IR 05000309/1987025
| ML20237C106 | |
| Person / Time | |
|---|---|
| Site: | Maine Yankee |
| Issue date: | 12/09/1987 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20237C093 | List: |
| References | |
| 50-309-87-25, GL-83-28, NUDOCS 8712210036 | |
| Download: ML20237C106 (10) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Docket / Report:
50-309/87-25 License:
OpR-36 Licensee:
Maine Yankee Atomic Power Inspection At:
Wiscasset, Maine Dates:
October 6, 1987 to November 16, 1987
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Inspectors:
Cornelius F. Holden, Senior Resident I'nspector Ri hard J. Freudenberger, Resident Inspector Approved By:
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] 9!f[
(lowell E. Trig, Chief, Reactor Projects
' 15 ate Section No. 3A.
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Summary:
Inspection on October 6 to November 16, 1987 Report No. 50-309/87-25 Areas Inspected:
Routine resident inspection (246 ' hours) of the control rocra, accessible parts of plant structures, plant operations, radiation protection, physical security, fire protection, plant operating records, maintenance and surveillance.
Results:
No violations or significant concerns were noted.
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8712210036 871210 ADOCK 05000309
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DETAILS 1.
Persons Contacted Within this report period, interviews and discussions were conducted with
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various licensee personnel, including plant operators, maintenance tech-nicians and the licensee's management staff.
2.
Summary of Facility Activities The plant was at 100 percent power at the beginning of the report period.
I On October 13 power was reduced to 75 percent for condenser waterbox
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l cleaning.
While at reduced power on October 13, Control Rod #55 was dropped and unable to be recovered for just over an hour, therefore power was reduced by 20 percent to 55 percent as required.
On October 14 the plant was returned to full power. Control Rod #19 was dropped and immedi-ately recovered; no power reduction was necessary.
On November 4, power
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was redu:ed for condenser waterbox cleaning and routine turbine valve testing.
By November 5, the plant was returned to full power, where it
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remained for the rest of the period.
3.
Followuo on previous Inspection Findings (Closed) Unresolved Item (50-309/87-20-01) Diesel Generator Cooling a.
Single Failure Vulnerability.
As a result of followup inspection into Licensee Event Report (LER)87-001, the licensee agreed to con-duct a scoping assessment to estimate the approximate time it would take to fail Emergency Diesel Generator DG-1A as a result of a postu-lated pipe break in the Secondary Component Cooling (SCC) Water Sys-This scenario, which is beyond the design basis of the plant, tem.
starts with the plant experiencing a loss of offsite power.
During this event, a SCCW pipe rupture results in eventual loss of cooling to Emergency Diesel Generator DG-18. The loss of SCCW results in the loss of cooling water to the service air compressors which fail and result in the loss of the Plant Air System.
With the loss of Plant Air, the firewater valves at each diesel generator fail open creating a crosstie between the SCCW and Primary Component Cooling Water (PCCW) Systems.
This allows the PCCW System to leak into the SCCW System and then out the SCCW pipe break.
PCCW cooling to Emergency Diesel Generator DG-1A becomes degraded and the diesel eventually overheats and fails.
No credit is taken for the SCCW outterfly valves to automatically isolate the nonseismic portion of the SCCW System and operator action outside of the Control Room is not assumed.
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l Maine Yankee Project, Yankee Nuclear Services Division, using the above scenario, estimated between 32 and 55' minutes after SCCW pipe rupture before failure of DG-1A would occur.
Based on this review the inspector determined that sufficient time exists for operator -
action to restore at least one means of alternate cooling to -the diesel generator and the air' compressors.
The inspector will con-tinue. to follow the licensee's actions to. permanently resolve the design deficiencies of the diesel generator cooling system.
b.
Closed) 50-309/87-06-01 IFI - During inspection 87-06, water samples for chemical analysis were split between the licensee and Brookhaven-National Laboratory (BNL).
Upon completion of the analysis, an
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evaluation was made of the acceptability of the results. The follow-ing is a listing of the sample results:
Split Sample Comparison Maine Yankee l
i Sample Chemical I
Source Parameter MY Value BNL Value i
Steam Generator Chloride 48.8 50.5 i
(ppb)
Fluoride 52.2 I
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Sulfate 52.0 52.4
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i Chioride 74.7
'77.0 Fluoride 77.2
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Sulfate 78.7 74.6 l
Reactor Coolant Copper 0.58 0.585 s
(ppm)
Iron 0.59 0.503 i
Chromium 0.55
i Nickel 0.64 0.560'
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1.12 I
Iron 1.12 1.02-
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Chromium 1.10
Nickel 1.15 l'.10
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The analytical comparisons of the results were acceptable.
