IR 05000293/1985028
| ML20138P957 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim, 05002938 |
| Issue date: | 12/02/1985 |
| From: | Mcbride M, Meyer G, Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20138P941 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.F.1, TASK-TM 50-293-85-28, NUDOCS 8512260371 | |
| Download: ML20138P957 (18) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
50-293/85-28 Docket No.
50-293 License No.
DPR-35 Category. C Licensee: Boston Edison Company 800 Boylston Street Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station Location: Plymouth, Massachusetts ' Dates: September 24, 1985 - November 4, 1985 Inspectors: / ' Pl. McBri(d, Senior Resident Inspector ' Date & ll $lf{{ . B. Meyerf,fProject Engineer / D4te Approved: / - ,j - //. D. & pf2/f9 IL. Tripp f' Chief ' Date Reactor Projects Section No. 3A, Projects Branch No. 3 Inspection Summary: Inspection on September 24, 1985 thru November 4, 1985 (Report No. 50-293/85-28) Areas Inspected: Routine unannounced safety inspection of plant operations including: Followup of previous inspection findings, operational safety verification and ESF walkdown, followup of events and non-routine reports, surveillance and maintenance activities, and security activities. The inspection involved 148 inspection-hours by one resident inspector and one project engineer.
Results: No violations were identified.
Concerns about inadequate plant housekeeping practices are discussed in section 4.6 of the report.
8512260371 851203 PDR ADOCK 05000293 G PDR
- . . TABLE OF CONTENTS P. age 1.
Persons Contacted............................................... 1 2.
Plant Status.................................................... 1 3.
Followup on Previous Inspection Findings and TMI Action Plan Requirements (NUREG 0737).................................. 1 a.
Previous Findings.......................................... 1 b.
TMI Items.................................................. 2 4.
Operational Safety Verification................................. 3 a.
Scope and Acceptance Criteria.............................. 3 b.
Findings................................................... 3 5.
Followup on Events and Nonroutine Reports....................... 9 a.
Events..................................................... 9 b.
Review of Licensee Event Reports (LERs)................... 10 6.
Surveillance Testing........................................... 11 a.
Scope..................................................... 11 b.
Findings.................................................. 11 7.
Maintenance and Modification Activities........................ 12 a.
Scope.................................................... 12 b.
Findings.................................................. 12 8.
Security......................................................
9.
Management Meetings............................................ 14 Attachment A - Surveillance and Maintenance Items A-1 Attachment B - Temperature Switch Drift B-1 <
_- . . . OETAILS 1.
Persons Contacted Within this report period, interviews and discussions were conducted with members of the licensee and contractor staffs and management to obtain necessary information for the subjects being inspected.
2.
Plant Status The reactor operated near full power throughout the report period.
3.
Followup on Previous Inspection Findings and TMI Action Plan Requirements (NUREG 0737) a.
Previous Findings (Closed) Unresolved Item 85-26-02): Review the need to compare and log moderator temperatures prior to starting a single idle recircu-lation pump. A licensee review indicated that thermal stratification could occur with one recirculation pump in service at low reactor power. A 1980 General Electric Service Information Letter (SIL) No.
251 discussed this potential problem.
The inspector requested that the licensee review recirculation pump starts in September 1985 for evidence of stratification. At that time, the licensee's procedures only required that a check for strat-
ification be made if both recirculation pumps were out of service. A caution statement in the pump start procedure, 2.1.9, did warn the operators against starting an idle pump if stratification had oc-curred.
However, the procedure did not require that a stratification check be made and logged if one pump was in service. One supervisor indicated that stratification would probably not occur as long as one pump was running.
The dome temperature must be inferred from the dome steam pressure. The licensee subsequently reviewed control room recorder data and determined that the maximum temperature difference between reactor coolant in the vessel dome and bottom head drain was 75 degrees F prior to recirculation pump starts on September 4, 5 and 7, 1985.
This was below the technical specification temperature lim-it of 145 degrees.
