IR 05000309/1986005

Insp Rept 50-309/86-05 on 860331-0510.No Violations Noted. Major Areas Inspected:Control Room,Radiation Protection, Training,Physical Security,Fire Protection,Maint & Surveillance & Accessible Parts of Plant Structures

ML20198K122
Person / Time
Site:	Maine Yankee
Issue date:	05/22/1986
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20198K111	List: IR 05000309/1986005 ML20198K105
References
TASK-2.E.1.1, TASK-TM 50-309-86-05, 50-309-86-5, NUDOCS 8606030344
Download: ML20198K122 (10)

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U.S. NUCLEAR REGULATORY COMMISSION ,

REGION I i Docket / Report: 50-309/86-05 License: DPR-36 ,

Licensee: Maine Yankee Atomic Power Inspection At: Wiscasset, Maine i

Dates: March 31, 1986 - May 10, 1986 Inspectors: Cornelius F. Holden, Senior Resident Inspector Jeffrey Robertson, Resident Inspector D vid Li roth, Project Engineer Approved: b. h ll/. E. Tr%fp, Chief, Reactor Projects Section 3A fG[Wfo

' Ddte Summary: Inspection on March 31 - May 10, 1986 (Report No. 50-309/86-05 Areas Inspected: Routine resident inspection (307 hrs) of the control room, ac-cessible parts of plant structures, plant operations, radiation protection, train-ing, physical security, fire protection, plant operating records, maintenance and surveillanc Results: One plant trip during this period was caused by problems with the gover-nor control on the steam driven main feed pump (Section 4.f). Licensee management conservatively kept the plant shutdown until the #3 interver was repaired rather than operate the plant with the 120 VAC vital buses cross-connected (Section 4.g).

The post trip review by the licensee identified the problem as a malfunction of the steam driven main feed pump pressure control valve. Similar problems with the pressure controller were observed ten days later (Section 4.h). The licensee iden-tified a print control problem for steam generator level instrumentation that did not impact on operability of the instrumentation involved (Section 8).

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DETAILS 1. Persons Contacted Within this report period, interviews and discussions were conducted with various licensee personnel, including plant operators, maintenance technicians and the licensee's management staf . Summary of Facility Activities At the start of the reporting period the plant was operating at approximately 97 percent power. A limit of 98.8 percent power was being maintained (since 3/17/86) due to concerns over generator vibration The plant was shutdown on April 16 in order to balance and shim the main generato Upon return to power on April 17, while switching from electric driven main feed pumps.to the turbine driven main feed pump, the plant tripped from 55 percent power. High level in #3 steam generator caused a turbine and reactor trip. The licensee identified the problem in the governor control on the steam driven main feed pump. The plant remained in shutdown until April 18 to repair #3 inverter which grounded on April 1 The plant reduced power on April 24 for routine surveillance of turbine valves and returned to full power later that same day. On April 27, the plant re-duced power to 72 percent and switched to electric driven main feedwater pumps after observing problems with the steam driven feedwater pump controlle The plant returned to 97 percent power (the maximum power while running elec-tric driven feedwater pumps) and with the exception of a brief reduction in power on April 29 because of grid problems, the plant remained at 97 percent power until the end of the inspection perio . Follow-up on Previous Inspection Findings (Closed) Inspector Follow Item (50-309/80-17-03). Heat Tracing Alarm is normally in alarm. The licensee has instituted interim corrective actions which require auxiliary operators to log heat tracing alarms and submit deficiency reports on abnormal alarm A conceptual design pack-age has been initiated to correct the seal-in feature of the heat tracing alarm and allow follow-on alarms to sound in the control room. The in-spector will review modifications of the heat tracing system during the Cycle 9 - 10 refueling outag (Closed) Inspector Follow Item (50-309/82-18-02). Instrument error analysis for Type B and C leak tests. The inspector verified that the instrument error analysis for Type B and C tests was included in the 1985 Containment Integrated Leak Rate Report dated January 7, 198 The in-strument error analysis for the Type A test was inadvertently omitted from the test report and was submitted March 20, 198 ,. . . .

