-AC-23C was not listed as locked closed on the applicable system drawing. Alsc, LLRT valves 1-SS-57 and 58 were closed but not locked. These valves were installed in the 1991 refuel outage to perform local leak rate testing of the drywell sump pump containment isolation valves. The inspector noted that similar valve configurations were required by the NRC to be locked as part of the Systematic Evaluation Program (SEP) under topic VI-4.

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Through discussions with the licensee, the inspector determined that the valves were not locked because of an administrative oversight. The licensee committed to lock the valves and update the applicable system drawing by February 28,1993. Additionally, the licensee will check other recent modifications that installed containment LLRT valves to ensure the valves were appropriately controlled. Based on the isolated nature of this finding and the licensee's committed actions, the inspector had no further questions at this time.

2.1.3 Ilousekeeping Tour - Unit 2 On January 27 and 29, the inspector conducted a housekeeping tour of portions of the Millstone 2 enclosure and auxiliary buildings. This followup inspection was performed in response to recent NRC team inspection fimdings of poor conditions in these areas as documented in inspection report 50-336/92-36. Conditions in the auxiliary building were good. However, the inspector found that conditions in the 38 foot-six inch elevation of the

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east and west enclosure building penetration rooms were little improved since the team inspection in early January. Discrepant items included pens, tools, rags, plastic sheets, tape, apparently abandoned drip pockets, lead shielding blankets, and welding machines. While

wc-of the items posed an immediate safety problem, the condition of the rooms reflected l

poor housekeeping practices during and after the performance of work in these areas. At the end of the inspection period the inspector noted that conditions had improved generally, but that more detailed cleanup remained to be done.

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The inspector reviewed licensee procedure ACP-QA-4.01, " Plant Housekeeping," and noted the requirement that unit department heads / supervisors monitor maintenance and housekeeping practices during routine / day-to-day activities and identify deficiencies in writing via inter-ofHee memoranda or trouble reports. Copies of these requests are to be kept until the deficiencies are resolved. Through discussions with the licensee, the inspector j

determined that management tours are performed frequently, but that discrepant items generally are dispositioned only on an informal basis. The inspector concluded that these measures were not entirely effective. This matter is unresolved (URI 50-336/92-35-001)

pending NRC review of the licensee's response to this item.

2.1.4 Technical Specification Review for Safety Injection Tanks - Unit 2 Technical Specifications (TS) provide assurance that the plant is operated within its design basis and to preserve the validity of the safety analyses. The surveillance procedures which

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verify conformance with the TS provide assurance that equipment, components, and systems important to safety are capable of performing their safety functions. The inspector reviewed the TS and surveillance requirements associated with the safety injection tanks (SIT) to verify j

the operability of that system. The inspection consisted of discussions with licensee i

penonnel from the operations, engineering, health physics, instrumentation and control, and chemistry departments, and review of the TS, Final Safety Analysis Report (FSAR), and

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surveillance and operating procedures.

The inspector reviewed the following procedures and completed surveillance forms:

SP-2619A, Control Room Shift Checks SP-2619E, Control Room Monthly Checks

SP-2836, Safety Injection Tank Analysis For Boron j

SP-2603A, Safety Injection Tank Isolation Valve Test, SIAS

SP-2603B, Safety Injection Tank Isolation Valve Test, Pressurizer Pressure j

OP-2306, Safety Injection Tanks

I All of the tests were completed satisfactorily within the time period required by the TS. The inspector observed that the boron concentration verification performed every shift consisted j

merely of logging the concentration posted on the main control board from the latest monthly

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analysis. The readings are required by procedure only if SIT level has increased by 1.0%

from the last sample date. Noting that the licensec had previously found that superfluous

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log. had contributed to plant equipment operator performance problems, the inspector questioned the utility of this practice. The licensee acknowledged the obsenation.

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The licensee currently enters the containment during power operation to obtain the monthly SIT liquid sample required by the TS. However, the inspector noted that boron verification

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samples taken for SIT level increases are taken from a recirculation header drain line located

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outside the containment. The licensee stated that the recirculation header samples were

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considered to be representative of SIT contents. Thu inspector questioned whether the

licensee had considered the need for the containment enny from a radiological dose

(ALARA) perspective, and found that the licensee was evaluating a TS change to reduce the i

frequency of the surveillance. The inspector also observed that NUREG-1366,

" Improvements to Technical Specification Suneillance Requirements," dated December 1992, recommends elimination of the SIT level sample requirement.

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Tha imoector found several potential discrepancies between the TS requirements and the

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The TS requires a minimum SIT nitrogen overpressure of 200 psig, while the large break LOCA analysis value in Table 14.6.5.I-3 of the FSAR appears to assume a mini'num

value of 238.5 psia (223.8 psig). The minimum SIT boron concentration required by the TS l

is 1720 parts per million, while FSAR section 6.3.2.2 specifies a minimum concentation of

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1770 parts per million. Fin?lly, the liquid volume of each SIT stated in FSAR Table

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14.6.5.1-3 is 1150.5 cubic feet, while the TS specifies a minimum volume of 1080 cubic feet. Regarding the last item, the inspector noted that TS amendment 95, dated May 16,

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1984, approved the TS value based on a revised LOCA analysis which satisfied the criteria i

of 10 CFR 50, Appendix K, ECCS Evaluation MJels, thus providing reasonable assurance i

that the TS values were the correct ones. Since the potential exists that the FSAR may not

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reflect the current design assumptions contained in the TS, the inspector requested that the

licensee reconcile these apparent conflicts. The licensee committed to evaluate the apparent

i discrepancies and revise the FSAR if necessary. This item is unresolved (URI 50-336/92-l 35-002).