Based on this review, the inspector found no evidence that operators were not checking for stratification prior to starting a recircula-tion pump. Although the licensee's procedures did not always require that the reactor coolant temperatures in the vessel head and bottom drains be logged as required by Technical Specification 4.6.A, the procedure caution statements were adequate to warn operators about thermal stratification in the reactor vessel.
Licensee actions to correct the logging problem were prompt.
The inspector had no fur-ther questions. This item is closed, i r ., _. -.. _.. - -v -
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(Closed) Unresolved Item (293/85-03-08).
Scope of independent veri-fication program.
Procedure 1.3.34, Conduct of Operations, stated that independent verification is to be applied to ECCS, RPS, and PCIS systems. However, ECCS had little meaning to plant personnel and the scope was too broadly defined. The inspector reviewed Revision 8 of procedure 1.3.34 which had revised the scope to " nuclear safety system". This phrase has specific meaning to plant personnel and is further delineated in procedure 2.1.11, System Lineup File. This item is closed.
(Closed) Unresolved Item (293/85-03-09). Methods for performing in-dependent verifications.
The independent verification program had not provided clear written instructions on how independent verifica-tions were to be performed.
The inspector observed two operators working together on a valve lineup and its verification during in-spection 85-03.
The Plant Manager subsequently issued a memorandum M85-137 dated July 12, 1985, which specifically described acceptable methods of perform-ing independent verifications.
The memo prohibits the verifier from accompanying the individual performing a valve lineup. The inspector found this to be acceptable. This item is closed, b.
TMI Items (Closed) Item II.F.1.4, containment pressure monitor. The inspector reviewed the licensee's resolution of TMI Action Plan item II.F.1.4, Containment Pressure Monitor.
The licensee's design provides four pressure transmitters, two which cover -5 to +5 psig and two which cover 0 to 225 psig. These transmitters provide control room indica-tion recording and are separate from existing reactor protection instrumentation.
The inspector reviewed the design description in letter BEC0 82-152 dated May 25, 1982, the NRC safety evaluation issued March 25, 1984, and the revised technical specification requirements issued November 7, 1984. The inspector reviewed the installed indicators and record-ers in the control room, OPER 9 (daily log of the containment pres-sure parameters), and the I&C records of the calibrations and maintenance on the installed equipment.
The inspector concluded that the installed design met the TMI Action Plan requirements and the associated safety evaluation, and therefore item II.F.1.4 is closed. The inspector noted that the licensee is replacing the existing low range pressure transmitters with the same model of transmitter having a differential pressure capability. This will reduce any errors due to variations in atmospheric pressure.
The inspector noted that the entries under Test #53 in OPER 9 do not cover all the associated readouts.
Specifically, the two indicators
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are logged for the narrow range and the two recorders are logged for the wide range, but the low range recorders and the high range indi-cators are not logged.
In discussions with the inspector, the Chief Operating Engineer stated that this appeared to be an oversight and if so, OPER 9 will be revised to log the additional parameters.
Revision of OPER 9 is open item (293/85-28-01).
(Closed) Item II.F.1.5, containment water level monitor.
The inspec-tor reviewed the licensee's resolution of TMI Action Plan item II.F.1.5, Containment Water Level Monitor.
The licensee's design provides two cedundant channels of wide range containment water level indication and recording in the control room.
The inspector reviewed the design description in letter BEC0 82-148 , dated May 24, 1982, the NRC safety evaluation issued March 25, 1984 ' and the revised te;hnical specification requirements issued November . 7, 1984. The inspector reviewed the installed indicators and record-ers in the control room, OPER 9 (daily log of the containment water level), and the I&C records of the calibrations and maintenance on the installed equipment.
The inspector concluded that the installed design met the TMI Action Plan requirements and the' associated safety evaluation.
Item II.F.1.5 is closed.
4.
Operational Safety Verification a.
Scope and Acceptance Criteria The inspector observed control room operations, reviewed selected logs and records, and held discussions with control room operators.
The inspector reviewed the operability of safety-related and radiation monitoring systems.
Tours of the reactor building, turbine building,-station yard, switchgear rooms, diesel generator rooms, battery rooms, and control room were conducted.
