IR 05000309/1988014
| ML20155A757 | |
| Person / Time | |
|---|---|
| Site: | Maine Yankee |
| Issue date: | 09/21/1988 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20155A739 | List: |
| References | |
| 50-309-88-14, NUDOCS 8810060059 | |
| Download: ML20155A757 (10) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Report No:
50-309/88-14 License No:
DPR-36 Licensee:
Maine Yankee Atomic Power 83 Edison Drive Augusta, Maine 04336 Inspection at:
Wiscasset, Maine Conducted:
August 1, 1988 to August 31, 1988 Inspectors:
Co nelius F. Ho den, Senior Resident Inspector R hard
. Fre denberger, Resident Inspector bl!88
Approved By:
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Sowell E. Tripr(,/ Chief Date Reactor Projects Section No. 3A Division of Resctor Projects Summary:
56 p_ec_ tion on August 1 to Auoust Ins 31, 1988 (Report Number 309/83-14 Areas Inspected:
Routine resident inspections of plant operations including:
YoTTc~wup on previous inspection findings, review of special reports, licensee event followup, oper4*ional safety verification, maintenance, surveillance, physical security, raatation protection and fire protaction.
The inspection was cor:duc+.ed by the resident inspectors including b6.(shif t inspections on August 1,
7, 13, 14, 18 and 28.
Results: No violations were identified. One SIMS iten, Multiplanc Action Item B!diAoderitor Dilution" (TI 2515/94), was closed (Detail 8).
The licensee's response to the piant trip on August 13, was well coordinated. Personnel were aggressive in identifying equipment malfunctions for resolution and all items were addressod prior to plant restart.
8810060059 880921 PDR ADOCK 05000309 O
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DETAILS 1.
Persons Contacted Withi i this report period, interviews and discussions were conducted with various licensee personnel, including plant operators, maintenance tech-niciant and the licensee's management staff.
2.
Summary of Facility Activities At the beginning of the report period the plant was operating at ninety-nine percent power beginning power coastdown.
On August 13, the plant tripped from ninety-eight percent power due to a fault on one of the main transformers.
The plant was restarted on August 18 using the.other main transfor*ar.
Power was stabilized at fifty-eight percent the following day. On August 27, the plant was shutdown to install a spare transformer.
On August 28, prior to phasing the unit on the grid, the spare transformer failed. On August 31, the plant was restarted and stabilized at sixty-five percent power.
3.
Operational Safety Verification (IP 71707)
On a daily basis, during routine facility tours the following were checked, manning, access control, adherence to procedures and LCO's, instrumentation, recorder traces, protective systems, control room annun-
- iators, radiation monitors, emergency power source operability, opera-bility of the safety parameter display system (SPDS), control room logs, shif t supervisor logs, and operating orders. On a weekly basis, selected engineered safety features (ESF) trains were verified to be operable. The l
condition of the plant equipmtnt, radiological controls, security and safety were assessed.
On a biweekly frequency the inspector reviewed a
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safety-related tagout, chemistry sample results, 55tft turnovers, portions of the containment isolation valve lineup.nd the posting of notices to workers.
Plant housekeeping and cleanliness were also evaluated.
The inspector observed selected phases of the plant's operations to deter-mine compliance with the NRC's regulations. The inspector determined that the areas inspected and the licensee's actions did not constitute a health and safety ha:ard to the public or plant personnel.
The following are noteworthy areas the inspector reviewed:
a.
On August 3, plant operators noted an increase in the containment sump in-leakage and the refueling water storage tank (RWST) leakage.
A containment entry was made which verified leakage into containment from the safeguards sump estimated at 0.5 gal / min.
For leakage to occur from the RWST to the containment safeguards sump, leakage past at least one check valve and a butterfly type isolation valve would l
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have to occur.
The isolation valves were stroked with no apparent change in the leak rate. Further testing was conducted in an attempt to identify the actual leak path. As a result of this testing the check valves apparently reseated, resulting in a significant reduc-tion in the leak rate.
