IR 05000348/1990001
| ML20012C346 | |
| Person / Time | |
|---|---|
| Site: | Farley  |
| Issue date: | 03/02/1990 |
| From: | Cantrell F, Maxwell G, Miller W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20012C343 | List: |
| References | |
| 50-348-90-01, 50-348-90-1, 50-364-90-01, 50-364-90-1, NUDOCS 9003210082 | |
| Download: ML20012C346 (18) | |
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UNITED STATES t
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NUCLEAR REGULATORY COMMISSION
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RE GION ll g
g 101 MARlETTA STREET,N.W.
ATLANTA, OE ORGI A 30323
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Re#phTNos.: 50-348/90-01 and 50-364/90-01 Licensee:
Alabama Power Compar,y 600 North 18th Street Birmingham, AL 36291
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Docket Nos.: 50-348 and 50-364 License Nos.:
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Facility name:
Farley 1 and 2
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Inspection Conducted: January 11, 1990 to February 10, 1990 In:ipection at Farley site near Dothan, Alabama
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Inspectors:
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5-a-To
. F. Maxwell, Senior Resident Inspector Date Signed A n_ s s w u-n
. H. Miller, Jr., Resident Inspec,or Date Signed Approved by:
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F TrTaTnfell, Section enfef //
Date Signed Division of Reactor ProjectV'
SUMMARY Scope:
This routine onsite inspection involved a review of operational safety verification, monthly surveillance observation, monthly maintenance observation, evaluation of licensee self assessment capabilities, licensee training for emergency response, licensee event re> orts, and action on previous inspection findings.
Certain tours were conductec on deep backshift, holidays or weekends.
These tours were conducted January 15, 24 and February 8 (deep backshift inspections occur between 10 p.m. and 5 a.m.).
Results:
Unit 1 operated at approximately 100 percent reactor power throughout the report period.
Unit 2 operated at approximately 100 percent power except on February 9,10, and 11.
On those dates power was reduced to allow work to be completed on a main turbine generator governor valve coupling.
Also, while power was reduced the licensee conducted cleaning activities on the secondary side of the steam generators.
Unit 2 was returned to full power on February 12.
The maintenance observations identified a potential weakness in gga32aB88E8888jha
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the preventive maintenance program.
Instances were identified where it was not clear that vendor reconmendations were incorporated 'in the licensee's preventive maintenance program (paragraph 4 b).
The failure to incorporate the correct. alarm set points on the "As Built" design drawings and control room
. annunciator panel is considered an engineering design weakness (paragraph 4 b.(3). Within 'the _ areas inspected, no violations or deviations were
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REPORT DETAILS 1.
Licensee Employees Contacted R. G. Berryhill. Systems Performance and Planning Manager C. L. Buck. Plent Modification Manager
L. W. Enfinger. Administrative Manager R. D.. Hill Assistant General Manager - Plant Operations D. N. Morey, General Manager - Farley Nuclear Plant C. D. Nesbitt. Technical Manager J. K. Osterholtz. Operations Manager L. M. Stinson Assistant General Manager - Plant Support J. J. Thomas Maintenance Manager L. S. Williams. Training Manager Other licensee employees contacted included, technicians operations personnel, maintenance and I&C personnel security force members, and office personnel.
Acronyms and abbreviations used throughout this report are listed in the last paragraph.
Other Inspections:
January 30 - February 1,1990. RIl Operations licensing personnel conducted requalification re-examinations on five APC0 site personnel.
The results will be documented by Report 348/0L-90-01.
January 29 - February 3,1990. Report _348.364/90-04.
Followup inspection on previous enforcement items and tracking Unit I steam generator tube cracking issue.
February 5 - 6, 1990. NRR conducted an evaluation of the Safety Parameter Display System (SPOS).
The findings will be processed by the Farley NRR project manager.
2.
Operational Safety Verification (71707, 92700)
a.
Plant Tours The inspectors conducted routine plant tours during this inspection period to verify that the licensee's requirements and commitments were being implemented. Inspections were conducted at various times including week-days, nights, weekends and holidays. These tours were performed to verify that: systems, valves, and breakers required for safe plant operations were in their correct position; fire protection equipment spare equipment and materials were being maintained and stored properly plant operators were aware of the current plant status; plant operations personnel were documenting the status of
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out-of-service equipment; there were no undocumented cases of unusual fluid leaks. piping vibration abnormal hanger or seismic restraint movements; all reviewed equipment requiring calibration was current; and in general. housekeeping was satisfactory.