Observations included a review of equipment condition, security, housekeeping, radiological controls, and equipment control (tagging).
The inspector also reviewed the licensee's preparation for cold weather operations.
These reviews were performed in order to verify conformance with the facility Technical Specifications and the licensee's procedures.
b.
Findings (1) The inspector toured the site and the intake structure during the inspection period, reviewing preparations for cold weather.
The inspector questioned the operability of two small exposed instrument lines connected to the fire water storage tanks.
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Flexible conduit originally protected the lines, but has since mostly rusted away. The licensee indicated that the lines were used to sense water temperature and activate tank heaters. The licensee stated that the missing conduit was in place as struc-tural protection for the lines, not temperature protection. At the exit interview, the licensee indicated that the effects of low temperature on the the lines would be evaluated. (Inspector Follow Item 85-28-05) The inspector had no further questions.
(2) On September 29, 1985, the inspector reviewed the results of an inspection of the salt service water bays.
Divers had inspected the bays for underwater debris.
No significant debris was found during the inspection.
Debris in the service water bays had previously plugged the suction of two salt service water pumps.
The inspector questioned the significance of missing pump re-straints noted during the dives.
The licensee indicated that the restraints were installed to minimize pump vibration during operation and had no seismic function (NED memo no. 77-490 dated August 17,1977).
The inspector has no further questions. No problems were identified.
(3) On September 26, 1985, the inspector noted that the inside latching mechanism was not functioning en the water tight door separating the heat exchanger rooms in the auxiliary bay. A maintenance request had been issued, but the repair was not giv-en high priority and was delayed several weeks. This door is relied upon to help prevent a single pipe break in one of the heat exchanger rooms from flooding the alternate heat exchanger room. The inspector discussed the implications of a door latch problem with licensee representatives.
Considering the design of the door and the drains in each room, the inspector agreed that only the outside door latch needed to be functional for the door to fulfill its intended safety function, i.e., slow leakage of water from one compartment to allow time for operator re-sponse to a pipe break.
Therefore, the delay in repairing (Se inner latch was acceptable.
The inspector had no further ques-tions at this time.
(4) On October 4,1985, a half scram occurred as licensee personnel prepared to conduct a surveillance test near a turbine condenser low vacuum pressure switch. Workers in the area apparently jarred the switch (PS-508-A) as they were preparing to conduct a test. The licensee later found a slightly loose switch wire on a terminal strip and a loose support for switch pressure tubing.
These problems may have made the switch sensitive to external vibrations.
The problems were repaired. The licensee reported the incident on the ENS telephone line.
The inspector had no further questions.
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8 (5) On October 4, 1985 at 6:45 p.m., the licensee declared the "A" emergency diesel generator inoperable after the drive belt for the shaft driven fuel oil pump broke. The same failure had oc-curred two weeks previously, on September 20, 1985. The belt was replaced and the diesel generator declared operable at 3:30 a.m. the next morning following post work testing.
The belt broke at an alligator clip fastener.
The fastener showed signs of wear at the point of both failures. The "A" diesel generator had been run seven times for a least one hour per run between the two belt failures.
The licensee discussed the problem with a vendor representative, but was not able to determine a root cause for the fastener failures.
Until a per-manent solution is devised, the licensee stated that the belt fastener would be visually inspected daily for evidence of wear.
No further instances of belt failure were noted during the in-spection period. The inspector had no further questions.
(6) On October 5, 1985 at 9:15 p.m., the licensee declared the "A" diesel generator inoperable after finding that the wrong type of lubricating oil had been added to the diesel crank case. The ^ wrong oil was requisitioned from the warehouse and added to the diesel due to a communication problem between the control room operators and an administrative assistant.
The assistant filled out a requisition for the oil and understood that the oil was for a different piece of equipment.
As corrective action, the licensee replaced the oil in the die-sel generator.
The licensee also issued a memo to all opera-tions personnel describing the incident and requiring operators to double check the station lubrication manual prior to adding any lubricant to station equipment.