The RWST level has been maintained above required levels.
The isolation and check valves have been scheduled to be inspected and repaired as necessary during the upcoming refuel-ing outage, b.
On August 13, at 3:34 P.M., a fault (high side ground) occurred in one of the two main transformers.
This resulted in a turbine trip due to generator protective relaying and a reactor trip on loss of load.
The reserve (offsite) power breakers did not automatically close, resulting in a loss of station service power and a start of the emergency diesel generators (EDG). Both EDG's started and loaded normally.
Reserve power was manually established within fifteen minutes.
The inspector reviewed the % tails of the event and the licensee's respons1 to it, The review 1" 1vded operator response, emergency classification, reporting of the evet co the NRC Operations Center and plant equipment functionality.
Based on discussions with licensed operators and review of plant trip recovery actions, the inspector determined that the post-trip actions of the Emergency Operating Procedures were implemented.
The opera-tors stabilized the primary plant conditions and acted to reestablish offsite power in accordance with plant procedures. While performing these actions, the operators were attentive to anomalies in the oper-ation (.f plant equipment, identifying several anomalies which were recorded and brought forth for resolution.
The specifics of equip-ment operating anomalies are discussed in Detail 4 below.
The operators evaluated the situation to determine whethor an emerg-ency condition declaration was warranted. Based on Procedure 2.50.0,
"Declaration and Categorization of Emergency Candition," Figure 2.50.0-1, the licensee would declare an Unusual Event if both 115-kv lines were inoperable for ten minutes.
The measurable / observable identified in the procedure used to make this determination is zero voltage on the 115-kv lines' meters for ten minutes.
Since the 115-kv lines had normal voltage after the transformer fault was cleared, offsite power was considered to be available.
Therefore, although the automatic transfer to offsite power did not occur, the conditions necessary to declare an unusual event based on the loss of of f site power did not exist.
The inspector concluded the licensee's emergency classification of the plant conditions was appropriat, _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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1he inspector listened to the licensee's tape of the report made to the NRC Operations Center using the Emergancy Notification System.
With the exception of describing the cause of the plant trip as a generator fault, versus a transformer fault the inspector found the information reported to be an accurate description of the plant con-ditior.s at the time. With respect to followup communict'.lon with the NRC, the inspector noted that, although there were some anomalies in the operation of plant equipment, there was no further degradation in the level of safety of the plant.
Since there was no declaration of emergency classes and the plant safety systems were performing as expected, no followup notifications were required.
c.
While the plant was shutdown, the licensee performed a detailed con-tainment inspection, including areas not routinely accessible during operation. This inspection identified a small fitting leak in the oil supply system to the upper shock suppressors of steam generator
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- 3 and a body-to-honnet leak on valve RH-M-1 (residual heat removal suction line isoletion valve). The leakage from RH-M-1 was estimated l
at 0.04 gal / min. Since the valve has no automatic function requiring it to open, it was manually reseated. A thermocouple was attached to the bonnet of the valve with an indicator in the annulus of the con-tainment building which was monitored during routine containment inspections. A catch basin was installed with tubing to the annulus area to allow monitoring of the leak rate.
Prior to plant startup, the licensee performed another detailed containment inspection to assure that all work in the containment building was adequately com-pleted. The inspector performed an inspection of the containment aw this time.
The shock suppressor fitting was repaired and the reser-voir refilled. The leakage f rom R4-M-1 was reduced to apprnximately 0.03 gal / min.
Plant Technical Specifications allow reactor coolant system leakage of up to 1 gal / min.
Total system leakage had not exceeded this limit.
The inspector noted that the catch basin was
fabricated from a plastic barrel. After discussing the reasoning for using plastic with the Plant Engineering Department (PED), the inspector determined that PED recommended plastic to be conservative with regard to seismic events and missile concerns during a loss of coolant accident (LOCA).
The engineer who performed the evaluation had not considered the possibility of the plastic melting during a LOCA, possibly interfering with the recirculation phase of the acci-dent.