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3 (Closed) IE Bulletin (50-309/83-BU-03). Check valve failures in raw water cooling systems of diesel generators (OG). The Primary and Secon-dary Component Cooling Systems supply cooling water to the DG's 1A and 1B respectively. There are check valves on the inlet and outlet of the heat exchanger Bulletin 83-03 required periodic inspection of these valve As stated in a letter dated October 17, 1983, Maine Yankee has no plans to periodically inspect the DG outlet check valves since this would re-quire draining the system of chromated water. Chromate is added to the system as a corrosion inhibito Draining is required because there is no isolation valve downstream of the outlet check valve. Instead, Maine Yankee committed to update the IST program to open and inspect one of the two DG inlet check valves each refueling outage. If an inspection indicates degradation, the remaining check valves will be inspecte In-service testing consisting of forward flow testing all four checks will continu The inspector verified compliance with these commitments. The licensee has indicated that inspections of the inlet check valves have shown no significant wear or corrosio (Closed) Inspector Follow Item (50-309/84-12-01). Additional instruction for Environmental Studies Laboratory technicians. The Environmental Studies Laboratory technicians have received two days of training on Fundamentals of Radiological Protection and one week of training on the Environmental Protection Progra . Routine Periodic Inspections Daily Inspection During routine facility tours, the following were checked: manning, ac-cess control, adherence to procedures and LCO's, instrumentation, recor-der traces, protective systems, control rod positions, control room an-nunciators, radiation monitors, emergency power source operability, con-trol room logs, shift supervisor logs, and operating order Systeo Alignment Inspection Operating confirmation was made of the Fire Protection Water System, Cardox Fire Protection System trains and Containment Spray System. Ac-cessible valve positions and status were examined. Power supply and breaker alignment was checked. Visual inspection of major components was performed. Operability of instruments essential to system perform-ance was assessed. No concerns were identifie _ _ _ _

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c. Biweekly Inspections 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 operational status was reviewe Plant housekeeping and cleanliness were evaluated. No concerns were identified.

d. Plant Maintenance The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifica-tions, radiological controls for worker protection, fire protection, retest requirements, and reportability per Technical Specification Maintenance items observed include Emergency Diesel Generator (EDG) 1A Fuel Strainer cleaning, reactor trip breaker #5 preventative maintenance, and #3 inverter troubleshooting. No concerns were identified.

e. Surveillance Testing The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results, removal and restoration of equipment, and deficiency review and resolutio The quarterly and monthly surveillance test of the steam driven auxiliary feed pump was witnessed. Testing was performed with good coordination between the control room and the Auxiliary Operator (AO) at the pum Strict adherence to the test procedure was noted. A step in the proce-dure required shutting the steam supply valves to the turbine and veri-fying steam pressure to the turbine dropped off. The A0 discussed this step with the PSS to determine what steam pressure was acceptable. This matter was further resolved at the Morning Managers Meeting the following day by requesting PED to add specific acceptance criteria to this ste PED stated that the steam pressure was acceptable as long as it was not sufficient to turn the turbine. This will be added to the procedur No discrepancies were note The inspector also witnessed a portion of the first monthly surveillance test of AFW automatic initiation relays. This test requirement was added by Technical Specification Amendment No. 87, dated March 4, 1986. Addi-tional surveillances observed or reviewed includes ECCS pump runs, reac-tor trip breaker #3, post maintenance test and safeguards valve testin No discrepancies were note ,