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Tours of the plant included review of site documentation and interviews with plant personnel. The inspectors reviewed the control room operators' ' logs, tag out logs, chemistry and health physics logs, and control boards and panels.
During these tours the inspectors noted that the operators appeared to be alert, aware of changing plant. conditions and manipulated plant controls property.
The inspectors evaluated operations shif t turnovers and attended shift briefings.
They observed that the briefings and turnover provided sufficient detail for the next shift crew and verified that the staffing met the TS requirements.
Site security was evaluated by observing personnel in the protected and vital areas to ensure that these persons had the proper authorization to be in the respective areas.
The inspectors also verified that vital area portals were kept locked and alarmed.
The security personnel appeared to be alert and attentive to their duties, and those officers performing personnel and vehicular searches were thorough and systematic.
Responses to security alarm conditions appeared to be prompt and adequate.
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Selected activities of the licensee's radiological protection program were reviewed by the inspectors to verify conformance with plant procedures and
NRC regulatory requirements.
The areas reviewed included: operation and
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management of the plant's health physics staff. "ALARA" implementation.
radiation work permits for compliance to plant procedures.. personnel
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exposure records, observation of work and personnel in radiation areas to verify compliance to radiation protection procedures, and control of radioactive materials, b.
plant Events and Observations (1) Turbine Building Fire (Incident Report 1-90-12)
Da January 10 at 2:33 p.m. workers in the Unit 1 turbine building observed smoke.
They reported this condition to the control room and a shift supervisor was sent to investigate the problem.
The foreman found the smoke coming from the wall section between the turbine building and the security building which provides access to the plant's protected areas. The fire alarm was sounded at 2:53 p.m. and the fire brigade responded.
Workers on the roof of the security building attempted to extinguish the fire with portable extinguishers.
The fire brigade pulled interior fire hose in the turbine building and discharged water onto the fire from inside the turbine building.
This extinguished the fire. The fire was considered out at 3:30 p.m.
A fire watch remained on the roof for several hours to observe any fire restart.
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The licensee's investigation found that the roof of.the security building was being repaired prior to the fire.
It appears that a portable propane gas torch being used to heat roofing tar ignited the tar and particle insulation wall board in the.
turbine building wall.
The location of the fire in the wall panel made it difficult to locate and extinguish.
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amount of fire damage was small and consisted primarily of damage to the insulation panels.
On January 11, at approximately 7:30 a.m., smoke was once' again
noted coming from the wall area.
It appears that the particle board in the wall panel had reinginited and smoldered through the night since the roofing repair work had not yet started for
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the day.
The fire brigade responded and extinguished the fire with water supplied from a turbine building interior. fire hose.
A fire watch was established for the area to observe any possible reflash.
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Following these fires the licensee instituted a policy to require future roofing repairs to be performed using a tar kettle heated by a propane heater positioned in a location-that will not present a-fire hazard to plant buildings or structures.
This action should help prevent future fires from-roofing
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repairs or installations. This wall panel material has been involved in plant fires in the past. Welding operations ignited this material on August 22, 1989.
For details-refer to Report 348,364/89-20. The inspectors have reviewed this event and have no further questions at this time.
(2) Unit 2 Penetration Room Filtration System The inspectors conducted a walkdown inspection of the Unit 2 penetration room filtration system to verify operability.
Procedure 2-SOP 60.0, Penetration Room Filtration System, and drawings D-205013 and D-205022 were used as reference documents during the inspection.
The system was also inspected for conformance to the system description in FSAR Section 6.2.3.3.2.
Particular attention was. paid towards verifying that valves, dampers and electrical breakers were correctly aligned, and that hangers and supports were in place and properly made up.
The system gauges and instrumentation were inspected and the calibration of these devices was found to be up-to-date.
The equipment couponents were provided with identification tags that matched the procedure description, except for the valves supplying instrument air to the air operated valves (dampers).