This concern was resolved prior to the restart of the plant.
The melting poir.t of the clastic drum was determined to be at least 60 degrees higher than the maximum temperature of the flooded containmen _ -___ _ -- _ _
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d.
Due to the extended higher than normal ambient temperatures which occurred this summer, several areas of potential concern were re-viewed by the inspector. Containment atmosphere temperatures and the ultimate heat sink temperature effects were previon=1y sJJe essed in Region I Inspection Report 50-309/88-11, Detail 4.c.
The licensee was sensitive to the effects of the high temperatures on plant equip-ment.
A computer group trend was established to monitor various pl a r.i parameters which have an impact on the operation of safety related equipmcnt.
Prima ry component cooling, secondary component cooling, service water inlet, and containment air temperatures were included in the computer trends.
When a fan associated with the ventilation to the unprotected (non-safety related) switchgear room f ailed, the licensee provided temporary ventilation, monitored area temperature at an increased frequency and provided sufficient prior-
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ity to complete the repair in a timely f ashion.
Also, an evaluation of the performance of the control room ventilation system was per-formed by the Plant Engineering Department (PED) comparing actual air flow distribution to design.
This evaluation identified several minor deficiencies which, when corrected, enhanced the performance of the system. The inspector concluded that the licensee's actions with j
regard to the higher than normal ambient temperatures were j
appropriate.
4.
Plant Maintenance (IP 62703)
The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and main-tenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, radio-logical controls for worker protection, retest requirements, and reporta-
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bility per Technical Specifications.
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The following maintenance evolutions were reviewed:
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Date Report Number Description
8/16 4212-88 EFCV Actuator Solenoid Replacement 8/17 4208-88 P-29A Service Water Pump Breaker 9/18 4246-83 Valve RH-M-1 Catch Basin Installation 8/3 4210-S8 Shock Suppressor Leakage S/30 3667-88 Valve VP-A-1 Pneumatic Actuator Rebuild
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The inspector reviewed the following plant equipment operating anomTlies which were identified by plant personnel and the licensee's disposition of the equipment's operability prior to plant restart following the August 13 transformer fault and subsequent reactor trip discussed above.
During normal at power operation, the in plant electrical loads are sup-plied from the output of the main generator. When there is a plant trip the electrical system is designed to accomp'ish a fast transfer to the reserve (offsite) power source.
The reserve poser source is supplied by two 115-kv transmission lines.
There is protective relaying associated with the reserve power breakers designed to prevent them from closing when an undervoltage condition exists on the 115-kv system. At the time of the fault on main transformer (X-1A), an oscilloscope was in operation at a switchyard remote to the plant, monitoring the 115-kv "Suroweic" trans-mission line.
The licensee's root cause analysis of the failure to transfer to reserve power determined that calculations, based on the Suroweic oscillograph data, demonstrate that the measured fault was of sufficient magnitude and duration to actuate the reserve power auto close permissive relaying which prevented the closure of the reserve power breakers on low 115-kv grid voltage.
The licensee is performing an analysis to determine the fault magnitude and duration that could be experien:ed without requiring the auto close permissive relaying associated with the reserve power breakers to actuate. Based on the results of the evaluation, a modification to the design of the reserve power auto close permissive relaying to allow it to properly ignore in:onsequential transients, yet provide the necessary
protection for larger faults, will be considered by the licensee.
The Reactor Control Element System consists of three shutdown groups (A,B and C) and five regulating groups (1, 2, 3, 4 and 5). Group 5 is divided into two subgroups SA and 58.
Subgroup 5B consists of four control ele-ment assemblies (CEA's) which are non-trippable.
An additional set of grippers is installed in the drive assembly which prevents movement of the subgroup 5B CEAS in either direction.
The grippers are disengaged from
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the CEA drive shaft when the associated coil is energized. Therefore, for any subgroup SB motion to occur, control power must be available to the control element drive system (CEOS).
