IR 05000309/1988001

Insp Rept 50-309/88-01 on 880101-0203.Violations Noted.Major Areas Inspected:Control Room,Accessible Parts of Plant Structures,Plant Operations,Radiation Protection,Physical Security,Fire Protection,Plant Operating Records & Maint

ML20149N016
Person / Time
Site:	Maine Yankee
Issue date:	02/23/1988
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20149N009	List: IR 05000309/1988001 ML20149N008
References
50-309-88-01, 50-309-88-1, NUDOCS 8802290391
Download: ML20149N016 (8)

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U.S. NUCLEAR REGULATORY COMMISSION Region I Docket / Report: 50-309/88-01 License: DPR-36 Licensee: Maine Yankee Atomic Power Inspection At: Wiscasset, Maine Dates: January 1,1988 to February 3,1988

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Inspectors: Cornelius F. Holden, Senior Resident Inspector Richard J. Freudenberger, Resident Inspector .

Approved By: / ' *

LV Tripp, ef, Reactor Projects Section 3A ' date Summary: Inspection on January 1,1988 to February 3,1988 (Report N /88-01)

Areas Inspected: Routine resident inspection (87 hours0.00101 days <br />0.0242 hours <br />1.438492e-4 weeks <br />3.31035e-5 months <br />) of the control room, accessible parts of plant structures, plant operations, radiation protection, physical security, fire protection, plant operating records, maintenance and surveillanc Results: Two licensee identified violations were identified. These involved a failure to calibrate the post accident containment hydrogen detector within the required six month interval (Detail 3.e) and valves that were not locked in position as required by Technical Specifications (Detail 9), although all the affected valves were in the correct operating position. An unresolved item involving a nonconservative bias in the calorimetric calculations used to determine reactor power levels is discussed in Detail l h$k OO 09

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DETAILS . Persons Contacted Within this report period, interviews and discussions were conducted with various licensee personnel, including plant operators, maintenance tech-nicians and the licensee's management staf . Summary of Facilitr Activities '

t The plant was operating at 100 percent power at the beginning of the re-port period. At 2:53 a.m. on January 5, the reactor tripped from full power. The cause of the trip was determined to be *i failed level switch for the heater drain tan Tu plant was returned to full power en January On January 27, reactor power was adjusted to compensate for art error identified in the calcritaetric used to determine reactor power level. Power was reduced to 75 percent on February 3 to allow for secondary plant maintenance. The plant was at 75 percent power at the end of the report perio . Routine Periodic Inspections Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures and LCO's, instrument nion,

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recorder traces, protective systems, control rod positions, con-tainment pressure, control room annunciators, radiation monitors, emergency power source operability, control room legs, shif t super-visor logs, and operating order Backshift inspections were con-ducted on January 23 and 3 System Alignment inspection Operating confirmation was made of selected portions of the high pressure safety injection system (HPSI). Accessible valve positions and status were examined. Power supply and breaker alignment was checke Visual inspection of major components was perforee Operability of instruments essential to system performance was i

assessed No deficiencies were identified, Biweekly Inspections l During plant tours, the inspector observed shift turnovers, chemistry

sample results and the use of radiation work permits and Health Physics procedures. Area radiation and air monitor use and opera-

, tional status was reviewed. Plant housekeeping and cleanliness were evaluate ,

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, Plant Maintenance

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The inspector observed and reviewed maintenance and problem inves- !

tigation activities to verify compliance with regulations, admini- '

strative and maintenance procedures, codes and standards, proper ;

QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, radiological controls for worker protec- t tion, fire protection, retest requirements, and reportability per Technical Specifications. The inspector witnessed portions of the i repairs tc the liquid waste radiation monitoring syste Samples were taken in accordance with the Remedial Action statements of the Technical Specifications. No deficiencies were note '

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e. Surveillance Testing i

The inspector observed parts of tests to assess performance in ac-cordance with approved procedures and LCO's, test results, removal and restoration of equipment, and deficiency review and resolutio ,

Included in this review was an observation of portions of the monthly reactor protection system surveillance tests. The inspector noted that the Instrument and Controls technicians were knowledgeable of the test procedures they were to perform, were attentive to the identification and resolution of minor daficiencies with the opera-tion of the equipment, and communicated well with the control room operators on shift to keep them appraised of the status of the

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reactor protection syste No deficiencies were identified by this l revie .

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On January 12, the licensee identified that the time interval for the performance of Surveillance Procedure 3-6.2.1.36 "Post Accident Containment Vent System, Containment H2 Detector" was exceeded for the Comsip hydrogen analyzer. The surveillance procedure is a t calibration of the post accident containment hydrogen detector and j

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is required to be performed at a six month interva It was not ,

performed due to a scheduling erro !