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The inspector concluded that surveillance procedures adequately assured that the TS

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requirements for the SITS were being satisfied, but that potential conflius between the TS j

and the FSAR needed to be resolved. The licensee is appropriately censidering changes to

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tank sampling requirements to minimize radiological exposure to personnel.

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2.2 Failure of Gas Turbine Output Breaker to Close - Unit 1 On December 24,1992, the Unit 1 gas turbine output breaker fa" to close automatically

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when the unit was started during a routine surveillance test. Acco.oingly, the gas turbine

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was declared inoperable, the applicable Limiting Condition for Operation (LCO) 3.5.F

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entered (a 4-day action statement), and troubleshooting was commenced on the breaker.

Initially the licensee attributed the breaker failure to high contact resistance in the breaker

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closing circuitry. Contacts in a suspect relay located in the closing circuitry were burnished to reduce resistance..After several successful manual cycles, the gas turbine breaker was

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racked up, and the gas turbine was successfully restarted and declared operable (LCO 3.5.F.

i was exited). However, licensee personnel decided to run the gas turbine again in the near i

future to achieve an additional level of confidence.

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On December 26, the gas turbine output breaker again failed to close when the gas turbine l

was given an automatic start signal. LCO 3.5.F was entered and the breaker closing circuitry was examined again. No specific inadequacies in the closing circuitry that would inUbit breaker operation were found. Therefore additional chart recorders were installed in

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the closing circuitry to monitor breaker operation. During a subsequent gas turbine run, the breaker closed as designed; however, during a second start attempt, the breaker closed then i

quickly reopened. Analyses of the chart recording revealed that while the breaker did i

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receive a close signal, no trip signal occurred.

On December 27, following another satisfactory start of the gas turbine, the licensee decided to replace the breaker when the installed strip chart test equipment could not identify a root cause for the inconsistent performance of the breaker. Following breaker replacement, the gas turbine was staned and the breaker closed normally. However, the replacement breaker failed to automatically recharge the closing spring when the breaker operated. Although this

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failure would not prevent the breaker from opening automatically and the breaker could be

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recharged manually, the licensee remained in LCO 3.5.F until the breaker closing spring could be repaired and additional, satisfactory runs of the gas turbine were accomplished.

On December 28, the licensee backdated the LCO entrance time from December 26 to

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December 24 when it was realized that both breaker failures could be attributed to the same l

root cause. This action placed the plant in a TS required 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> plant shutdown because the

4 day action statement was exceeded. Following two subsequent successful starts of the gas

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L turbine, the plant declared the gas turbine operable and exited the LCO prior to reducing i

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i The inspector observed the licensee troubleshooting efforts conducted on December 28, and

considered them to be thorough. Test equipment was properly installed and controlled.

l Personnel who conducted the gas turbine troubleshooting efforts were knowledgeable.

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Licensee review of the breaker failures and component operability was considered thorough.

I However, a weakness was identified in logging into LCOs when related equipment failures

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were apparent. Specifically, when the gas turbine breaker failed to close on December 26, the licensee did not relate that failure to the December 24 failure despite the fact that both failures had apparently the same root cause. The licensee initially considered the entry time

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into LCO 3.5.F as December 26 when December 24 would have been appropriate. The I

nonconservative LCO entry was corrected on December 28, when the Operations Manager

reviewed the Shift Supervisors log.

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To ensure that the personnel who were involved in the December 26 LCO entry j

determination adequately consider previous equipment failures when logging into LCO action j

statements, the Operations Manager discussed the issue with these personnel. This action j

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addressed the inspector concern in this area since the licensee has handled previous multiple

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equipment failures m a conservative appropnate manner.

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2.3 Main Steam Line Radiation Alarm - Unit 1

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On December 29,1992, main steam line high radiation alarms were received in the Unit 1 j

control room when the 'G' condensate demineralizer was valved into service. ' Analyses of -

i the main steam line radiation monitor recorder traces indicated that, following valving in the

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'G' demineralizer, main steam line radiation levels spiked from the normal operating value of

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350 mrem per hour to 1300 mrem per hour. The main steam line high radiation trip setpoint

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is set at 1700 mrem per hour. The main steam line radiation monitor (MSLRM) trip function results in a reactor trip and a main steam isolation valve (MSIV) (Group I) isolation.

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The main steam lino high radiation trip is required by Technical Specifications (TS) 3.1 and 3.2 to be operable at all times when the reactor is in the Hot Standby, Startup or Run modes.

If the trip is not operable, plant TSs require all control rods to be inserted within four hours or the MSIVs must be closed within eight hours. Chapter 7.2 of the Unit 1 Final Safety

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Analyses Report (FSAR) states that the trips are inatalled to prevent the release of large

amounts of activity in the event of a fuel failure.

t The December 29,1992, event was similar to events in 1985 and 1989 when a condensate demineralizer was being placed into service. The licensee attributed the 1985 event to a high

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demineralizer crud loading which became highly activated and increased main steam line l

radiation levels when swept into the reactor coolant system. To prevent recurrence of the i

event, the licensee increased the cleaning frequency of demineralizer resins to twice a week.

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The 1989 event was attributed to entrapped oxygen in unvented sections of demineralizer piping. To prevent recurrence, the licensee made procedure revisions which require the i

demineralizers be placed slowly into service. Additionally, vents were added to the dead leg i

sections of piping. Since the 1989 event, approximately 240 demineralizers had been placed into service without a corresponding increase in main steam line radiation levels.

