IR 05000261/1995030
| ML14181A800 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 01/26/1996 |
| From: | William Orders, Shymlock M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A798 | List: |
| References | |
| 50-261-95-30, NUDOCS 9602120106 | |
| Download: ML14181A800 (22) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 Report No.:
50-261/95-30 Licensee:
Carolina Power & Light Company P. 0. Box 1551 Raleigh, NC 27602 Docket No.:
50-261 License No.:
DPR-23 Facility Name: H. B. Robinson Unit 2 Inspection Conducted: November 26 - December 31, 1995 Lead Inspeco
,t~
a Orde, Senior Resident Inspector Other Inspector: J. Zeiler, Resident Inspector J. Coley, Region II Inspector B. Crowley, Region II Inspector Approved by:
_____
Milton B. Shyrdock, Chief Date Sign Reactor Projects Branch 4 Division of Reactor Projects SUMMARY SCOPE:
Inspections were conducted by resident and regional inspectors in the areas of plant operations, maintenance and surveillance, engineering, and plant support. As part of this effort, backshift inspections were conducte RESULTS:
Plant Operations An out-of-date valve lineup was used to verify proper configuration of the steam driven auxiliary feedwater system prior to its operation and testin This was an administrative deficiency that had minimal safety significance and was promptly corrected by the licensee (paragraph 2.2). A power reduction to perform routine turbine valve testing was accomplished in a controlled manner (paragraph 2.3).
Enclosure 2 9602120106 960126 PDR ADOCK 05000261 G
Maintenance Various maintenance activities were observed to be well-planned and conscientiously executed (paragraph 3.1 and 3.5).
An inadequate Safet Injection Accumulator level calibration procedure contributed to level indication inaccuracies and was identified as a violation. Also contributing to this problem was ineffective corrective actions to address level transmitter sensing line configuration problems (paragraph 3.3).
Following oil sampling for a spent fuel pool cooling pump an oil sightglass was not restored to its proper leve It was determined that the technician did not have a good understanding of the bearing reservoir volume or fundamental principles involved in the operation of the oiler (paragraph 3.4).
Engineering Reactor engineering provided good support to operations during the power maneuver for turbine valve testing (paragraph 2.3).
Plant Support The ALARA pre-brief and associated radiological controls for conducting maintenance and testing inside containment were comprehensive and well controlled (paragraph 5.1.2).
Enclosure 2
REPORT DETAILS PERSONS CONTACTED Licensee Employees
- B. Clark, Manager, Maintenance J. Clements, Manager, Site Support Services
- D. Crook, Senior Specialist, Licensing/Regulatory Compliance
- D. Gudger, Senior Specialist, Licensing/Regulatory Programs
- C. Hinnant, Vice President, Robinson Nuclear Plant
- J. Keenan, Director, Site Operations R. Krich, Manager, Regulatory Affairs
- B. Meyer, Manager, Operations
- G. Miller, Manager, Robinson Engineering Support Services J. Moyer, Manager, Nuclear Assessment Section D. Stoddard, Manager, Operating Experience Assessment
- R. Warden, Superintendent, Plant Support Assessment
- T. Wilkerson, Manager, Environmental Control
- D. Young, Plant General Manager Other licensee employees contacted included office, operations, engineering, maintenance, and chemistry/radiation personne NRC Personnel W. Orders, Senior Resident Inspector
- J. Zeiler, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragrap.0 PLANT OPERATIONS (71707 and 92901) Plant Status The unit operated at or near full power for the entire report period with no major problem.2 Plant Operations Observation Activities The inspectors evaluated licensee activities to determine if the facility was being operated safely and in conformance with regulatory requirements. These activities were assessed through direct observation of ongoing activities, facility tours, control room observations, discussions with licensee personnel, evaluation of equipment status, and review of facility records. The inspectors evaluated the operating staff to determine if they were knowledgeable of plant conditions, responded properly to alarms, and adhered to procedures and applicable administrative control Enclosure 2
Selected shift changes were observed to determine that system status continuity was maintained and that proper control room staffing existed. Routine plant tours wqe-e conducted to evaluate equipment operability and to assess the general condition of plant equipmen On December 13, 1995, the inspectors witnessed and reviewed aspects of monthly testing to verify operational readiness of the steam driven auxiliary feedwater pump and valves. This test was performed in accordance with operations surveillance test, OST 202, Steam Driven Auxiliary Feedwater System Component Tes Testing involved operating the pump in full flow recirculation with suction from the condensate storage tank. The inspectors noted that the procedure provided detailed instructions and precautions. At the operations pre-briefing, personnel responsibilities were clearly delineated and emphasis was placed on personnel using good self-verification techniques. The inspectors reviewed the pump test results which adequately