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5 l f. Plant Trip While placing the steam driven main feedwater pump (P-2C) in service on April 17, 1986, the plant tripped from 55 percent power. All systems functioned normally during the trip. The cause of the trip was high level in #3 steam generator which tripped the main turbine and the reac-to During a normal plant startup the electric driven main feedwater pumps (P-2A and P-28) are used until the plant reached 55 to 60 percent powe P-2C is then placed in service and P-2A or P-28 is secured. The actual sequence requires raising the discharge pressure on P-2C until it bas assumed the majority of the flow (as indicated by a 20 amps' current re-duction on P-2A or B). P-2A or B is then secured. Discharge pressure is returned to normal and the recirculation valve for P-2C is adjusted to minimize pump vibration At the time of the trip, the operators had placed P-2C in service, se-cured P-28, reduced header pressure by lowering the speed of P-2C and adjusted the pump vibrations on P-2C usirg the recirculation valve. In response to lowering header pressure, the feedwater regulating valves began to open to maintain steam generator (S/G) level. An unexplained P-2C speed decrease continued resulting in a low level alarm in the steam generators. The feed regulating valves continued to open to recover level in the steam generators. P-2C eventually responded and increased speed. This increased flow and pumped a large volume of water into the S/Gs which resulted in a high level in the S/Gs. The main turbine auto-matically tripped on high level in #3 S/G (all S/G levels followed the same pattern). Above 15 percent power a turbine trip automatically causes a reactor tri An inspector was in the control room at the time of the trip and attended post trip review meetings. The analysis of post trip review information was thorough. The PORC reviewed the plant trip and the findings of the Post Trip Review Committee including the review determination that P-2C response was not correct. The PORC decided to allow a plant startup after : Conducting an inspection of the plant for any associated damag None was foun . Cycling the feedwater regulating valves. to assure proper operatio The feedwater regulating valves functioned normall . Placing an administrative hold on the use of P-2C until trouble-shooting of the control circuit was complete. Subsequent trouble-shooting identified a " dead spot" on the potentiometer for header pressure control. This opening in the circuit was the identified cause of P-2C failing to maintain the required feedwater flow and subsequent trip of the plan .

Plans were made to restart the plant using the electric driven feedwater pump Because of delays caused by #3 inverter repairs, the potentio-meter was replaced and P-2C was used during plant startup on April 18, 198 g. Loss of #3 Vital Bus Inverter While shutdown on April 17, 1986, at 2:15 p.m., the contro' room received a ground alarm on the 120 volt A.C. vital bus. The smoke auctor system alarmed for the protected switchgear room. The fire brigade respeded and identified the source of the smoke as the #3 vital bus inverte The inverter was deenergized and the ground alarm cleared. #3 A.C. vital bus was crossconnected with #2 A.C. vital bus. Investigation revealed one of the four capacitors in the static inverter was grounded and had begun to smoke until it was deenergized. Repair efforts located addi-tional parts within the inverter that were in need of replacement. A manufacturer's representative was called in to assist in the repair effor The Plant Operations Review Committee (PORC) reviewed the loss of #3 A.C. inverter. Based on an evaluation of the electrical system by Yankee Atomic Electric Company (YAEC), the PORC decided to remain shutdown until the repairs to the inverter were completed. The YAEC evaluation recom-mended minimizing plant operations with the 120 volt A.C. busses cross-connected. Failure of one bus in this crossconnected configuration could cause a loss of redundant instrumentation. At 8:05 p.m. on April 18, 1986 following repairs to inverter #3, the plant was taken critical and re-turned to power operations, h. Steam Driven Feedwater Pump While operating at 100 percent power on April 27, plant operators noted a discrepancy in the feedwater pressure controller associated with the steam driven feedwater pump (P-2C). The operators were required to set the header pressure controller higher than the actual header pressure in order to maintain the required differential pressure across the feed-water regulating valves. The decision was made to switch to the electric driven feedwater pumps, an operation that involves reducing poser to 55 percent and conducting the switchover. While reducing power, the P-2C pressure controller failed to maintain header pressure. An emergency switchover to the electric driven feedwater pumps was conducted at 72 percent power. P-2C was removed from service and the plant returned to 97 percent power (which is the maximum power with electric driven feed-water pumps). P-2C remained out of service for the remainder of the report period. The licensee is studying the feasibility of operating P-2C in the speed control mode instead of the pressure control rcod Problems with the P-2C controller are significant because a trip of P-2C can result in a plant trip. In the past, problems associated with the P-2C recirculation valve and heater drain tank level control valve were C