These instrument valves were not provided with identification tags as part of the original plant component identification l
program.
In recent months the licensee has found several air supply valves to pr.eumatic valves in the closed position which made these pneumatic valves inoperable.
Recently the instrument
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air valves to some systems have been provided with identifica-tion tags.
The inspectors. pointed out that instrument air supply valves to pneumatically operated safety related valves should be provided with identification tags.
This concern is identified as Inspector _ Followup Item 348.364/90-01-01.
Identification tags are not provided for instrument air supply valves to all safety related valves.
(3) Ruptured Fire Protection Yard Main On the morning of January 25. maintenance personnel were
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calibrating a level gauge on one of the fire protection tanks.
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One of the three fire pumps was being operated for performance of a surveillance test procedure.
At 9:48 a.m.. the outside system operator _ observed a ruptured 12-inch above ground fire protection pipe south of Unit 1 cooling tower 10.
The control room had previously received pump running and fire protection
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tank low level alarms at 9:38 a.m.
However, these alarms were anticipated due to the maintenance being performed on the tank level gauge and the fire pump surveillance test.
Following the report of the pipe break, operations personnel responded to isolate the ruptured pipe.
Before the break could be isolated.
the system pressure dropped to about 90 psig; all three fire pumps, each rated at 2.500 gpm, automatically started; ' w
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level of water in the two 300.000 gallon tanks dropped _
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TS minimum of 250.000 gallons per tank.
The lowest L r reached was about 226.000 gallons per tank.
The b"eck s isolated at approximately 10:00 a.m., and the water levei me storage tanks was restored to the minimum TS level at 11:50'a.m.
This event was reported to the NRC as required by TS section 3.7.11.1, action b 2.
A followup written confirmation was sent on January 26. and a special report is being prepared as required.
The licensee's initial investigation failed to identify the cause of this event. The piping freeze protection system was in place and fully operational which eliminated freeze damage as a possible cause.
The break involved a pipe crack approximately seven feet long and up to 1/2-inch wide.
The section of pipe with the crack has been removed and is being sent to a testing laboratory for further evaluation.
The NRC inspectors reviewed this event and verified that the event was properly reported and evaluated for cause.
The inspectors had no further questions.
(4) Steam Generator Blowdown Isolation Valves - Unit 1 On January 31 the inspectors accompanied licensee personnel during an entry into Unit 1 containment while the unit was at 100% power.
The entry was necessary to determine the physical
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status of the "1B" steam generator blowdown isolation valves.
The licensee noted that one of the valves (7698B) had acquired a steam leak through the valve packing. The electrical wiring on the valve operators was inspected.
The valves were found to be wired in accordance with the electrical design drawings.
The physical orientation of the blowdown valves were compared to the drawing for the steam generator blowdown system (Drawing D-175071, sheet 1. revision 15).
The drawing comparison
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revealed that the blowdown isolation valves were identified in various site operating procedures with numbers which were
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MWR 207327 was issued and the packing leak was repaired on valve 76988. The valve was then tested in accordance with STP 22.25 and returned to service.
A drawing change was initiated to revise drawing
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D-175071 to reflect the actual valve numbers which have been assigned to these valves throughout the various site procedures and documents.
3.
Monthly Surveillance Observation (61726)
The inspectors witnessed maintenance surveillance test activities on safety-related systems and components to verify that these activities were performed in accordance with TS and lices,see requirements.
These observations included witnessing selected portions of each surveillance, review of the surveillance procedures to ensure that administrative controls and. tagging procedures were in force, determining that approval was obtained prior to conducting the surveilltace test, and the l
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individuals conducting the test were qualified in accordance with plant-approved procedures.