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4.
Routine Periodic Inspections
,a.
Daily Inscection
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During routine facility tours, the following were checked: manning, access control, adherence to procedures and LCO's, instrumentation, recorder traces, protective systems, control rod positions, control room annunciators, radiation monitors, emergency power source opera-bility, control room logs, shift supervisor logs, and operating orders.
No significant concerns were identified.
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b.
System Alienment Insoection Operating confirmation was made of the Low Pressure Safety Injection System (LPSI) piping system trains.
Accessible valve positions and status were examined.
Power supply and breaker alignment was checked.
Visual inspection of major components was performed. Oper-ability of instruments essential to system performance was assessed.
No discrepancies were identified.
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 opera-tional status were reviewed. plant Housekeeping and cleanliness were evaluated.
No significant concerns were identified.
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d.
plant Maintenance The inspector observed and reviewed maintenance and problem inves 1-gation activities to verify compliance with regulations.
This in-cluded administrative and maintenance procedures, codes and stand-ards, proper QA/QC involvement, safety tag use, equipment alignment, l
jumper use, personnel qualifications, radiological controls for worker protection, fire protection, retest requirements, and reporta-bility per Technical Specifications.
Included in this review were the activities.' associated with trouble
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shooting the inability to move Control Element Assembly (CEA) #58, the subsequent CEA #58 timer control module and control power supply replacement, and Reactor Protective System Channel A test cable ground troubleshooting.
No concerns were identified by this review.
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e.
Surveillance Testina The inspector observed parts of tests, including the following, to.
assess performance in accordance with approved procedures and LCO's, test results, removal and restoration of equipment, and deficiency review and resolution.
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Monthly Surveillance Testing
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(DG-1B)
CEA Exercising
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Turbine Valve Testing
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Main Steam Excess Flow Check Valve Testing.
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Prior to the performance of the monthly surveillance run of the emergency diesel generator, the inspector noted a' rust stained area on the decking below the air start motors and discussed the possi-bility of excess water in the air start system with the licensee.
During the monthly surveillance run the diesel generator started successfully and passed the surveillance test. Approximately 50 ml of water was observed in the exhaust from the air motors even. after, the air start system had been blown down as required by the surveil-lance procedure. The licensee determined that water in the air start system may degrade the air starting motors over time.
Work Orders were written to check the oil injectors on the starting air lines for water prior to the next monthly surveillance run of both diesel generators.
The inspector will follow licensee actions to identify the source of the water in future inspections.
f.
Cold Weather Preparations In anticipation of winter weather, the licensee performs procedure 1-202-2." Cold Weather Operations". This. procedure along with Proced-ure 1-24-1 " Safeguards Heat Tracing System" provides insurance that the necessary precautions are taken to protect plant equipment from freezing conditions.
The Safeguards Heat Tracing System ' procedure includes a checklist that is completed on a. daily basis, year round.
The Cold Weather Operations procedure is ' performed annually, in Autumn, and takes various actions to provide the necessary protection for plant equipment.
These actions include; verifying the operation of all space heating units, checking roof vents, placing outside-tank heating units in operation, and installing covers on the inlet dampers to several ventilation units.
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The inspector reviewed the procedures and verified. operation of selected portions of the equipment listed.
No discrepancies were
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g.
Backshift Inspections The inspectors conducted backshift inspections on October 8,19, 20, 31 and November 5, 14, and 15.
5.
Observations of physical Security Checks were made to determine whether security conditions 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.
During this period a Regulatory Effectiveness Review of the Security area was conducted and will be reported under separate correspondence.
i 6.
Misaligned (Drooped) Control Element Assemblies (CEA's)
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On October 6, 1987, while performing surveillance procedure 3.1.8 " Control
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Element Assembly (CEA) Exercising", CEA 58 could not be repositioned from the control room. CEA 58 remained operational since its ability to insert was unaffected.
Troubleshooting was conducted and corrective action in-cluded replacement of the 15 volt D.C. power supply and the upper gripper coil switch.
While troubleshooting the control circuitry, it was noticed'
that the voltage which was being supplied to the upper coil was incorrect.
The licensee decided that voltage readings of all other CEA's 15 volt 0.C.
control power supply and upper gripper coil switches should be checked to ensure that no other CEA's had a similar problem.
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In an unrelated incident, on October 13, 1987, while adjusting plant power with control rods, the reactor eperator selected manual group sequential mode to increase power level.
Group I deviation high alarm was received and the operator identified that CEA 55 had dropped.
In accordance with Technical Specification 3.10 and Plant Procedure (AOP 2.21), power was reduced by ten percent within the next half hour.