The inspector had no fur-ther questions.
(7) On October 10, 1985, the "B" train of the control room environ-mental system failed a routine surveillance check and was de-clared inoperable.
The differential pressure across the filter train exceeded the technical specification limit of three inches of water at 1,000 cfm.
Following a filter and charcoal bed change in the unit, the differential pressure across the unit was still almost three inches of water.
The licensee declared the unit operable on October 16, 1985 af-ter demonstrating a pressure drop of 2.99 inches of water at 991.5 cfm.
The inspector questioned the acceptability of the test flow rate, since it was below the rate required by the technical specifications.
The licensee indicated that the tech-nical specification pressure requirement was too low and could only be met at lower unit flow rates. The licensee's test pro-cedure, no. 8.7.2.7, allowed flow rates as low as 900 cfm to be
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used.
The inspector reviewed system pressure drop tests for the last several years and noted that the licensee consistently re-ported test results at slightly less than 1,000 cfm.
An Engineering Department evaluation, memo NED85-1047, was com-pleted on October 11, 1985 and indicated that the manufacturer recommends that filters be changed when the pressure drop across each HEPA filter exceeds three inches of water.
However, the technical specifications require action when the pressure drop across the entire unit (consisting of a prefilter, a charcoal bed, and two HEPA filters) exceeds three inches of water.
Data taken following a HEPA filter changeout indicates that the two new HEPA filters have pressure drops of 1.6 and 1.7 inches of water.
A new charcoal bed produced an additional inch of pres-sure drop.
The prefilter produced 0.1 to 0.2 inch of pressure drop.
Based on this review, the inspector agreed that the cur-rent technical specification limit appeared overly restrictive.
At the exit interview, the licensee indicated that a technical specification change for this test was being processed.
The in-spector had no further questions.
(8) On October 15, 1985 at 6:48 p.m., the output breaker for the "A" diesel generator would not stay closed in on safety bus A5 dur-ing a routine surveillance test, The licensee initiated a plant shutdown and declared an unusual event due to the concurrent loss of the "B" loop of containment cooling.
The containment cooling loop had been previously taken out of service for envi-ronmental qualification modifications.
The shutdown and unusual event were terminated the next morning.
The licensee bench tested the diesel generator output breaker, but could find no problems.
Trip flags on two relays in the breaker logic circuit, an antimotoring relay and a voltage bal-ance relay, were evaluated, but did not contribute to the break-er problem.
The breaker was subsequently returned to service and the diesel successfully tested at 1:40 a.m. on October 16.
The diesel generator was also run the following day without in-
- ident.
At the exit interview, the licensee indicated that no root cause had been identified for the breaker problem.
No fur-ther incidents of this type occurred during the inspection peri-od.
The inspector had no further questions at this time.
(9) On October 17, 1985, the inspector interviewed two licensed op-erators who had indicated that they were working overtime "under protest" in the control room log.
Both operators stated that they were mentally and physically alert for the shifts that they worked under protest.
They also were aware of their responsi-bility to inform licensee management if they felt unable to per-form their licensed dutie. .
The operators were concerned that they would be asked to work the 8:00 a.m. watch after having worked the previous watch.
They felt that this was unreasonable, considering the added strain of the day watch activities.
The inspector discussed the concern with the licensee. The licensee indicated that licensed individuals would not be forced to work if they were physically or mentally incapable of conducting their duties. Additional operator overtime has been required in the past few months because of an ongoir.g shortage of licensed operators.
The inspector did not find evidence that operators were overly fatigued and unable to perform their licensed duties during the inspection period. The inspector had no further questions at this time.
(10) On October 25, 1985, the inspector attended a meeting of the Nuclear Safety Review and Audit Committee (NSRAC).
This commit-tee normally meets once per month at the licensee's corporate of*1ce. The meeting frequency and meeting quorum exceeded the technical specification requirements.
The discussion during the meeting was forthright and focused on safety matters.
The mate-rial under review had been distributed to committee members pri-or to the meeting. A meeting agenda was prepared and followed.