Other observations included ascertaining that
. test instrumentation used was calibrated, data collected was within the specified requirements of TS, any identified discrepancies were properly
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The following specific activities were observed:
0-STP-80.1 Diesel Generator 1&2A Operability Test 0-STP-80.2 Diesel Generator 1C Operability Test 0-STP-123.0 Control Room Emergency Ventilation Performance Test ("A" Train)
0-STP-131.04 Smoke Detector Semi-Annual Test
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1-STP-22.16 Turbine Driven Auxiliary Feedwater Pump Quarterly Inservice Test 1-STP-22.25 Steam Generator Blow Down Inservice Valve Exercise Test 1-STP-33.2B Reactor Trip Breakers Train B Operability Test l
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1-STP-63.2 Auxiliary Building Ventilation Systems Handswitch/ Thermostat Position Verification 1-STP-63.3 EQ Area Temperature Monitoring
2-STP-33.0B Solid State Protection System Train B Operability Test 2-STP-41.3 Power Range Functional Test (N-42)
2-STP-124.0 Penetration Room Filtration Performance Test ("A" Train)
2-STP-627.2 Leak Testing of Containment Purge System (Supply)
On January 10, while performing procedure 1-STP-62.2, the licensee found the temperature in the main steam valve room to be 105 degrees F. This exceeded the procedure limit of 104 degrees F.
Portions of the freeze protection enclosure coverings were removed from the exterior walls to provide additional ' cooling for this area.
Procedure 1-STP-62.2 was conducted again for this room on January 11 and the temperature was found to be 90 degrees F which was satisfactory.
Surveillance 1-STP-63.2 was found to be unsatisfactory on January 19. The installed thermostats for the elevator equipment rooms were found to-have a maximum set point of 90 degrees F, whereas the procedure and plant -
drawings require.a thermostat with a set point of 104 degrees F.
Plant change requests 89-1-6311 and 89-2-6312 have been issued to revise the drawings to conform to the "As Built" conditions.
During a review of the inservice test on the Unit 2 turbine driven l
l feedwater pump, the inspectors noted that test procedure 2-STP-22.16.
Turbine Driven Auxiliary feedwater Pump IST,-required the temperature of the pump bearing to be taken locally and recorded.
The acceptance criteria for the temperature was required to be less than 195 degrees F.
However, the annunciator response procedure stated that the maximum safe temperature for this bearing was 185 degrees F and the alarm set point was 180 degrees F as recorded by the temperature monitoring panel in the control room.
Based on observations by the inspector it appears that the bearing temperatures of the turbine driven pump taken at the pump with portable instrumentation as required by the procedure were about 20 degrees F lower than the reading on the temperature monitoring panel, i.e.
a local reading of 195 degrees F would indicate about 215 degrees F on the control room panel.
This could result in exceeding the maximum safe
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operating temperature of the bearing. The licensee has revised procedures L
1/2-STP-22.16 to require the bearing temperature on the turbine driven
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auxiliary feedwater pump to be obtained from the temperature monitoring panel in the control room.
This :;hould alert the operators prior to any
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damage to the pump as a result of elevated pump bearing temperatures. The l
licensee's corrective action resolved the inspectors concern.
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During a maintenance test run of emergency diesel generator 1C on February 9 using surveillance test procedure 0-STP-80.2. diesel generator
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IC experienced excessive load swings.
The problem was promptly evaluated and found to have been caused by a blown fuse in the voltage regulating system control circuit.
The fuse blew due to a short in the " Engine Running" status light socket on the local diesel generator control panel.
The fuse was replaced, light socket removed from the circuit (no replace-ment parts were available), and diesel generator retested satisfactory.
-The light socket is to be replaced when approved parts are obtained.
No violations or deviations were identified.
The-results of the inspections in this area indicate that the program was effective with respect to meeting the safety objectives.
4.
Monthly Maintenance Observation (62703)
a.
The inspectors reviewed maintenance activities to verify the following: maintenance personnel were obtaining the appropriate tag out and' clearance approvals prior -to commencing work activities; correct documentation was available for all requested parts and material prior to use; procedures were available for all requested parts and material prior to use; procedures were available and adequate for the work being conducted; maintenance personnel performing work activities were qualified to accomplish these tasks; activities reviewed were not violating any limiting conditions for operation during the specific evolution; post-maintenance testing activities were completed; and that equipment was properly returned to service after 'the completion of work activities. Activities reviewed included:
MWR-0-CCP-332 Chemical addition to the diesel generator fuel oil tanks.
l MWR 172658 Replace charcoal filters in control room HVAC systems QSV49F001A-A.
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MWR 188970 Replace broken battery cable on diesel driven fire pump "B".
MWR 197822 Replace "Agastat" pneumatic time delay relay on
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Unit 1 emergency diesel generator 1B.