The subgroup 5B CEAs are full l
strength CEAs for local power distribution control and do not contribute l
to the available scram reactivity assumed in the cycle 10 core performance l
analysis. Af ter the plant trip on August 13, all trippable rods tripped l
into tha core as expected. Normal practice is to drive Subgroup SB into l
the core 'or extra shutdown margin following the trip.
When this was attempteo, none of the rods in Subgroup SB would move into the core. In-
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strumentation and Control (I&C) technicians identified a failed power sup-ply for that subgroup and replaced it prior to plant restart.
Since CEA subgroup SB does not contribute to the post trip shutdown margin analyzed in the Cycle 10 Core Performance Analysis, the inspector considered this component failure to be of minor significanc _ _ _ _ _
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The service water system is the safety related cooling system which pro-vides cooling water from the ultimate heat sink to the primary and secondary component cooling heat exchangers. The system consists of four pumps, four heat exchangers and two supply headers.
Any one pump dis-charging through either header to the heat exchangers provides sufficient heat removal capability during design basis accident situations.
Pumps
"A" and "B" are normally aligned to discharge through the south header and
"C" and "0" through the north header.
Following an automatic start upon receipt of an emergency diesel generator load program start signal, all four service water pump breakers are shut.
Controller logic causes the "C" pump to trip automatically if the "A" pump is running.
Similarly the
"B" pump will trip if the
"D" pump is running.
If the "A" or "0" breaker fails to shut its backup pump ("C" or "B") will not trip.
The controller logic provides for the tripping of extra pumps to minimize the load on the emergency diesel generators while maximizing the reliability of the service water system.
Prior to the plant trip on August 13, the
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"B" SW pump was removed from service while the "A" and the "D" pumps were running.
Following the plant trip and start of the emergency diesel gen-erators, the "A" service water pump's breaker did not reclose.
Therefore, the
"C" pump remained running as designed.
The
"C" pump operated nor-mally. With the "C" and "0" pumps operating, the redundancy of the ser-vice water system was not affected. Af ter resetting the overload device
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on the "A" service water pump, it operated normally.
Inadvertent opera-
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tion of the overload device appears to have caused the "A" pump's breaker i
to remain open.
The licensee removed the "A" service water pump breaker from service to test its operation.
No abnormalities were found.
Prior to restarting the plant the breaker from the "B" service water pump was l
installed in the
"A" pump breaker cubicle.
(The
"B" pump was out of
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service for maintenance). The licensee has plans to replace the overload i
devices in their safety related breakers with electronic excess current i
devices during the upcoming refueling outage.
The service water pumps
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will receive priority in the replacement of their overload devices.
The main steam excess flow check valve (EFCV) MS-33 closed at a slower rate than the other two EFCVs when operated from the rnain control board controls.
There are three solenoid valves associated with the pneumatic
actuator to the EFCVs.
Low pressure on any steam generator will actuate two of the solenoids on all three EFCVs.
The third solenoid is operated
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from the auxillary shutdown panel.
The main control board controls oper-ate one of the solenoid valves which is operated on low pressure.
technicians identified that this solenoid valve to MS-33 was sticking.
The solenoid valve was replaced prior to plant restart.
If the EFCV had been required to operate to fulfill its safety function, the redundant solenoid valve would have allowed the EFCV to close.
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After the plant trip and loss of of f site power, the letdown system iso-lated resulting in a decreasing level in the volume control tank (VCT).
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Oue to the decreasing level, the VCT outlet valves to the charging pump suctions were closed after the suction valves from the refueling water
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storage tank (RWST) were open.
This was accomplished to allow the addi-l tion of borated water to the reactor coolant system (RCS) to maintain pressurizer level as the RCS cooled. After letdown was reestablished, one
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of the VCT outlet motor operated valves (CH-M-1) would not reopen from the main control board.
Af ter manually moving the valve off its seat it opened normally, Review of the operating requirements of this valve re-vealed that the safeguards function of this valve is to close on a safety i
injection actuation signal (SIAS) and remain closed through any design basis accident scenario.