Several meeting items were rejected by the committee due to a lack of detail or justification.
No problems concerning the NSRAC meeting were identified.
(11) On October 29, 1985 at 4:15 a.m., a security guard noticed smoke coming from a nonsafety 480 V electrical circuit breaker, no.
506.
The breaker powers the service air blower from bus 85.
The inspector discussed the breaker failure with licensee per-sonnel. The breaker, an AK-5A-25, was subsequently examined and found to have a burned trip coil.
The licensee indicated that the breaker had been bought refurbished as a non-Q breaker dur-ing the last outage. None of the refurbished breakers were used in safety related equipment. At the end of the inspection, the licensee's evaluation of the root cause of the breaker failure had not been completed.
The inspector concluded that the fail-ure was isolated and not safety related. The inspector had no further questions at this time.
(12) On October 29,1985 at 1:15 a.m., a half scram trip was initiat- - ed during a routine surveillance test when an I&C technician inadvertently set a multimeter to measure current instead of voltage.
The technician was attempting to perform test no.
8.M.1-13, main steam line radiation monitor calibration, when the incident occurred. The licensee indicated that the tech-nician was experienced and had completed the surveillance test several times before. The main steam line monitor was promptly
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repaired and returned to service.
The technician was counsel-led. The inspector concluded that this was an isolated person-nel error and had no further questions.
(13) On October 29, 1985 during the evening, the inspector toured the reactor building, including all the quadrant rooms and the "B" residual heat removal (RHR) valve room.
Loose trash and tools on the floor was observed in several areas of the building.
In addition, loose protective clothing (coveralls, slipons, and gloves) were also noted on the floor at several locations. A pool of potentially contaminated water was noted at the bottom of the "A" RHR quadrant stairs.
Also, a floor fan was found taped to the body of a manual con-tainment penetration isolation valve in the "B" RHR valve room.
The licensee removed the floor fan from the valve room and checked that the isolation valve was in its normal position (closed). The fan was apparently used with the knowledge of the health physics group in the contaminated area during welding to clear area smoke.
Contamination levels were low, less than 10,000 dpm per 100 square cm.
Health physics management stated + hat in the future, ventilation suction instead of a floor fan would be used in contaminated areas.
The licensee counselled workers in the area not to tape equipment to valve bodies.
The inspector discussed the ongoing trash problem in the reactor building with the licensee.
The licensee stated that each prob-lem area was inspected and cleaned. A program is being devel-oped which will assign responsibility for housekeeping in various sections of the plant to individuals. Housekeeping will be evaluated further during future routine tours of the plant.
The inspector had no further questions at this time.
(14) On October 31, 1985, at 8:15 a.m., a stream of water was ob- < served flowing out of a reactor building ventilation duct above the west CRD hydraulic control units.
The water had backed up into the ventilation system during a resin transfer from the "E" ' condensate demineralizer to the cation regeneration tank. A block valve which isolates the demineralizer from the condensate system ras not fully closed during the transfer. The condensate pressure forced water and resin back up into the demineralizer vent system, through a resin trap, and into the reactor building contaminated exhaust system.
Radwaste operators quickly isolat-ed the demineralizer after receiving high level alarms.
No res-in was found downstream of the resin trap. The water was slightly contaminated (10,000 dpm on a wet smear). Although water sprayed on several pieces of plant equipment during the incident (CRD hydraulic control units, motor control center en-closures, and scram discharge volume level instrumentation), no subsequent equipment problems were noted.
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The "E" condensate demineralizer was kept out of service until the end of the assessment period.
Licensee corrective actions will be reviewed during a subsequent inspection (85-28-02), 5.
Followup on Events and Nonroutine Reports ! a.
Events (1) On October 27, 1985, hurricane Gloria was in the vicinity of the station. The licensee secured all loose material around the ' plant, reduced power to approximately 25%, and took the genera-tor offline in preparation for the storm. These actions were in accordance with licensee procedure no. 5.2.2.
No storm damage ' was sustained. The inspector monitored storm preparations and was onsite during the height of the hurricane. No problems were identified.