MWR 205164 Verify balance drum clearance conforms to vendors requirements for Unit 1 turbine driven auxiliary i
feedwater pump.
MWR 210273 Repair leak on Unit 1 emergency diesel generator IB jacket water pum,
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MWR 202144 Evaluate possible electrical wiring errors on Unit 1 steam generator IB blowdown valves 7698A and 7698B.-
MWR 202146 Repair the closed indicator for Unit 1 turbine
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driven auxiliary feedwater pump flow control valve.
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t MWR 207327 Repair packing leak on Unit 1 steam generator 1B
-blowdown isolation valve-76988.
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MWR 207781 Repair leaks on Unit I turbine driven auxiliary i
feedwater steam valve HV3226.
b.
Auxiliary Feedwater Pumps The inspectors conducted an evaluation of the methods and procedures used by the licensee to control maintenance activities and tests for the auxiliary feedwater pumps.
As part of the evaluation, the inspectors referred to Information Notice 88-09. Reduced Reliability of Of Steam-Driven Auxiliary Feedwater Pumps Caused By Instability (July-Woodward PG-PL Type Governors and NUREG-0940 Volume 8. Number 3
- September 1989). Significant Actions Resolved, pages I. A-100 and 1.A-101; The review was to determine if maintenance activities were being conducted on selected components in accordance with the manufacturers recommendations.
Unit 1 and 2 each have one turbine driven auxiliary feedwater pump and two motor driven auxiliary feedwater pumps.
The turbine driven pumps are manufactured by the Terry Steam Turbine Company.
The inspectors referred to this manufacturer's technical manual which is identified as APC0 document number U277859 Revision F.
As a result of the evaluation the following were noted:
(1) The Terry Turbine is supplied with a governor valve and a motor operated throttle trip valve.
The turbine motor operated trip valve is normally placed in the open position.
This valve is designed as an emergency overspeed trip valve for the turbine.
The manufacturer's Technical Manual. U277859 Revision F. Section 7, recommended that the linkage and moving parts for the valve be lubricated at least once per week with a good grade of oil.
l The inspectors conducted a visual inspection of the linkage and moving parts attached to the throttle trip valves. The linkage and moving parts did not have any visible evidence that they were being lubricated on a weekly basis.
The inspectors
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informed the General Plant Manager about this concern.
APC0 contacted the manufacturer of the throttle valves (Schutte &
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Koerting) on January 26 and requested that the lubrication schedule for these valves (Q1N12M0V3406 and Q2N12MOV3406) be changed from the the weekly requirement which is specified in the vendor manual. The vendor approved changing the schedule to allow the valve to be lubricated quarterl m
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(2) MWR 205164 - requ(red that the clearance of the balance drum setting for the turbine driven auxiliary feedwater be inspected
and adjusted for proper clearance.
Procedure 0-MP-7.1, Repair of Auxiliary Feedwater Pump, requires a clearance of 0.001'
(+0.0005 and - 0 inches) between the balancing drum and the pump casing. This clearance was originally required by vendor manual U-214885 to be 0.006 inches.
This clearance was changed by vendor letter June 1,1989 for the turbine driven auxiliary feedwater pump (Model No. 4 HMTA) to 0.001 (+0.0005 and - 0 inches).
In reviewing the work for this MWR on January 24, the inspectors reviewed the balance drum clearance requirements for the motor driven auxiliary feedwater pumps and found this clearance requirement to be 0.006 inches.
Procedure MP-7.1 is written for both turbine driven and auxiliary driven feed pumps.
The licensee's review of maintenance records identified only one
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MWR that involved adjusting the balance drum clearance performed-since June 1987.
This was MWR 1635595 which was completed on
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May 3,1988 for pump 1B.
However, the maintenance records do
not indicate the final adjustment setting.
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maintenance procedure MP-7.1 both referenced the vendor's manual to be used in the repair of the pump.
Therefore, it is assumed that the pumps were properly adjusted.
Furthermore, the pumps have satisfactorily passed the quarterly IST surveillance tests.
To assure that future repairs will properly restore the pumps to meet the vendor's requirements, the licensee promptly revised procedure MP-7.1 into two procedures.