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l In response to the December 29 event, the licensee assembled a review team consisting of l

personnel from various departments to determine the root cause, and recommend corrective

actions. Although the team developed several theories for the event, including resin fine i

intrusion and incomplete venting, a defm' itive cause was not identified. Consequently, to prevent a reactor trip and MSIV isolation during future demineralizer changeouts, the team i

proposed to bypass the main steam line high radiation trip function during future l

demineralizer changeouts and enter the applicable TS Limiting Condition for Operation (LCO). According to the licensee, the basis for that proposal involved r.n NRC determination in a generic May 15, 1991, safety evaluation that concluded the main steam

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line high radiation reactor trip and MSlV isolation were not required and could be removed from the plant TS if additional compensatory actions were taken by a licensee. However, following discussions with the NRC staff, the licensee decided to formally apply for a TS waiver of compliance and permanent TS change which would allow the trip function to be

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bypassed for two hours during resin changeout. The request was granted by the NRC staff

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by letter issued on January 15, 1993.

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The inspector attended two Plant Operations Review Committee meetings and one Nuclear

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Review Board meeting which discussed this event and the merits of revising the TSs to allow bypassing the main steam line radiation monitors. The inspector subsequently witnessed the l

swapping of two demineralizer beds on January 15 and 21,1993. Both demineralizer l

changeouts were controlled by special procedure SP-93-1-01, " Bypassing Main Steam Line

Radiation Detectors While Placing Condensate Demineralizers in Service." The inspector reviewed the procedure and considered it to be thorough. Prior to swapping demineralizers,

thorough briefings were conducted with the operators, I&C technicians and maintenance

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personnel involved. During the observed changeouts, the inspector noted that the procedures

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were followed, log entrees were appropriately annotated and restricted access areas were properly controlled. Both changeouts took approximately 30 minutes. No radiation spikes

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l were noted during the two demineralizer changeouts. Currently, the licensee plans to

continue using the special procedure during future changeouts until a root cause for the spiking is found, or the main steam line high radiation trip function is permanently removed

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i from the plant TS.

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2.4 Operations Control of Out of Service Equipment - Unit 1

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l On January 20,1993, while performing a walkdown of control room instrumentation, the

inspector noted that a recorder which is required by plant Technical Specifications (TS) to i

monitor several reactor vessel temperatures while the reactor is critical was inoperable.

Specifically, plant TS 4.6.b.3 requires the parameters listed below be permanently recorded

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to ensure reactor vessel temperature and pressure limits are not exceeded a

j Reactor vessel shell

Reactor vessel flange

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Recirculation loops A and B

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Reactor vessel shell adjacent to shell flange

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Reactor vessel bottom head

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Plant TS allow the recorder to be out of service for brief periods of time for maintenance not

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to exceed 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. No remedial action is specified in the plant TS if the recorder is out of l

service for greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. The defective recorder was reported to the Instrumentation

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l and Controls (I&C) department for repair by use of a trouble report. Through conversations

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l with control room operators, the inspector was informed that the recorder began to act j

erratically the day before.

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The status of the recorder was not carried on the shift turnover log. Operators appeared

unaware that the recorder could not be out of service for greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> despite a label on the recorde-r which referred to TS 4.6.b.3. Additionally, the trouble report which documented the deficient condition was listed as a low priority #3 work item rather than a

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priority #1 item of immediate importance. Therefore, repair of the recorder was of low significance to the I&C department.

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The inspector discussed the status of the recorder with the Operations Manager. Following

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the discussion, the licensee determined that the recorder had been out of service since midnight on January 19. The recorder was then repaired by the I&C department later in the day The inspector concluded that if the NRC had not questioned the status of the recorder, a Riation of TS 4.6.b.3 could have occurred.

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To ensure the recorder is accurately tracked so it could be returned to service within the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> time period allowed by TS 4.6.b.3, the Operations Manager discussed the issue with the

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Shift Supervisors. The Shift Supervisors were instructed to log the status of the recorder in the shift turnover log ifit is out of service and write a Plant Incident Report (PIR) if the time

period exceeds 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Other recorders which are required by TS to be operable were checked to ensure they were properly labeled as monitoring TS required equipment. Finally,

information was provided to operators on what actions should be taken if those recorders

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become inoperable.

The inspector considered the corrective actions to be adequate. Plant conditions did not l

change during the time the recorder was out of service. Therefore, plant temperatures

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remained relatively constant and within TS reactor vessel temperature pressure limits during this period. The inspector considered the apparent failure of Operations to take the necessary action to assure the recorder was repaired within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to be a weakness of operator

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awareness of this specific TS requirement.

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2.5 Failure to Log Into Tecimical Specification Action Statements - Unit 2 At approximately 1:00 p.m. on January 7, the licensee determined that it had not entered into the Technical Specification action statement for certain accident monitoring instruments when, during plant heatup, the hot standby (mode 3) condition was reached. The instruments were not operable because calibration check prerequisites pertaining to plant conditions could not be met in mode 4. Using data stored in the plant computer, operators verified that the compensatory readings required by the action statements were acceptable during the time in which the readings had been missed. The deferred calibration checks were performed satisfactorily and the actions statements exited by 2:30 p.m. that same day. The licensee initiated a plant incident report to determine the cause of the incident and determined that it was reportable to the NRC pursuant to 10 CFR 50.73.