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the cause of feedwater associated trips. Esen 'though the P-2C speed con-troller was repaired following the; plant' trip on April 17, a similar type failure of the controller led.to the emergency transfer of feedwater pumps on April 27. The inspector' discussed these concerns with plant management. The licensee has initiated a review of the problems noted with P-2C control. P-2C remains out of service pending the results of the licensee's investigatio Containment Weight of Air On April 30, 1986 the containment high accuracy pressure detector (Mensor)

was removed from service and declared-inoperable. The Mensor is used to provide a highly accurat'e input into the Containment Weight of Air (WOA) calculation. WOA is a system used to detect changes in the con-tainment atmosphere which could be the result of leaks from a pressurized containment. A series of humidity and temperature detectors are used in the WOA calculatio As a result of the Mensor being declared inoperable, the plant operators hand calculated containment WOA using a pressure input from a manometer located in the Primary Auxiliary Building. This calculation was per-formed once each shift. Additionally, the plant computer containment pressure input was switched to an alternate pressure sensor. Since neither of these methods is as accurate as the Mensor, the data received from the hand calculations and computer calculations were plotted in an effort to eliminate data scatte The PORC met on May 8 to review the circumstances of the Mensor inoper-abilit Technical Specification (T.S. 3.11) requires that the contain-ment WOA system be operable whenever the reactor has been at power for more than 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> If the containment WOA system is out of service for more than ten days with the reactor critical, the licensee must notify the NRC of plans to restore the system to operability. PORC de-termined that the WOA system was not, in fact, inoperable with the Mensor out of service since hand calculations and computer calculations gave comparable readings. PORC determined that the alternate means of calcu-

-lating containment WOA provided the necessary accuracy to ascertain leak-age from containment was within the allowable limit Repair parts for the Mensor were received and the Mensor was returned to service on May . Observations of Physical Security Checks were made to determine whether security conditions met regulatory re-quirements, 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 meas-ures when required. No discrepancies were note ~ - _ - _ __ _

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6. Radiological Controls Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices, conformance to radio-logical control procedures and 10 CFR Part 20 requirements were observe Independent surveys of radiological boundaries and random surveys of nonradio-logical points throughout the facility were taken by the inspecto An independent radiation survey was performed by the inspector in the PA The purpose of the survey was to verify that the posting of radiation areas and hot spots was correct. One hot spot was found that was approximately 3 R/hr. contact and 30 MR/hr. at 12 inches. It met the criteria of procedure 9.1.6 for " Establishing and Posting Controlled Areas" in that the component contact reading was greater than 300 MR/hr. and 5 times the general area dose rates at approximately 12 inches. A health physics technician at the control point was notified. The technician surveyed the component and properly posted it as a hot spo No additional discrepancies were identifie . Follow-up of TMI Action Plan Items The following TMI Action Plan items detailed in NUREG-0737 were reviesed during this report perio . II.E.1.1 - Auxiliary Feedwater (AFW) System Evaluation - Two items remain open within this action ite In a letter to the NRC dated December 12, 1985 (MN-85-174), the licensee reviewed these two item The first deals with redundant level indication for the Demineralized Water Storage Tank (DWST). Maine Yankee maintains that the level indi-cation system for the DWST is sufficiently diverse for this tank con-sidering the static reserve water it holds. This item is under review by NR The second item is operator diversion time for a postulated break of the AFW header. Operators are estimated to have 35 minutes to manually divert flow through the first point feedwater heaters in the event of a break in the AFW manifold. This item also remains open pending review by NR . II.E.1.2.1.B.2 - Auxiliary Feedwater System Initiation and Flow - On March 4, 1986, the NRC issued Amendment 87 to the Maine Yankee Technical Specifications. This Amendment required logic testing of the Auxiliary Feedwater (AFW) initiation circuit. The license conducted the first monthly surveillance of the AFW initiation logic using procedure 3-6.2.2.22 on April 4, 1986. Observation of this surveillance is docu-mented in section 4e. This item is closed.