One procedure for the motor driven auxiliary feedwater pumps and one procedure for the turbine driven auxiliary feedwater pumps.
(3) During a review-of the control room annunciator alarm panels on -
January 30 the inspectors noted that the temperature set points on the temperature monitoring panel for the component cooling water and auxiliary feedwater pump bearings were incorrect. The alarm et points were 10 degrees F higher than the manufacturers recommei !ed maximum safe operating temperature.
Drawing No.
D-17028 indicates that the required alarm set point is 200 degrees F and the maximum safe operating temperature is 190 degrees F for these bearings.
Minor Departure 90-2185 was written to change the alarm set points to 185 degrees F which is the same as the Unit 2 set points.
The inspectors verified on February 5 that the alarm set points on the temperature annunciator panel had been changed.
Drawing D-170280 also failed to indicate the alarm set points and maximum safe temperature for the thrust bearings on the three auxiliary feedwater pumps. Minor Departure 90-2185 will require drawing 0-170280 and the instrumentation set point documents to be revised to indicate the correct alarm set points and the manufacturer's maximum safe operating temperature for the component cooling water and auxiliary feedwater pump bearing o E
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Annunciator-response procedure 1-ARP-1.10 was also revised to indicate the correct temperature readings.
The failure to include the correct alarm set points on the "As
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Built" plant drawing was a design error.
This discrepancy has~
existed since -the plant became operational in 1977, and could have resulted'in damage to the pumps if pumps had experienced high bearing temperature during pump operation..No violation is
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being issued due to the low. safety significance but this item-indicates that a weakness may exist in design engineering.
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Chemical And Volume Control (CVCS) Charging Pumps Each unit has three CVCS char.ging pumps. The inspectors conducted an evaluation of the methods and procedures used by the licensee to control maintenance activities for CVCS pumps and their motors.
Emphasis was' placed on reviewing preventive maintenance activities to determine if the manufacturer's recommendations were being considered.
The pumps were supplied by Pacific. Pumps and the manufacturer's recommendations are provided in a technical manual identified as APC0 Document No. U176922. Revision Q.
The components which were considered during this evaluation included the pumps, drive motors, pump bearings, and high-speed gear drive, and gear drive couplings.
During the evaluation the following points were noted:
(1) The vendor's manual recommends that the electrical motors be
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inspected periodically to check motor cleanliness; insulation and windings; lubrication and bearing; and vibration.
The licensee has implemented a maintenance procedure for a detailed 18 month inspection of each motor. The motor is cleaned and the windings are subjected to an insulation resistance test during this inspection.
The pump bearings are lubricated every six months. These appear to meet the vendor's recommendations.
(2) Periodic greasing of the couplings for the motors, gear drives, and pumps is recommended by the vendor's manual.
The licensee's procedure required these couplings to be greased yearly.
This appeared to be adequate.
(3) Lubrication of the high speed gear drive units between the motor drives and the pumps is recommended by the vendor's manual to be accomplished every six months or after 2,500 hours0.00579 days <br />0.139 hours <br />8.267196e-4 weeks <br />1.9025e-4 months <br /> of operation.
The licensee's procedures require the oil in each unit to be replaced semi-annually.
This appears adequate.
However, the l
vendor's manual requires the oil strainer in the the system to l
be cleaned at least once a month, and the licensee's program l
only cleans this strainer quarterly.
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Regular cleaning and inspection of the oil coolers are recommended by the vendor.
Initially the oil coolers at Farley were supplied from the service water system.
In 1987, the cooling source for the coolers was changed from service water to the component cooling water system which contains a corrosion inhibitor (potassium chromate).
Since this change the cooling system corrosion has not been a problem. Operations monitors the flow through the coolers during each shift.
This should identify any reduction in cooling water flow prior to any major reduction in cooling efficiency.
This may be adequate, but it is not apparent that this meets the vendor's recommendations.
(4) Quarterly inservice tests are performed by operations on the pumps to measure pump discharge capacity and vibration.-
The lube oil for the pump bearings is replaced semi-annually. This
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meets the vendor's recommendation.
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The vendor recommends that the mechanical seals for the pumps be
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replaced when the total pump operating hours reaches the maximum hours recommended by the seal manufacturer.