The affected instruments were the pressurizer power-operated relief valve (PORV) acoustic monitor and the reactor coolant system (RCS) subcooling/superheat monitor. These

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instruments are required to assure that sufficient information is available to operators to monitor and assess plant conditions during and following an accident. Technical

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Speci0 cation 3.3.3.8, applicable in modes 1, 2, and 3, requires that certa' a actions be taken

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when the instruments are inoperable. For the acoustic monitors, quench tank level, pressure, and temperature, and PORV tailpipe temperature are to be obtained once per shift. RCS

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subcooled margin is to be calculated every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if that instrument is not available. Since operating mode 3 was entered at 12:31 a.m. on January 7, the compensatory readings mandated by the action statements were not taken within the outage time permitted by the Technical Specification.

t The inspector reviewed Operations department form (OPS FORM) 2201-1, " Plant Heatup,"

and interviewed licensee personnel knowledgeable of the incident. The form is the document used by the licensee to verify that plant conditions and Technical Specification surveillance activities will support a change in operating mode. The inspector found that the surveillance procedures for the instruments had been deferred because the plant condition prerequisites could not be achieved in mode 4. An Instrumentation and Controls (l&C) department mode change " punch list", which specifically identified the need to enter the action statement, was available in the control room, but was not appended to FORM 2201-1. In addition, the form does not include a formal mechanism by which departments other than Operations signify readiness to change operating mode. The licensee is evaluating changes to the form to

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consolidate uncompleted work and surveillance requirement items in order to facilitate review and identification of outstanding items. The inspector concluded that the licensee's proposed

corrective actions addressed the cause of the incident.

i A similar failure of operators to recognize the need for entry into another TS 3.3.3.8 action statement during this plant startup was identified by the NRC several hours earlier and prior to entry into Mode 3. This finding regarding an inoperable main steam radiation monitor is documented in inspection report 50-336/92-36. However, licensee response to that finding

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was still in progress and did not prevent the problems noted with the other accident monito ig systems. Failure to perform the action requirements of Technical Specification 3.3.3.8 for the PORV valve position acoustic monitors and the RCS subcooled/superheat monitor within the required time is a violation of NRC requirements. However, due to the i

minimal safety significance of missing these required actions and because this problem could not have been reasonably prevented by the previous finding several hours before, the violation is not being cited in accordance with Section VH.B of the NRC Enforcement Policy.

i 3.0 MAINTENANCE (IP 62703)

The inspectors observed and reviewed selected portions of preventive and corrective maintenance activities to verify compliance with regulations, use of administrative control

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procedures and appropriate maintenance procedures, compliance with codes and standards, proper QA/QC involvement, proper use of bypass jumpers and safety tags, adequate

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protection, and appropriate equipment alignment and retest. The inspectors reviewed j

portions of the following work activities:

• M2-93-01561 - Troubleshoot ground on DC bus 201 A

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• M2-93-01401 - Adjust thrust bearing wear detector

• M3-93-01786 - Replace 3 RCS*TY-411B (Loop 1 T-cold RTD amplifier)

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• M3-93-23370 - PM,18 month Limitorque maintenance and its breaker 3 CND-MCCl

• M3-93-00941 - Disassemble, inspect and repair or replace 3 PAS-V009 as needed

• M3-92-24568 - Troubleshoot 3RCS*TY-433D (loop 3 wide range cold leg temperature) to determine cause of repeated failures The inspectors determined the maintenance activities observed were performed well. Details of the inspectors' observations are provided in report sections 3.1 - 3.3.

3.1 Turbine Coupling Inspection - Unit 1 The inspector observed inspection of a coupling located between the power unit assembly and main reduction gear of the Unit 1 gas turbine. The licensee was inspecting this coupling in an effort to locate the source ofincreased gas turbine vibration which resulted in a gas turbine trip during a surveillance run on October 1,1992. The inspection included a visual examination of the visible coupling teeth, and testing the coupling assembly for cracking l

using liquid penetrant non-destructive examination techniques.

Prior to the inspection effort, the inspector verified that the gas turbine was tagged out in accordance with the approved tagout sheet 1-74-93. The inspector noted the nondestructive testing (NDT) technician adhered to the procedure during the portions of the testing of the coupling witnessed by the inspector, including observing the minimum temperature limits for

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l penetrant testing and dwell times. The NDT technician found no relevant indications on the inspected areas of the coupling. Examination of the entire coupling circumference was not possible since the licensee did not have a written procedure available for rotating the gas tmbine in the partially disassembled condition. Following reinstallation of the coupling cever, the licensee performed a leak test of the coupling. The gas turbine started as designed and was declared operable the following day.

The inspector had no questions concerning the performance of the coupling examination.

However, a weakness was noted in the pre-job planning effort. Specifically, the licensee did not ensure a procedure was available for rotating the gas turbine in a disassembled condition prior to initiating the gas turbine coupling examination. The lack of planning prevented full examination of the suspect couplin !

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3.2 Analysis of Gas Turbine Breaker Failure - Unit 1 i

i The gas turbine breaker which failed to close during the December 24,1992, surveillance i

test (see Section 2.2) was examined by the breaker vendor (General Electric) and licensee j

maintenance and engineering personnel on January 27 and 28,1993. Inspection of the

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breaker revealed that a deformed 'H' bracket prevented the breaker from closing. The 'H'

i bracket is located in the breaker tripping mechanism and is used to transfer the force from the trip coil to the breaker closing springs. The bracket was deformed because of a i

misalignment which allowed the bracket to contact the breaker sidewall during operation.

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The misalignment was caused by a combination of worn "Tuf-loc" bushings and a less than optimal alignment of the tripping mechanism when preventative / corrective maintenance was performed on the breaker during the 1987 time period.

According to the vendor representative, industry experience has shown that improved i

performance of the tripping mechanism would be achieved if the alignment of the tripping i

mechanisms are checked and reshimmed following reinstallation. However, rechecking and j

adjusting the tripping mechanism alignment was not a recommended action during the 1987 l

time period. Rather, industry personnel were instructed to reassemble the breaker m reverse

order following disassembly.