(2) On September 27, 1985 at about 11:30 a.m., the inspe(cor was notified that the mast on the refueling bridge had besu found in a damaged condition.
Fuel movement was last conducted on Sep- ' tember 26, 1985. The mast was found in the lowered state with the end grapple latched onto an irradiated fuel assembly. The refueling bridge trolley had been moved sideways with the mast lowered, bending the mast. After discovering the problem on September 27, licensee personnel were able to meve the trolley backwards, unlatch the fuel assembly, and partially raise the mast. The licensee noted the problem at 9:15 a.m. that morning.
The inspector examined the refueling britje cn September 27, and discussed the sequence of events with the Licensee's Chief Tech-nical En-ineer. A special team inspection of the incident was subsequei.tly conducted, NRC inspection no. 50-293/85-29.
On October 8, 1985, the inspector observed a reenactment of the refuel bridge incident, performed under Temporary Procedure (TP 85-95-2.
The personnel who had been on the bridge during fuel movements on September 26, 1985, participated in the reenact-ment.
The reenactment demonstrated that the grappler could have remained attached to a fuel assembly and the trolley could have moved the roughly six feet distance to the railing opening on the bridge at the end of the authorized fuel movement activity.
. (3) On October 15, 1985 at 6:48 p.m., a reactor shutdown was initi-ated and an unusual event declared due to the concurrent loss of the "A" diesel generator and the "B" loop of containment spray.
This event was discussed in section 4 of this report.
(4) On November 4, 1985 at 10:30 p.m., the licensee initiated a re-actor shutdown and declared an unusual event due to the -ncur-rent loss of the MO-1001-36A valve in the containment cooling < i -.. , .m., m m ..., - _. ~,_ - _.. - - _ _,.., _. -_ ._.
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. . system and the low pressure coolant injection (LPCI) system.
The event and the shutdown were terminated on October 15, 1985, after the M0-1001-36A valve was returned to service.
I The licensee declared the "A" loop of the containment cooling system inoperable when the M0-1001-36A valve would not open during a containment cooling valve surveillance test, no.
8.5.2.1.
This valve, a block valve for the torus cooling line, does not need to be open for containment cooling (i.e., torus < spray) operability.
However, the licensee declared the cooling ' ' loop inoperable because the surveillance test could not be com-pleted as written.
The LPCI system was concurrently out of ser-vice for environmental modifications to system components.
Additional revir.w of the failure of the M0-1001-36A valve will
7 be documented '.n the next monthly inspection (85-28-03).
b.
Review of Licensea Event Reports (LERs)
Licensee Event '<eports were reviewed to verify that the details were clearly reported and that corrective actions were adequate..The in-spector also cetermined whether generic implications were involved and if on site followup was warranted.
e The events described in the LERs were reviewed during the NRC inspec-tions listed below: , NRC , LER No.
Insp. No.
Subject i 85-21 85-20 Main Steam Line Radiation Monitors "B" and "C" Outside Technical Specification Limits 85-22 85-20, Hot Shop Ventilation Contamination 85-22 85-23 85-26 HPCI System Inoperable P 85-24 85-17 Missed Surveillance Test on Station Batteries - 85-25 85-26 Reactor Scram on Load Rejection 85-26 Not Reviewed Inadequate Surveillance Procedure for i Control Rod Position Indication 85-27 85-26 LPCI Injection Valve Inoperable LER 85-24 was reported two months late. The licensee indicated that
the event was reported late because NRC identified the problem and
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licensee personnel did not initiate a Failure and Malfunction Report (F&MR) prior to taking corrective action.
The F&MR triggers the licansee's reportability evaluation.
In the future, the licensee plans to initiate F&MR's more promptly for NRC findings. This inci-dent is isolated. The inspector had no further questions concerning this LER.
The inadequate surveillance test procedure described in LER 85-26 was identified by a licensee Quality Assurance Audit.
The failed LPCI injection valve motor operator was reviewed during a special NRC team inspection, no. 50-293/85-30.
No additional LER problems were identified.
6.
Surveillance Testing a.