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9 II.K.3.5.B - Automatic Trip of Reactor Coolant Pumas (RCP) - In a Safety Evaluation Report (SER) dated April 15, 1986, the iRC accepted the lic-ensee's proposal to manually trip RCP's when subcooling margin reached 25 degrees F. During the inspector's review of newly developed Emergency Operating Procedures (due to be implemented in May,1986), the 25 degree F subcooling margin was verified. Current operating procedures were verified to include similar RCP trip criteria. This item is close . Steam Generator Level On May 8, 1986, I&C technicians entered containment to conduct a calibration of #1 and #2 steam generator (S/G) wide range (WR) level instruments. The calibratien involved isolating the wide range level differential pressure (d/p) transmitter, conducting the calibration and returning the transmitter to service. According to the mechanical (FM) drawings, the wide range in-strument, channel X (feedwater regulating valve control circuit) and channel A of the Reactor Protection System (RPS) all use the same root valve for the low pressure side of the d/p transmitte While valving #2 steam generator wide range instrument back into service a perturbation of level was observed and channel D of the RPS tripped on low S/G level. Some change in indicated level was expected on the channels that are connected, however, no change was expected on channel When valving in the #1 steam generator wide range instrument, a similar perturbation was observed affecting the feedwater bypass valve control circuit (channel Y).

Again, this was unexpecte A Plant Operations Review Committee (PORC) meeting was held later that day to discuss the instrument response and determine a corrective action pla The correctivc action decided upon was 1) a thorough review of all prints associated with the piping and electronics of the systems involved, and 2) a containment entry to physically trace the piping systems. Depending on the outcome of these reviews, the PORC would recommend further action, if require On May 9, 1986, a second PORC meeting was held to review the results of the event review. A discrepancy was found bctween the mechanical (FM) prints and the tubing (FK) prints. FM prints are controlled prints. FK prints are un-controlled. The FM prints showed channels WR, X and RPS channel A, all using a common high side tap. The FK prints showed WR, RPS channel D and channel Y (feedwater bypass valve control circuit) all using the same high side ta A containment entry revealed that WR, RPS channel D and channel Y were in fact all piped to the same high side tap. The PORC concurred on a plan to recreate the events of the preceeding day to verify the response of all instrumentation involve Additional personnel were stationed to observe meter responses. I&C techni-cians entered containment to valve in the transmitters as they had done the day before. Once again, similar responses were observed.

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The licensee concluded that an error in the FM drawings caused the observed indications. The FM drawings had been developed from original plant drawing The root valves were shown on these drawings to indicate the function of these level taps. At the time, no valve numbers were assigned to root valves. An error in the assignment of the wide range channel had resulted in the observed discrepancies. The uncontrolled FK drawings had shown the proper orientation of the instruments. Changes were made to the FM prints to indicate the proper instrument assignment The inspector closely followed the licensee's actions during this event. No discrepancies, other than the error in the FM print, were noted. All instru-mentation was operable during this period. The removal from service and re-turn to service of the WR level d/p transmitters was controlled through I & C calibration procedures and tagout . Staff Training Program The licensed operator and non-licensed staff training program was reviewed in order to determine if there was a correlation between abnormal events or unusual occurrences attributable to training program deficiencies. No such correlation could be establishe The requalification program examinations and results were reviewed with par-ticular attention directed to the reexaminations of the 1 of 22 senior reactor operators and the 1 of 14 reactor operators who failed to satisfactorily com-plete initial requalification examinations. No discrepancies were note The licensee utilizes a number of methods to keep operators aware of plant occurences. Morning Managers Meeting minutes are distributed daily. Plant In-formation Reports and Unusual Occurrence Reports are issued for plant events and become part of turnover review or required reading. The combination of these systems results in operator awareness of observed problems and/or plant events and their corrective action. A review of the Operations Department re-quired reading book indicated several instances of operators failing to com-plete required reading of revised procedures by the date established for com-pletion. Although these were isolated cases, further emphasis in this area is neede Licensee schedules currently project completion of Institute of Nuclear Power Operations (INP0) accreditation for Operations by June, 1986; Instrumentation

& Control (I&C), Mechanical Maintenance and Radiation Protection by September 1986; and Electrical Maintenance, Chemistry, Shift Technical Advisor and Technical Staff training accreditation by the end of 198 . 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 inspection.