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During the breaker inspection effort, other observations were made which included the l

following:

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l The grease installed in the breaker had deteriorated to a hard gummy mixture, which l

failed to lubricate the breaker internals properly, and could slow breaker operation,

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Several General Electric Service Advisory Letters (SALs) issued since 1989 to correct

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e potential denciencies in 4.16 KV breakers had not yet been implemented; and, l

The breaker had never received a complete overhaul. The vendor representative stated that General Electric recommends a complete overhaul every 5-7 years

depending on service life.

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Examination of two spare breakers revealed slight misalignment in the tripping mechanism of j

one breaker. The other breaker was properly aligned; however, the grease on both breakers

was hard. To ensure the other breakers located in the plant were not susceptible to 'H'

bracket failure, the licensee plans to commence a program of breaker removal and j

inspection. Suspect breakers will be evaluated and replaced with repaired spares as necessary. The degradation will then be assessed for reportability as appropriate.

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The inspector considered the licensees's corrective action plan to be adequate based on the information to date. However, the inspector was concemed that the licensee's breaker preventive maintenance program may be inadequate to prevent deterioration of breaker operation. Additionally, the licensee may not have adequately evaluated the General Electric

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Service Advisory letters. This issue is unresolved pending further assessment of the 4.16'

kV breaker preventative maintenance program and evaluation of the results of additional

breaker inspections (URI 50-245/92-33-003).

3.3 125 Volt DC Bus Ground Troubleshooting - Unit 2 f

i On several occasions during the inspection period, the inspector witnessed licensee

troubleshooting activities related to an electrical ground on safety-related DC bus 201 A. The

condition has existed since approximately January 14. The licensee developed a detailed ground isolation plan. This plan included thorough system walkdowns and prioritization for deenergizing individual loads based on the potential for causing a plant transient and Technical Specification operability considerations. Maintenance electricians and electrical engineers reviewed loop diagrams and system drawings and discussed the operational impact with the shift supervisor prior to deenergizing each component. A detailed log of system

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responses and findings was maintained. The

.:nsee intends to use the findings to enhance operator guidance concerning the consequences of a loss of DC power to individual circuits.

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On January 27, the normally deenergized charging pumps started unexpectedly when fuses associated with a pressurizer level alarm annunciator were pulled. Operators promptly responded by verifying that the start was not the result of a valid pressurizer level decrease

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or engineered safeguards actuation signal, and secured the pumps. The occurrence was l

determined not to be reportable to the NRC per 10 CFR 50.72 or 10 CFR 50.73 because the pressurizer level control system actuation of the charging pumps is not considered to be part

of the engineered safety features actuation system. Troubleshooting was suspended until the

cause was identified. The licensee subsequently determined that the loop diagram for the

fuse circuit was in error in that relay contacts shown as spares were actually connected to the

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pump start circuit. A drawing change request was initiated to correct the error.

The inspector concluded that the licensee had developed a good troubleshooting plan and that the evolution was conducted properly and safely. Communication and coordination among the departments involved in the effort were excellent.

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4.0 SURVEILLANCE (IP 61726)

The inspectors observed and reviewed selected portions of surveillance tests, and reviewed test data, to verify compliance with test procedures and Technical Specification limiting conditions for operation. The inspector also verified proper removal and restoration of equipment, and adequate review and resolution of test deficiencies. The inspector reviewed i

portions of the following tests:

• SP 408J Condenser low Vacuum Scram Functional and Calibration Test

• SP 412L Isolation Condenser Isolation Instrument Functional Test / Calibration

• SP 2604H Containment Sump Outlet Isolation Valve Operability Test, Facility 2

• SP 2651Q Hydraulic Thrust Wear Detecter Test

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r e SP 2401E Calibration of Excore Nuclear Instruments to Incores I

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The inspectors determined that the surveillance activities observed were performed well.

Details of the inspectors' observations are provided in report sections 4.1 - 4.3.

l 4.1 Isolation Condenser Instrumentation Functional Test / Calibration-Unit 1 l

The inspector observed Unit 1 Instrumentation and Control (I&C) technicians test the isolation condenser isolation logic per procedure SP-412L, " Isolation Condenser Isolation Instrument Functional Test / Calibration." This test is performed monthly by the I&C department and typically involves the use of four I&C technicians and two operators. This

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particular surveillance was also observed by a quality services department inspector and an

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I&C supervisor as part of the licensee field observation program.

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t During the test, the inspector verified that adequate controls were placed on contacts which were bypassed, the appropriate Limiting Condition for Operation (LCO) action statement was i

entered when the isolation condenser was rendered inoperable, and procedures were followed. The inspector also verified that the surveillance procedure tests the isolation j

condenser at the frequency required in plant TS and is listed in procedure ACP 9.02A,

" Surveillance Master Test Control List," as the proper procedure for testing the containment

isolation functions of the isolation condenser.

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The inspector did not identify any inadequacies during the performance of the surveihance l

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procedure. However, the inspector noted that the I&C technicians did not completely review

all the requirements contained on the Automated Work Order (AWO) which authorized performance of the test. Specifically, the inspector noted that the AWO contained a caution which referred to Justification for Continued Operation (JCO) 1-91-1. The JCO cautions that

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changing the layout or alignment of this system can invalic ite the high pressure line break safety analysis. However, neither technician who performed the test knew what was contained in the JCO or had asked their supervisor for guidance concerning its status. The inspector reviewed the JCO and concluded that this generic caution was not necessarily germane to the performance of this surveillance. Nevertheless, the inspector concluded that the technicians should have asked questions concerning the caution statement contained in the AWO it case the JCO was relevant. The inspector discussed this observation with the I&C manager who acknowledged that the technicians should have read and understood the caution statement contained in the AWO. The I&C manager discussed the importance of reviewing i

the requirements contained in AWOs with the I&C department in weekly training. The inspector determined that this action was appropriate.