Scope The inspector reviewed the licensee's actions associated with sur-veillance testing in order to verify that the testing was performed in accordance with approved station procedures and the facility Tech-nical Specifications.
A list of the items reviewed is included in Attachment "A" to this report.
b.
Findings On October 24, 1985, the licensee found that the set point for a HPCI area temperature switch, TS-23738, had drifted above the technical specification limit of 170 degrees F during a routine surveillance test. The as found set point was 172.5 degrees F.
The inspector reviewed previous switch calibration data and noted that the switch set point was stable.
However, the inspector questioned the adequacy of the method used to calibrate temperature switches in the plant.
These switches are used to sense steam line breaks and isolate prima-ry containment. They are also used to activate safety related area coolers in the reactor building.
The licensee maintains two duplicate sets of temperature switches for each plant function with one set installed and one set in storage.
The switches are changed out quarterly.
The as found settings of the switches are determined and the switches are calibrated and stored in unlocked drawers in the I&C lab in the reactor building until the next changeout. At the end of the quarter, the stored switches are installed without additional calibration.
The technical specifications require that the switches be calibrated every three months. Although the temperature switches are changed every three months, the switches are only calibrated once every six months.
The licensee indicated that the switches stored in the I&C
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lab were stable and not subject to significant drift.
The inspector requested data to support this statement.
The licensee subsequently reviewed set point drift that occurred dur- - ing the 1984 outage. The data (Attachment B) shows that drift did occur, although the no switch drifted above the technical specifica-tion limit. The maximum drift was'-10 degrees F over 14 months of storage. Component failure data indicates that only 13 switches have drifted out of the technical specification limits since 1972.
Based on this review, the inspector agreed that the switches were generally stable.
However, control over the stored switches was weak with minimal restraints on the stored switches. The licensee also had no means of ensuring that the stored switches were not disturbed, prior to installation.
The licensee committed to take the following actions to strengthen the calibration process: -- Switches will be stored in individual padded compartments in the I&C lab drawers.
The switch storage drawers will be locked.
-- The switch calibration will be performed just prior to install- -- ing the switches, rather than just after removal from the plant.
Switch calibration data sheets will be incorporated into the -- station procedures. Currently, this data is kept separately on forms that are not controlled by procedure.
The inspector had no further questions concerning temperature switch calibration at this time.
(Inspector Follow Item 85-28-06) 7.
Maintenance and Modification Activities a.
Scope The inspector reviewed the licensee's actions associated with mainte-nance and modification activities in order to verify that they were conducted in accordance with station procedures and the facility Techni~al Specifications. The inspector verified for selected items c that the activity was properly authorized and that appropriate radio-logical controls, equipment tagging, and fire protection were being implemented.
A list of the items reviewed is included in Attachment "A" to this report.
b.
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The inspector reviewed the licensee's method of scheduling preventa-tive maintenance described in procedure 1.8.1, "PM Tracking Program".
The licensee indicated that some preventative maintenance had been delayed, due to the workload imposed by current plant modifications.
Discussions with maintenance personnel and a review of the PM comput-er listing indicated the following weaknesses in the PM tracking program: -- The listing of overdue PMs was inaccurate.
Many PMs were listed as overdue, some with due dates in 1983.
Some items listed as overdue are no longer used in the plant. The scheduling fre-quencies for other PMs were incorrect.
Calibrations for some test equipment were listed as overdue, when the equipment was normally calibrated before use (and not calibrated at a routine
frequency).
Some PMs were not updated in a timely manner at the completion of maintenance.
-- Notes of explanation for the overdue PMs were not uniform, mak-ing the notes unclear to some of the maintenance managers who are responsible for reviewing the listing. Many overdue items had no explanation notes.
-- Variance reports for overdue items are required by procedure to be sent to the Station Manager for review.
However, these re-ports have not been prepared for several years, apparently be-cause the licensee group sho originally issued the reports was reorganized.
The successor group issued the PM listings, but ' not the variance reports.
-- Responsibility for scheduling and tracking PMs was largely dele-gated to the first line supervisors in the Maintenance Depart-ment.