The seal manufacturer recommends that the seals be replaced following 8.760 hours0.0088 days <br />0.211 hours <br />0.00126 weeks <br />2.8918e-4 months <br /> of operation or ten years after cure date of the elastomer.
However, the licensee does not have a seal replacement program.
The seals are only replaced when required due to leakage.
(5) The licensee lubrication manuals were reviewed and the specified oils and grease for the charging pumps, gear -drives, and motors were found to comply with the vendor's recommendation.
Of the items reviewed the following' departures from the vendor's recommendations were identified:
strainer in high speed gear drive units are cleaned--quarterly in lieu of monthly; the component cooling water cooling systems for the high speed gear drive units are not included in a preventive maintenance and cleaning program; and a routine pump seal replacement program is not provided. These items were discussed with the licensee.
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The observations noted in paragraphs 4.b and 4.c indicates that the preventive maintenance program for safety related equipment may not take into consideration all of the vendors recommended-maintenance items and frequency.
This concern was discussed with plant management. The vendor manuals for the auxiliary feedwater pumps and charging pumps are being reevaluated to assure that all recommended maintenance items have been considered in the development of the licensee's preventive maintenance program.
This is identified as Inspector Followup Item 348.364/90-01-02. Vendor recommendations for preventive maintenance of auxiliary feedwater and charging pumps.
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The' licensee also stated that the vendor manuals for other
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safety related systems will be reviewed as part of the plants overall independent safety system function evaluation.
This evaluation is in process but is not scheduled to be completed until the m'.d 1990s.
The results of this evaluation will be reviewed durir.g future NRC inspections.
No violations or deviations were identified.
5.
Evaluation ~of Licensee Self Assessment Capabilities (40500)
a.
Plant Operations Review Committee (PORC)
On January 25, the inspectors attended a PORC meeting.
Members present included the chairman, seven members, and one alternate which meets the the.TS quorum. Copies of agenda items were provided to the members for review prior to the meeting.
Discussions between the PORC board members during the meeting indicated that the members appeared to be knowledgeable on the items. The meeting was conducted in a professional manner. The following items were discussed:
(1) Special Report 90-001 for Unit 2: The "A" Train RVLIS Inoperable for More Than Seven Days.
(2) Design Changes PCN S 87-1-4612. Replacement stems for Unit 1 main
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feedwater stop check valves.
PCN S 87-2-4613. Replacement stems for Unit 2 main
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feedwater stop check valves.
PCN B 88-204973, Replacement valves for Unit 2 VCT purge
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line.
(3) Procedure Changes FNP-0-ETP-3016. Testing diesel fuel storage tank
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recirculation time.
FNP-AP-9, Procurement and procurement document control.
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FNP-1-M-050 (Rev. 31), Master list of Unit 1 surveillance
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requirements.
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FNP-1-M--050 (Rev. 26), Master list of Unit 2 surveillance requirements.
FNP-EIP-8, Emergency communications
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Procedures ETP-3016 AP-9 and ElP-8 were not approved and were
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returned to the appropriate group for additional information.
The remaining items were reviewed by the PORC, determined to involve no unreviewed safety questions and were approved.
i-b.
Audits By Safety Audit and Engineering Review (SAER)
On February 7, the inspectors attended an APC0 post-audit conference which was held by SAER.
The conference was conducted to allow SAER audit personnel to present some preliminary findings to site management.
The findings were the results of evaluations recently completed by audit personnel of the Farley operating' experience evaluation programs.
The findings included two apparent discrepancies and three comments each requiring APC0 management attention.
The audit findings placed emphasis on detail compliance with procedural requirements concerning the quarterly reporting to management, the status of of significant operating experience report (50ERs) and vendor reports.
Also, emphasis was placed on reviewing site documents and correspondence to assure compliance with 10 CFR 21 The PORC activities and the SAER audit group activities appeared to be effective with respect to meeting safety objectives.
6.-
Licensee _ Training For Emergency Response (82301)
During the week of February 5, the inspectors observed APC0 personnel conducting on-site emergency response training. The training was scheduled such that an accident scenarios guided the participants through: reviewing assigned tasks; emergency classification systems; notification methods; emergency communications; and accident assessment.