4.2 Implementation of Limiting Conditions for Operation During Surveillance Testing and Maintenance - Unit 2 While observing surveillance testing and maintenance at Millstone 2, the inspector noted that l

the licensee did not enter the applicable Technical Specification (TS) limiting condition for

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operation action statement while equipment was inoperable. This practice could result m failure to confirm the condition of or to maintain redundant equipment operable while the

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activity is taking place. In addition, the potential existed that the Technical Specification

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allowed outage time could be exceeded if the equipment being tested failed a surveillance

test. Regarding surveillance tests, the inspector observed that the action statements of TS

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l 3.3.1.1, " Reactor Protective Instrumentation," were not entered during the performance of excore nuclear instrument calibrations per procedure SP-2401E, " Calibration of Excore Nuclear Instruments to Incores." This procedure bypasses the trip functions of the thermal margin / low pressure, turbine trip, variable high power, and local power density protective instruments. The inspector also noted that the action statement of TS 3.7.4.1, " Service

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Water System," was not entered while the 'C' service water pump was inoperable and

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undergoing post-maintenance testing, supplying 'B' train components. The automatic start feature of the operable swing 'B' service water pump, which was aligned to the 'B' header,

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was locked out during this period. Finally, the inspector noted that the ECCS Subsystems

action statement of TS 3.5.2.a. is not entered when high pressure safety injection (HPSI)

system throttle valves are shut to fill safety injection tanks with a HPSI pump. While the

valves receive an open signal by design on initiation of a safety injection actuation signal, the

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licensee was unable to identify a procedure which tests this function. The inspector noted, l

however, that the procedure verifies proper restoration of the valves in accordance with the

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TS. The inspector found no instances in which the TS allowed outage times were exceeded.

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In addition, the licensee does enter TS action statements during surveillance or maintenance

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on other systems (e.g. radiation monitors and emergency diesel generators).

As documented in Generic Letter 91-18, "Information To Licensees Regarding Two NRC Inspection Manual Sections On Resolution Of Degraded And Nonconforming Conditions and i

Operability," the NRC position is that unless specifically permitted otherwise, the TS limiting condition for operation action statements shall be entered when equipment is removed from service and rendered incapable of perfornJM its safety function. The inspector discussed TS usage with the operations department manager who observed that this position was contrary in many cases to normal practice at Millstone Unit 2. The licensee position, in part, was that personnel performing a surveillance were capable of quickly restoring the affected equipment to service if called upon. The inspector considered that this philosophy did not satisfy the intent of the TS since operator action in many cases does not replicate the designed automatic protection. The licensee is reviewing its practices for conformance with the generic letter. This issue is unresolved pending NRC review of the licensee's evaluation l

(URI 50-245/92-29-004).

4.3 Containment Sump Isolation Valve Testing - Unit 2 On January 29,1993, the licensee performed monthly surveillance procedure SP-2604H,

" Containment Sump Outlet Isolation Valve Operability Test, Facility 2." The test verifies that the sump valve opens automatically upon receipt of a sump recirculation actuation signal (SRAS) from the engineered safeguards actuation system (ESAS). The test is performed by depressing SRAS test pushbuttons on certain ESAS sensor and actuation modules, and

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verifying that the appropriate bistable modules trip and that the valve opens fully. During the test, the operator observed an unanticipated trip of an additional bistable module. No other safety equipment was affected. The operators initiated a plant incident report (PIR)

and contacted the Instrumentation and Controls (l&C) department to determine whether a recent modification to the SRAS logic system was responsible for the unexpected response.

l The system was restored to service properly in accordance with the procedure.

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f Through discussions with I&C department personnel, the inspector determined that the ESAS response to a SRAS had changed as a result of the modification and that the equipment response was normal. The inspector noted that the current revision of SP-2604H was dated prior to installation of the modification and questioned whether this and other applicable

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procedures had been reviewed prior to declaring the ESAS operational. These procedures l

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included OP-2384, " Engineered Safeguards Actuation System;" SP-2604I, " Engineered Safeguards Features Actuation System Automatic Logic Check Using the Automatic Test

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Insert;" and SP-2604G, * Containment Sump Outlet Isolation Valve Operability Test, Facility

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The licensee responded that the procedures had been reviewed and changed as necessary prior plant startup, but that the need to revise SP-2604G and SP-2604H had been missed.

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The licensee further noted that the test had been performed previously and the unexpected

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response had not been identified on those occasions. The licensee is investigating this matter

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as part of the PIR process. This item is unresolved pending NRC review of the PIR (URI

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50-336/92-35-005).

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5.0 ENGINEERING /TECIINICAL SUPPORT (IP 92702)

t 5.1 Inadequate Overlap Testing - Unit 3

On January 26, 093, at 2:30 p.m. with the plant at 100 percent power, the licensee

identified that the channel calibration procedure for the nuclear instrumentation system (NIS)

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l channels did not fully implement the requirements of the Technical Specifications (TS). The

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l TS require that overlap testing be performed as part of a channel calibration every 18 i

months. The NIS power range channel calibration procedures did not monitor the upper and

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lower flux output (voltage signals) to the Westinghouse 7300 process control system which calculates the setpoint for the variable over emperature delta-T (OTDT) reactor trip signal.