The torque switch value in the closed direction of the motor operator is intentionally set high so that the valve will
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fully close when required.
The licensee plans to test the motor operator during the upcoming refueling outage and reevaluate the torque switch setpoints.
Overall, the licensee's identification of equipment operating anomalies
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was aggressive, resulting in minor equipment malfunctions being brought forth for resolution.
Resolution of the equipment malfunctions described above was well coordinated and completed prior to plant restart.
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5.
Surveillance Testing (IP 61726)
l 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 resolution.
The following surveillances were reviewed:
l Oate Procedure Number Title 8/1 3.1.3 Turbine Valve Testing 8/1 3.1.6 Main Steam Excess Flow Check Valve Testing No violations were identified.
6.
Observations of Physical Security (IP 71707)
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Checks were made to determine whether security conditions met regulatory requirements, the physical security plan, and approved procedures. Those
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checks included security staffing, protected and vital area barriers,
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vehicle searches and personnel identification, access control, badging, and compensatory measures when required.
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Due to the failure of the main transformer, there was a significant number of contractor employees to be escorted inside the protected area.
The inspector observed work in progress and discussed the specific responsi-bilities of the additional guard positions established with on duty security personnel. The security officers were knowledgeable of the addi-tional duties they were required to perform when stationed at the tempor-ary posts.
7.
Radiological Controls (IP 71709)
Radiological controls were observed on a routine basis during the report-ing period. Areas reviewed included Organization and Management, external radiation exposure control and contamination control.
Standard industry radiological work practices, conformance to radiological control proced-ures and 10 CFR Part 20 requirements were observed. Independent surveys of radiological boundaries and random surveys of nonradiological points throughout the facility were taken by the inspector.
No violations were identified.
8.
f.oderator Dilution (TI 2515/94)
A review was conducted to verify the implementation of licensing actions.
Multiplant Action Item (MPA) B-03 - Poderator Oilution was selected for this review.
By letter dated September 14, 1977, the NRC staff informed the licensee of an incidunt which occurred at an operating PWR facility involving unanti-ctpated dilution of the reactor coolant system (RCS) boron concentration.
The September 14, 1977, letter requested that the licensee review existing boron dilution analyses to assure that these analyses are bounding for all potential boron dilution events including an assessment of factors which affect the capability of the operator to take corrective action.
The letter further requested the licensee to inform the NRC staff if, based on the results of the analysis, design or procedural corrective actions are required to preclude the occurrence or mitigate the consequences of pos-tulated boron dilution accidents. A letter similar to the September 14, 1977, NRC letter was sent to all licensees of operating PWR facilities.
The review of licensees' responses to the boron dilution inquiry was undertaken by the NRC staff and identified as Multiplant Action (MPA) B-3.
The licensee responded to the September 14, 1977, NRC letter by their letter dated January 5,1978.
The licensee's letter provided the results of an evaluation for 131ne Yankee Atomic Power Station.
The evaluation considered conservative assumptions as analyzed in the FSAR.
The con-clusions presented in the evaluation are as follows:
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Additional dilution flow paths do exist and the worst cases would occur during refueling operations.
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For significant dilutions to occur an operating error resulting in system misalignment or control mode selection must take place.
3.
The plant design is such that no potential dilution events were identified which result from a single active component failure.
4.
For the worst case potential boron dilution event identified the time available for operator to take' corrective action is not significantly different f rom that determined for the worst case identified in the FSAR.
Thus, for potential boron dilution events, there is sufficient time and indication available for the operator to take corrective action and preclude an inadvertent criticality.
Based on this review, the inspector concluded that the licensee has com-plied with the NRC request for the performance and submittal of an analysis of the potential for and consequence of boron dilution accidents at Maine Yankee Atomic Power Station.
TI 2515/94 is closed.
9.
Exit Interview (IP 30703)
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.
The licensee did not identify 2.790 material.
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