The training was
- conducted to assure continued readiness for prompt responses to plant conditions which may activate the site emergency response team.
7.
Licensee Event Reports (92700, 90714)
The following Licensee Event Reports (LERs) were reviewed for potential generic problems to determine trends, to determine whether information included in the reports meet the NRC reporting requirements and to consider whether the corrective action discussed in the reports is appropriate.
Licensee action was reviewed to verify that the events were reviewed and evaluated by the licensee as required by the Technical Specifications; that corrective action was taken by the licensee; and that safety limits, limiting' safety settings and LCOs were not exceeded. The inspector examined the incident reports, logs and records, and interviewed selected personnel. The following reports are considered closed:
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Unit 2 (50-364)
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LER/89-15 Surveillance not performed on radiation monitor RE-14 due to personnel error.
LER/89-16 Reactor trip caused by a voltage transient on the digital electro-hydraulic control inverter.
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No violations or deviations were identified.
8.
Action on Previous Inspection Findings (92702)
a.
(Closed) Part 21 (348.364/88-03), Gamma-metrics cable assemblies installed as part of the neutron monitoring system may possibly leak.
The vendor Gamma-metrics, tested the cable assemblies and made the necessary repairs during the 1989 refueling outages to correct the previously identified discrepancies.
The inspectors reviewed the completed work requests. MWRs 190556 and 290559, which were completed and functionally accepted on May 4 and October 26, 1989.
This indicates that the required modifications were accomplished.
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Therefore, this item is closed, b.
(Closed) Unresolved Item 348,364/89-22-03. Temperature limit requirements for electrical equipment areas.
The high temperature observed in the electrical equipment area was. evaluated by Bechtel
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and found not to have affected the qualified life of the equipment in this area.
To prevent re-occurrence the licensee has issued procedures 1/2-STP-63.3, EQ Area Temperature Monitoring, to verify that the temperature in each EQ affected area is maintained below-the l'
FSAR limit of 105 degrees F.
These procedures are performed two times per week.
Furthermore, the non-safety related room coolers in these areas are to be maintained with downtime restricted to as short a time as possible.
This should assure that the temperature in the affected_ EQ areas will remain below 105 degrees F. This item is l-closed.
9.
Exit Interview The inspection scope and findings were summarized during management interviews throughout the report period, and on February 13, with the
' plant manager and selected members of his staff. The inspection findings were discussed in detail.
The licensee acknowledged the inspection findings and did not identify as proprietary any material reviewed by the inspectors during this inspection.
Licensee was informed that the items discussed in paragraph 7 and 8 were closed. The following items were also identified.
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i IMM NUMBER DESCRIPTION-AND REFERENCE'
-348,364/90-01-01 Inspector, Followup Item - Identification tags are not provided-for instrument air supply valves. to all safety related valves - paragraph.2.
348,364/90-01-02 Inspector Followup Item - Vendor recommendations for preventive maintenance for auxiliary feedwater and charging pumps
- paragraph 4.
-10 Acronyms and Abbreviations Auxiliary Feedwater AFW
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Abnormal Operating Procedure A0P
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Administrative Procedure APC0 -
-Alabama Power Company Code of Federal-Regulations CFR
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CCW -
Component Cooling Water CVCS -
Chemical and Volume Control System Design Change.
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ECP -
Emergency Contingency Procedure-l EIP~ -
Emergency Plant' Implementing Procedure
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Environmental Qualifications EQ
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ESF.-
Engineered Safety Features Fahrenheit F
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Gallons Per Minute Inservice Inspection ISI L
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IST Inservice Test
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Limiting Condition for Operation
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Motor-Operated Valve M0 VATS - Motor-0perated Valve Actuation Testing Maintenance Work Request _
MWR
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NRC Office of Nuclear Reactor Regulation NRR
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PND --
Plant Modifications Department Quality Assurance QA
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Quality Control
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. Reactor Coolant Pump-RCP
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Safety Injection SI
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SAER -
. Safety Audit. and Engineering Review Steam Generator j
S/G
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SSPS -
Solid State Protection System Solenoid Operated Valve S0V
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SPDS -
Safety Perameter Display System STP Surveillance Test Procedure
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Technical Specification TS
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Technical Support Center-TSC
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Work Authorization
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