The licensee declared the OTDT instruments inoperable and entered T c 3.0.3/4.0.3. The l

surveillance procedures were modified, the four instrument channels were satisfactorily tested, and the TS action statement was exited within the 24-hour grace period allowed by TS

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l 4.0.3. The licensee determined the event to be reportable in accordance with 10 CFR

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l 50.73(a)(2)(i).

Another overlap testing deficiency was identified by the licensee in August 1991. The

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operation of the comparator trip switch auxiliary contact, which blocks transmission of the

containment depressurization actuation (CDA) signal, was not being verified (reference Unit

'11 w processing of a CDA l

3 license event report (LER)91-022). This contact is in series '

signal from the Westinghouse 7300 instrument mck to the solid state, cotection system

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(SSPS). The vendor protection channel testing instructions, which were submitted to plant management prior to initial startup, had not been distributed to the I&C department proce-l dure writers for incorporation. As a result of this deficiency, the licensee committed to:

1) review other I&C department procedures versus the vendor operating instructions t

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(commitment #300291) and 2) verify adequate overlap testing between the Westinghouse

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7300 instrument rack and the SSPS to determine if similar deficiencies existed (commitment

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1. 3-91-0161). The licensee completed these reviews in February 1992. None of the additional deficiencies identified compromised TS or Final Safety Analysis Report (FSAR)

e operability requirements. As a product of commitment #300291, the licensee identified additional vendor documents (the vender startup manual procedure and its referenced i

documents) to be reviewed. A new commitment, #3-92-0033, to review these documents is i

scheduled to be completed by March 1993.

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On Friday, January 22 an instrument and control (l&C) engineering specialist was reviewing

vendor operating instruction " Nuclear Instrumentation System Reactor Trip Channels," as

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part of commitment #3-92-0033. During the review, the specialist identified that there appeared to be no overlap testing between the NIS and the 7300 instrument racks. The

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technician brought this concern to the attention of his supervisor. He was concerned that the NIS flux signals (voltage signals) are prone to problems with attenuation, ground loops, and i

noise; and there is no direct indication of signal transmission quality. The technician also

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stated that, although some functional testing has been accomplished by the reactor trip

system response time test, the signal quality has never been verified.

l The I&C supervisor requested that the individual document the concern to support further j

review to ascertain if the cabling under question was tested under some other surveillance l

procedure. The supervisor believed that the OTDT system remained operable based upon the

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time response testing which verified continuity. Also, a failure in one of the flux signals l

would result in an indicated reactor core power tilt. This tilt would be indicated by the

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power range channel deviation alarm or the power range hi/ low detector high flux deviation

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annunciators. In addition, the I&C department procedures had been reviewed against the

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applicable vendor operating instructions for adequacy in February 1992 as part of

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commitment #300291. Therefore, the I&C supervisor determined that this was not an urgent

safety matter.

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On January 26, after subsequent review of the overlap testing concern, the licensee was

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l unable to identify adequate testing of the subject cabling and issued a plant incident report.

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l As corrective action, the licensee modified the quarterly power range channel operational test

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procedures and stated that the eighteen month calibration procedures would also be corrected.

The quarterly operational test was performed on January 26 and demonstrated satisfactory transmission of the flux signals. The licensee attributed the missed surveillance to an i

oversight in the initial vendor operating procedure review and stated that the emphasis of the l

l review was not directed towards overlap testing but to ensure that all vendor testing proce-l dures were encompassed by I&C department procedures.

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The inspector reviewed the change to the quarterly power range channel operating procedure

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and concluded that the test methodology adequately tested the transmission of the flux

signals. The inspector reviewed the LERs for the past two years to determine if similar overlap testing deficiencies had been identified and noted that the licensee has identified a

total of four overlap testing deficiencies; the two referenced above plus two identified during

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the licensees' procedure re-write program. Licensee event report (LER) 91-25 identified that the deenergization of input relays for the cold overpressurization protection system was not

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verified during channel calibration. These input relays process an actuation signal from the l

Westinghouse 7300 instrument racks to the SSPS. LER 92-31 identified that two SSPS

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l output relays driven from the 7300 process control system for the power operated relief

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ulves actuation were not tested. In each case the operability of the relays was subsequently

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verified by either testing or actuatica.

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The I&C systems are designed to provide automatic protection and exercise proper control

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against unsafe and improper reactor operation by providing initiating signals to mitigate the l

consequences of faulted conditions. The instrumentation channels which supply these functions are divided into three sections; instrumentation systems, process control systems

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(7300 cabinet), and the solid state protection system. The licensee stated that overlap testing between the 7300 cabinet and the input relays of the SSPS has been reviewed as part of

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commitment 3-91-0161. The licensee also stated that they have two outstanding commit-l

ments; one to verify adequacy of testing between the sensing device to the 7300 instrument

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rack and another to verify adequacy from the output relays of the SSPS to the activating

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devices. The first commitment is scheduled to be completed by March 1993 and the second i

should be completed by the end of the next Unit 3 refuel outage scheduled for July 1993.

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As part of the performance enhancement program, the licensee is in the process of re-writing all their technical procedures in accordance with the procedure writing manual. Volume two,

" Verification and Validation Procedure," requires that a technical review be performed. This j

review requires that all TS, FSAR requirements and NRC commitments be addressed. To

provide a documented basis for this review, I&C department Form 176 was generated. This

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form specifies that a review for overlap testing be accomplished to verify that the entire

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instrument loop is tested from sensing device to output device.

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The licensee acknowledged that there have been overlap testing deficiencies. They believe that their continuing effort to upgrade plant procedures in conjunction with the two continuing corrective actions identified in the specified LERs will correct the deficiencies in overlap testing.