There is a Preventive Maintenance (PM) procedure which is performed l on the hydrogen analyzers at a five year interval to meet equipment ,

qualification requirements. Both the equipment qualification PM and l

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the calibration surveillance were scheduled to occur on November 23, -

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1937, in order to reduce the downtime for the equiptrent; however, parts necessary for the completion of the equipment qualification PM were not available and both jobs were delayed. The delay of the PM procedure was reviewed to ensure equipment qualification requirements would not be exceeded prior to the acquisition of the necessary '

part To allow the surveillance procedure to be delayed and per- I formed simultaneously with the PM activities, it was decided that a "

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portion of the 25 percent extension of the surveillance interval would be used. 'The maxiLium interval for the surveillance ended' on January 7. - 0n January 12, the licensea ' discovered that the _ sur-veillance procedure had not yet been completed. The Comsip . hydrogen analyzer was declared inoperable as of January 7 and the surveillance procedure was performed on January 1 There are two hydrogen monitors installed for containment hydrogen monitorin The second, a Bendix hydrogen analyzer was operable throughout this time perio The Technical Specifications for the operability of accident monitoring instrumentation require that one channel of the Containment Hydrogen Monitor be operable, therefore the requirement was met at all time The root cause of the missed surveillance appeared to be poor coordination between the maintenance and instrument and controls departments in schedulino the work. The licensee conducted the surveillance within one day of determining it had been missed. The licensee also utilizes a program called Co-ordination Improvement Opportunity (CIO) which reviews situations such as these to effect long term corrective action. The licensee is studying this event to determine its applicability to the CIO syste Since the licensee identified that the surveillance procedure was not completed as required by the Technical Specifications and this con-ditions meets the criteria to be considered a licensee identified violation, in accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix _C, no Notice of Violation will be issue .

f. Reactor Trip from Full Power On January 5, the plant tripped from full power. The cause of the reactor trip was loss of load. The turbine generator tripped on the trip of the steam driven main feedwater pump (P-20) as expecte The main feedwater pump trip was caused by a sustained low suction pressure condition. The suction pressure to P-2C decreased when the running heater drain pump tripped and the standby pump failed to auto-start. An operator attempted to start the standby pump manually from the control board, however it failed to operate. Plant systems

responded normally to the tri It was determined that the heater drain pumps would not operate be-cause the level switch which trips the pumps on low heater drain tank level faile The switch, Jo-Bell model CB-300STD, consists of a float which activates a magnetic reed switch. The float was found

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to have perforations as the result of corrosion in the area sur-

! round',g a welded sea The perforations allowed water to ente the float causing it to sink. This resulted in the level indicated by the switch to indicate a level lower than that of the low level trip setpoint for the heater drain tank pump Since this instrument supplies both pumps, the f ailure of this switch caused the running pump to trip and prevented the standby pump from operatin The failure of the heater drain tank level switch was determined to be the root cause of the plant tri . - _ . -

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The licensee identified all similar float type switches that have a control function throughout the plant. . An inspection .to verify the condition of these switches is being conducted _ and all floats are being replaced. The~. licensee has; incorporated . float type ' level switches into the preventive maintenance program. . Based on the in-spectors review of this trip, the operators response was judged to be very good. .With the incorporation of expanded preventive main-tenance for the float type level switches the root cause for this-plant trip should be resolve The inspector had no: further ques-tion Loss of Normal Communications On January 7, at 2:54.p.m. the control room was notified that the New England Telephone Company line to the plant was out of service. The Maine Emergency Management Agency (MEMA) and '1/to Maine State Police phone lines were tested and found to be out of service also. By 3:30 p.m. MEMA and the Maine State Police had been centacted via microwave

. patched to land lines from the corporate offices in Augusta. This condition was determined to be reportable to the NRC. When at-tempting to contact the NRC, the Emergency Notification System was ,

found to be out of service also. The NRC operations center was contacted at approximately 3:35 p.m., using the same method that was used to contact MEMA and the Maine State Police. Normal communi- -

cations were fully restored by 5:55 p.m. The NRC, MEMA and the Maine State Police were informed of the restoration of the lines by 6:05

, . Observations of Physical Security Checks were made to determine whether security conditiens met regulatory requirements, the Physical Security Plan, and approved procedures. Those checks included security staffing, protected and vital area barriers, vehicle searches and personnel identification, access control, badging, and compensatory measures when required.

' Radiological Controls

Radiological controls were observed on a routine basis during the re-i porting perio Standard industry radiclogical work practices, conform-L ance to radiological control procedures and 10 CFR Part 20 requirements

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were observe Independent surveys of radiological boundaries and random surveys of nonradiological points throughout the facility were taken by the inspecto . Calorimetric Adjustment As pa.- of an ongoing Margin Reduction Program, Yankee Nuclear Services Division (YNSD) of Yankee Atomic Electric Company (YAEC), had an effort underway to characterize the uncertainties associated with Maine Yankee's