While maintenance management at the station was generally aware of the status of overdue PMs, the first line supervisors were most familiar with the list and made PM schedul-ing decisions. One of these supervisors indicated that the PM listing was not useful because it was so inaccurate.
In response to this finding, the licensee indicated that the PM list-ing would be updated.
Variance reports to station management were promptly prepared and issued. Also, the licensee is reviewing the PM tracking procedure and indicated that it would be revised to make the program more useful.
The inspector had no further questions at this time. The adequacy of the PM tracking program will be reviewed during a future routine inspection (Inspector Follow Item 85-28-04).
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8.
Security a.
On October 24, 198E, the licensee failed to take prompt compensatory action for a degraded security system.
The inspector noted that the event was similar to six previous events reported to the NRC earlier this year. The licensee subsequently agreed to discuss the recurring problem and corrective actions in the response to a recent security civil penalty, NRC inspection 50-293/85-24.
The lack of action to correct this problem is considered to be a re-flection of the weaknesses discussed in the civil penalty.
The licensee's corrective actions will be reviewed during the followup to inspection 85-24.
b.
On~0ctober 24, 1985, the_ inspector observed an individual kicking a security card reader. The licensee promptly restricted the individu-al's access to plant vital areas and verified the operability of the card reader. The individual stated that he was frustrated with the operation of the security device and had not previously kicked a reader.
The individual _was instructed or, the importance of security devices.
The inspector interviewed the individual and was satisfied that the incident would not recur. The inspector had no further questions.
9.
Management Meetings During the inspection, licensee management was periodically notified of the preliminary findings by the resident inspector. A summary was also provided at the conclusion of the inspection and pria.' to report issuance.
No written material was provided to the licensee during this inspection.
k
. . ATTACHMENT A TO INSPECTION REPORT 50-293/85-28 The following surveillance and maintenance items were reviewed during the re-port period.
Portions of the following surveillance tests were reviewed: , Control room high efficiency filter unit tests, procedure 8.7.2.7.A, -- conducted during October, 1985 and previous tests in 1984 and 1983.
' Compensatory surveillance tests conducted between September 30 and October -- 11, 1985 while safety equipment was inoperable.
Diesel generator test, procedure 8.9.1, on October 16 and 17, 1985.
-- -- Vessel metal temperature surveillance test during a plant start up on Sep-tember 5, 1985.
Plant temperature switch calibrations for safety-related equipment con- -- ducted during September, 1985 and during the 1984 outage.
Portions of the following maintenance and modification activities were reviewed: -- -MR 85-619, Panel alarm for loss of DC power comes in MR 85-617, "A" diesel generator breaker will nnt close in -- -- MR 85-605, Wrong lube oil added to the "A" diesel generator -- MR 85-596, Repair RIT 1001-606A --- MR 85-10-66, Perform Movats tests per TP 84-274 on valve 1001-34B , ! , -,. _... % __._,s, .r...,, _ _, _ _ _.,., _.. ,_-..,,--,,r,,.,,_.r.
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. . . ATTACHMENT B TO INSPECTION REPORT 50-293/85-28 TEMPERATURE SWITCH DRIFT The licensee reviewed temperature switch calibration data for the 1984 outage and calculated the following average drifts in set points.
Total Set Point Drift * No. of Stability Switches Switches System Switches Period Stored in Lab In Service Main Steam
14 mo.(storage) 4.0 1 2.4 F 2.6 1 1.6 F Line 17 mo (in service) Reactor Water
9 mo (storage) 1.5 1 1.0 2.4 1 1.6 Cleanup 11 mo (in service) High Pressure
12 mo (storage) 1.4 1 1.4 1.5 1 1.2 Coolant Injection 15 mo (in service) Reactor Core
10 mo (storage) 2.1 1 1.6 2.2 1 1.8 Isolation 15 mo (in service) Cooling
- Table values represent the average of the absolute values of set point drifts 1 one standard deviation. The set point drift values are expressed in units of degrees fahrenheight.
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