Although the flux signals were not tested on the eighteen month channel calibration frequency, the subsequent testing verified that they were functional. Additionally, th., reactor trip system response time testing, which is performed at least once every 72 months for each channel (i.e. one of the 4 channels is tested every 18 months) verifies continuity of these signals. Based on these factors, the failure to verify continuity of the NlS flux signal to the 7300 instrument racks, as part of the 18 month channel calibration, did not result in a

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i significant safety consequence. The inspector acknowledged that there are two outstanding commitments which are designed to identify overlap testing deficiencies in addition to the

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l procedure rewrite program. The NRC will access the licensee root cause and corrective actions during NRC review of the licensee event report for this incident.

t 6.0 SAFETY ASSESSMENT / QUALITY VERIFICATION (IP 40500,90712,92700)

6.1 Review of Written Reports l

l The inspector reviewed periodic reports, special reports, and Licensee Event Reports (LERs)

l for root cause and safety significance determinations and adequacy of corrective action. The inspectors determined whether further information was required and verified that the

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reporting requirements of 10 CFR 50.73, station administrative and operating procedures, and technical specifications 6.6 and 6.9 had been met. The following reports and LERs were reviewed:

Unit 1 Monthly Operating Report for December 1992, dated January 11, 1993.

Unit 1 Licensee Event Report 92-028-00, Reactor Scram due to Inadvertent MSIV

Switch Closure.

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Unit 1 Licensee Event Report 92-30-00, Feedwater Flow Transmitters Failures Cause

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Reactor Power License Limits to be Exceeded.

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Unit 2 Monthly Operating Report for December 1992, dated January 11, 1993.

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Unit 3 Monthly Operating Report for December 1992, dated January 11,1993.

• The inspectors did not identify any deficiencies with the content and timeliness of these reports.

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6.2 Potential Inadequate Core Cooling - 10 CFR Part 21 - Unit 3 l

In a December 9,1992, letter to the NRC, Westinghouse identified a potential inadequate core cooling flow condition resulting from isolation af the residual heat removal / low head safety injection (RHR/LHSI) system pumps from the reactor coolant system (RCS) when attempting to aF n them to the RCS hot legs. Specifically, it was identified that for some

plants, a single valve failure could block of RHR/LHSI flow to the core when attempting to align to the hot leg recirculation mode of core cooling. This realignment typically is required to begin eight to twenty-four hours following a postulated loss of coolant accident (LOCA). However, plant specific emergency operating procedures (EOPs) or operator training may not advise the operator to realign the RHR/LHSI system back to the RCS cold legs and thus mitigate the event. Continued loss of flow could result in exceeding the criteria of 10 CFR 50.46 for LOCAs analyzed as part of the licensing basis.

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The inspector discussed the issue with the licensee to determine if adequate guidance is

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provided to the operators for mitigating this event. The licensee stated that they have reviewed the applicable emergency operating procedures (EOPs) and do not believe this issue i

is a concern for Unit 3. As a result of containment recirculation cooler tube vibration concerns identified during initial start-up, Unit 3 revised the flow lineup for the hot leg recirculation mode of core cooling. This change discontinued using containment recirculation pump flow via the RHR/LHSI system to the RCS during the hot leg recirculation phase of an accident. Flow is now provided to the core via the charging and high pressure safety injection systems. Thus the failure of the subject RHR/LHSI motor i

operated valve to the hot leg header to open is not a primary safety concern.

The inspector reviewed EOP 35 E-1, " Loss of Reactor or Secondary Coolant," and EOP ES-

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1.4, " Transfer to Hot Leg Recirculation," and concluded that, for the reasons stated above, this issue does not appear to be a concern at Unit 3. The inspector had no further questions.

6.3 Feedwater Flow Transmitters Out of Calibration - Unit 1 LER 92-030

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On December 8,1992, the licensee determined that two out of the four feedwater flow instruments at Millstone Unit I were out of calibration and showed feedwater flow to be less than actual flow. This occurrence resulted in a non-conservative heat balance equation and

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caused the licensee to exceed the licensed power limit of 2011 megawatts thermal (MwTh)

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by 0.6 percent or 14 MwTh. Prior to discovery of the overpower condition, the licensee had been investigating a small increase in plant efficiency. Close examination of the feedwater s

flow transmitters was initially not considered since the transmitters were in close agreement

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with each other and they had been recently calibrated.

Troubleshooting of the feedwater transmitters revealed that one transmitter was out-of-calibration because of a failed capacitor in a power supply. The other transmitter was out-of-calibration because ofinstrument drift. The licensee determined that the amount of error due to the out-of-calibration transmitters was within the assumed error contained in the plant

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safety analyses.

To correct the problem, the licensee fixed the power supply and recalibrated both feedwater flow instruments. Additionally, the performance of the feedwater flow transmitters will now be checked weekly and calibration checks will be performed as required. The licensee reported this event in Licensee Event Report 50-245/92-30 under 50.73(a)(2)i(B), any operation or condition prohibited by plant Technical Specifications.

The inspector reviewed the licensee event report and corrective action which was found to be appropriate to prevent recurrence. The safety significance of this event was minor; no previous occurrences of this problem were noted. Therefore, enforcement discretion was exercised in accordance with section VII.B of the NRC Enforcement Polic.

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7.0 MANAGEMENT MEETINGS

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Periodic meetings were held with station management to discuss inspection findings during i

the inspection period. Following the inspection, an exit meeting was held on February 12, 1993 to discuss the inspection findings and observations. No proprietary information was

covered within the scope of the inspection. No written material regarding the inspection findings was given to the licensee during the inspection period.

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