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calorimetric calculatio YNSU identified a span shift associated with the Rosemount model 11510P6E22 and 1151DP5E22 differential pressure transmitters associated with the steam flow and feed flow inputs to the calorimetric calculations. These transmitters were installed in May 198 The transmitters previously used in this application did not exhibit the span shif t effect, thereTare, this effect had not been considered in the calorimetric calculations. This resulted in a non-conservative bias being introduced into the calorimetric when the Rosemount transmitters were installed. The licensee was notified of the bias associated with the calorimetric and, af ter a preliminary review of the information, a Plant Operation Review Committee (PORC) meeting was held on January 27 to de-termine the actions to be take The offset due to the span shif t was estimated to result in a bias that caused the calorimetric to indicate slightly less than one percent lower than actual reactor powe PORC recommended that reactor power be reduced from 2630 MW to 2600 MW (ap-proximately 1.1 *4) , the necessary changes be made to the calorimetric calculations, and reactor power then be increased to full power based on the revised calorimetric. The adjustment to the calorimetric calculation resulted in a deviation of approximately 22 megawatts which is equivalent to 0.84 percent reoctor powe The licensee is performing an assessment of the impact of this error in the calorimetric calculation. The inspector will review this assessment upon completion. A determination of the safety impact of the error on plant operations since the replacement of the transmitters will be made at that tim This 1. sue is unresolved pending further review (UNR

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50-309/88-01-01).

7. Control Element Drive Mechanism Difficulties During this report period there were four eximples of difficulties with the control element drive mechanisms (CEDW s).

On January 5, the licensee was conducting t:st trip testing of the reactor trip breaker This prc:edure requires that the shutdown groups be withdrawn to eight steps and then the reactor trip breakers are opened to verify that the CEA's drop and the trip breakers have functioned properl CEA 47 did not drop to rod bottom indication when its group was teste The CEA did drop fully into the core from its full out position of 179 steps on the reactor trip earlier in the day, therefore the CEA was con-sidered operable. The licensee concluded that CEA 47 did not possess sufficient inertia when dropped from low levels to drop fully into the core. The cause of the sticking of the CEA was estimated to be due to minor binding or crud buildup in the dashpot. The CEA was withdrawn to nine steps and driven to rod bottom indication six times to clear any crud buildup, and then withdrawn and drop tested successfully three times; there' ore, the crud was assumed to be cleared f rom the dashpo . _ . - _ .-. . __. .

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.Later in the day, while withdrawing the shutdown groups in preparation for

.a reactor startup, CEA 53 remained fully inserted as the rest of its grou was withdrawn to .approxinately 14 steps. 'An instrument and controls technician identified a problem with the upper gripper module which .was subsequently replaced returning the CEA to service. Since this CEA was fully inserted, it was con.sidered operable at all time On January 19, during CEA exercises, CEA 34 dropped to fully inserte The CEA was recovered.within five minutes. Reactor parameters were verified to be within limits throughout and after the recovery of the CE .

On February 3, with the plant at 75 percent power for balance of plant mainter nce, regulating group 5 CEA's were adjusted due to low symmetric -

offset. 'CEA 55 dropped to approximately 140 steps. The operator at-tempted to withdraw the CEA cau:ing it to drop to the fully inserted positio The operatc^ was able to fully withdraw the rod within ten minutes. Reactor parameters were verified to be within limits during and following the recovery of the CE ;

In response to these and previous difficulties with the Control Element Drive System, the licensee has implemented an action plan to assess the reliability and operation of the system. The inspectors will review this plan in followup inspectioa . Management Reorganiza.'. ion

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In a submittal dated January 6, 1988, the licensee described a revised management structure which adjusted beth the spans of control and the onsite and offsite reporting chains. A preliminary review of the licen-see's submittal was conducted by the Region I Office and the Office of Nuclear Reactor Regulation. This preliminary review identified no de-ficiencies. The restructuring was implemented on January 15, 1988. Based

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on the above review, the NRC Region I Director, Division of Reactor Projects eiscted not to pursue enforcement at this tim The associated ,

Technical Specification review is receiving expedited revie . Control of ECCS Valves During a routine review of Surveillance Procedure 3.1.2 "ECCS Routine Testing," the licensee identified several valves that were listed as Emergency Core Cooling System (ECCS) valves, which were not required to be locked by the procedur The valves are associated with the Primary and Secondary Component Cooling Systems' (PCC and SCC) Nat exchanger It was also identified that the service water (SW) valves which isolate the Service Water System from the PCC and SCC heat exchangers were not included in the procedure. All the valves were in the proper position for system operations, however, they were not locked in position as required by the plant Technical Specifications, section A temporary procedure change was written to lock the valves and incorporate them into the sur-veillance procedure. Further evaluation of the need to lock these valves

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and the impact on the operation of the system is in progress. Since the licensee identified this condition and this condition meets the criteria to be considered a licensee identified violation, in accordance with the

"General Statement of Policy and Procedure for NRC Enforcement Actions,"

10 CFR Part 2, Appendix C, no Notice of Violation will be issue ,

10. Exit Interview Meetings were periodically held with senior facility management to discuss the inspection scope and findings. A summary of findings for the report period was also discussed at the conclusion of the inspectio .

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