Power was further re-duced by another ten percent because the CEA was not recovered within one hour of dropping.
I&C technicians identified a problem with the lower l
gripper coil card. When a control rod is moved, the rod control system sequences power to upper and lower grippers. When rod 55 was called on to move, the lower gripper coil was not energized because the lower gripper switch failed to reposition.
This resulted in the dropping ' of CEA 55.
The lower gripper coil card was replaced and CEA 55 was returned to its normal group position one hour and six minutes after dropping.
Followup analysis of core peaking factors and chemistry samples showed no adverse effects of the dropped rod.
Plant pcwer level was ; returned to normal.
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On October 14, 1987, CEA 19 dropped.
At the time, I & C was checking voltage readings on the 15 volt D.C.
control power supply to CEA 19's
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timer module as part of the followup to the problem with CEA 58.
A loose lead apparently interrupted power to the upper gripper coil causing CEA 19 to drop. The lead's terminal was tightened and the CEA was immediately restored to its normal position.
No power reduction was necessary.
The inspector had no futher comments.
i 7.
Radiological Controls i
l Radiological controls were observed on a routine basis during the report-ing pe ri od.
Standard industry radiological work practices, conformance to radiological control procedures and 10 CFR part 20 requirements were observed.
Independent surveys of radiological boundaries and random sur-veys of nenradiological points throughout the facility were taken by the j
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inspector.
Radiological work practices were evaluated including observa-tion of an auxiliary operator's entry into a high radiation / contamination i
i area to realign the inservice letdown demineralized and a maintenance i
team's entry into a similar area to replace a gasket on a limit switch that provides position information for a motor operated valve.
No con-
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cerns were identified.
8.
Natural Circulation Cooldown The inspector reviewed the licensee's program for the control of natural circulation cooldown in accordance with their commitments to Generic Letter (GL) 81-21.
In response to GL 81-21 the licensee documented two special natural circulation cooldown tests conducted in 1979 and 1980.
The 1979 test, a cooldown from 532 degrees Fahrenheit (F) to 360 degrees F, achieved a maximum cooldown rate of 23 degrees F/hr. The 1980 test, a cooldown from 500 degrees F to 190 degrees F achieved a cooldown rate of 60 degrees F/hr.
An evaluation of test data by the licensee indicated no voiding had taken place.
The licensee also verified that sati s factory
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supplies of safety grade water were on hand to conduct natural circulation cooldowns.
i Since the licensee replied to GL 81-21 a number of plant changes have been made which serve to enhance the abil.ity of the operators to conduct natural circulation cooldowns. A Condensate Stora.ge Tank (CST) was added
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which allowed the Demineralized Water Storage Tank (DWST) to be reserved as a dedicated, seismically qualified tank for Auxiliary Feedwater suc-tion.
The volume of CST water (normally greater than 100,000 gallons)
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provides an additional source of makeup water.
New Emergency Operating i
Procedures exist which direct the operators to estahlish natural circu-lation cooldewns and contain precautions which alert the operators to'
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potential problems / conditions that may cause voiding.
The simulator.
offers realistic conditions under which operators, may practice natural circulation cooldown procedures.
The inspector reviewed the licensed s
operator training program to verify training in the performance of natural circulation cooldowns covers pertinent topics. The operator training pro-gram contains both lecture topics and simulator practice sessions ' on natural circulation cooldowns including indications of voiding in the core and methods to control it'.
The licensee also conducted a natural circulation cooldown of the plant during the last refueling outage.
The cooldown was planned as part of-normal plant refueling.
However, forced circulation was 1,ost in icop #2
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when #2 Reactor Coolant Pump (RCP) tripped due to intermittent stop valve position indication.
Since #2 RCP did not have a backstop device in-
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stalled, the operators tripped the other RCP's as required by procedure to prevent reverse rotation of #2 RCP.
The operators conducted the plant cooldown using natural circulation in accordance with Procedure 1-7, Plant Cooldown.
No anomalies were observed.
The inspector had no further questions. This inspection closes TI 2515/86 (MPA B-66).
9.
Inspection Followuo to Generic Letter 83-28 Item 4.1 The inspector conducted a followup to the licensee's response to Generic Letter (GL) 83-28 " Required Actions Based on Generic Implementation of Salem ATWS Events".
The NRC's Safety Evaluation for Maine Yankee's response to GL 83-28 item 4.1 was reviewed.
Due to slow response times
experienced by some reactor trip breakers at Maine. Yankee late in 1983, the licensee committed to either refurbish, replace, or upgrade the Reactor Trip Breakers (RTB's) with new front frame assemblies. ~ Th.e in-
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spector reviewed the technical manuals for the RTB's and found no out-standing vender recommended modifications for Maine Yankee.
Machinery History records, Deficiency Reports and purchase orders were resiewed.
l All breakers were either returned to the factory for refurbishment and new front frames ~ or the front frame assemblies were replaced by the licensee.
Post modification testing showed all RTB's were tested in accordance with
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Maintenance Procedure 5-77-3, Inspection and Repair of General Electric
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AK-2 Circuit Breakers.
The inspector had no further questions.. TI 2515/
91 and SIMS item MPA-B-80 are closed.
10.
Low Temperature Overpressure Protection (LTOP)
j A technical issue identified with pressurized wate,'r reactors was. the safety margin-to-failure of the reactor coolant system (including reactor vessel) should it be subjected to a severe pressure transient at a rela-tively low temperature. The majority of these transients ' are postulated i
to occur during startup or shutdown operations when the reactor coolant
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system (RCS) is in a solid water condition.
During such concitions, the RCS is susceptible to a rapid increase in system pressure through thermal expansion of the RCS water or through injection of water into the system without adequate relief capacity to control the pressure increase.
The inspector reviewed the licensee's actions taken to address this issue.
The licensee installed two design changes during the 1984 refueling outage which address the hardware required to protect against a low temperature overpressurization. The first was the addition of two new pressure trans-mitters and controllers for the Power Operated Relief Valves (PORV's).
These were installed in place of old transmitters and provide for redund-ant trains of LTOP protection.
The new controllers have an adjustable setpoint that provides operators with a means to manually control the activation setpoint of the PORV's (one per train).
Each LTOP train is provided with a keylock switch that is used to arm or disarm the LTOP system, depending on plant conditions.
Each keylock switch has a high
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pressure safety relief (HPSR) and a variable pressure safety relief (VPSR)
f position.
In the HPSR position, the LTOP system i s disarmed, and the PORV's will open if an RCS overpressure condition is sensed by the Reactor Protection System (RPS).
In the VPSR position, the LTOP system is armed and each LTOP train will open its respective PORV if system pressure exceeds the adjustable setpoint.
Each train is powered from a different vital bus tb provide reliable power.
The second design change installed in 1984 was a flow restrictor which maintains charging flow less than 200 gpm when in a low pressure condi-tion.
Inadvertent high pressure safety injection (HPSI) and maximum charging flow have been identified as the limiting transients for LTOP when RCS pressure is celow approximately 400 psig. The flow restrictor is i
valved in to restrict charging flow to 200 gpm when operating at low RCS pressures to address this concern.
The inspector reviewed the design of these two systems to determine that the LTOP system prevents the plant from exceeding 10 CFR 50, Appendix G limits, that it is single failure resistant, that it is not vulnerable to failures of equipment which cause overpressure events, that the setpoints are supported by analysis and an appropriate 10 CFR 50.59 review has been conducted.
The inspector will continue to follow related LTOP issues in future inspections.
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11.
Reactor Coolant System Leakaoe Evaluation A review of the licensee's Reactor Coolant System Leakage determination was conducted.
This consisted of a review of the lic,ensee's surveillance.
procedure 3.1.19 " Reactor Coolant System Leakage Evaluation" Rev. 8,- two weeks worth of data and results, and a comparison of the licensee's re-suits to the results of independent calculations performed with an NRC developed leak rate computer program.
The detailed methodology of this
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program is described in NUREG - 1107, "RCSLK9: Reactor Coolant. System Leak Rate Determination for PWRs; User's Guide".
The licensee's results for the 14 day period were on average approximately 0.147 gpm lower than calculated by the NRC computer program.
Several factors were identified.
which may have contributed to this difference.
The licensee's calculation of the change in mass in the Rx vessel and a.
piping is calculated using ~ density as a function of average tempera-ture (Tave) only.
Changes in Reactor Coolant' System Pressure are also considered for this calculation in the NRC program.
b.
Mass change in the pressurizer is a function of change in water inventory only.
The NRC calculation also includes the change in steam mass during the test period.
The density of the water at the point of the leak is determined by c.
the conditions in the Volume Control Tank.
The NRC calculation uses standard conditions to arrive at the density ' assumed at the leak.
j It was also noted that the licensee's assumptions used for the calculation of the constants was not well documented. Therefore, changes to the plant parameters that may affect these assumptions may not result in changes to the constan,ts, when needed.
The inspector discussed these differences with the licensee.
The 11cen-see is evaluating the accuracy of the present method.of performing. this calculation.
The inspector will review the results of the licensee's
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Exit Interview Meetings were periodically held with senior, facility management to discuss i
the inspection scope and findings.
A summary of findings for the report l
period was also discussed at the conclusion of the inspection.
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