demonstrated that the pump was operating within acceptable design parameter While verifying that OST-202 prerequisites were properly completed, the inspectors identified one weakness. Step required verification that the auxiliary feedwater system was aligned in accordance with operating procedure OP-402, Auxiliary Feedwater System. The intent of this step was to review the latest completed valve checklist performed in accordance with OP-402. The operator who completed this step indicated that a valve checklist performed on January 13, 1994, was reviewed. The inspectors later determined that a more recent valve checklist was completed June 1, 1995, prior to startup from the last refueling outage. This checklist was contained in an unmarked binder located in the control room. The inspectors considered this problem to be the result of not adequately controlling the use of, and not clearly communicating the location of, necessary plant information. The out-of-date material was subsequently removed from the control room and operations personnel were instructed on the proper use and location of the up-to-date information. The inspectors determined that this problem had minimal safety consequence since auxiliary feedwater system alignments had been verified during previous monthly system testing. The licensee's corrective actions were considered adequate for this proble.3 Turbine Valve Testing and Associated Power Reduction On December 16, the licensee initiated a power reduction to 65 percent in order to perform routine quarterly testing of the turbine control valves. The inspectors noted that reactor engineering personnel provided good support to this activit Prior to the power reduction, reactor engineering personnel Enclosure 2
performed an evaluation of the planned power maneuver. It was determined that no special actions were necessary to control the core power distribution or core reactivity during the power reduction or ascension. The operators were supplied with graphs and tables to aid them in determining the effects of the xenon transient on core reactivity. Reactor engineering personnel were also present in the control room during the power maneuver to monitor the response of the reactor cor Turbine valve testing was performed satisfactorily following the downpower to 65 percent in accordance with OST-551, Turbine Valve and Trip Functional Test. While performing this procedure, a steam leak developed in a level transmitter flange connection to the 2B Moisture Separator Reheater drain tank. The operators effectively isolated the leak and were able to complete this testing and return to full power operation without any further complication.4 10 CFR 50.9 Report Submittal for Technical Specification Nonconservatism By letter dated December 4, 1995, the licensee submitted a 10 CFR 50.9 report to the NRC after identifying a Technical Specification condition that could allow operation in a condition outside the current UFSAR Chapter 15 Accident Analysi The issue involved TS 3.10.6.2, which allows continued reactor operation with one inoperable control rod. During a review of the licensing basis for this TS, the licensee noted that the UFSAR Chapter 15 Accident Analysis assumes the most reactive control rod fails to insert into core when the accident occurs. If one control rod was already inoperable as permitted by TS 3.10.6.2, failure of another control rod would be beyond the current design basis analysi The inspectors noted that currently, there were no inoperable control rods. However, the licensee indicated that in 1980, operation with an inoperable control rod (in core location L-11)
occurred during operating cycle 8. The inspectors reviewed the licensee's safety analysis dated November 6, 1980, evaluating the safety impact of operation with the inoperable control rod. The results of this evaluation showed that reactor operation with control rod L-11 withdrawn and inoperable would have no adverse impact on the safety aspects of the core. The inspectors noted that this evaluation included the impact of operation with the inoperable control rod in addition to the failure of the most reactive control ro The licensee planned to revise TS 3.10.6.2 as part of their conversion to the Improved Standardized Technical Specification Enclosure 2
In the interim, administrative controls were implemented to prevent continued operation should a control rod become inoperable. The inspectors reviewed operations night order 95-051, implemented on November 29, 1995. This night order required the operators to enter TS 3.0, requiring unit shutdown, should an inoperable control rod be identified. The inspectors considered this to be adequate interim actions until TS 3.10. was revise.5 Close Out Issues (Closed) VIO 50-261/93-19-01:
Operator Deviation from OST-005 Results in Turbine Runback This issue involved a turbine runback that was initiated as a result of an operator repositioning the dropped rod mode switch instead of the operation selector switch while performing OST-005, Nuclear Instrumentation Power Range Test. Testing was interrupted when the operator was requested to assist in another task. Upon resuming the test, the operator inadvertently positioned the incorrect switch. The licensee attributed this personnel error to failure to apply adequate focus and self-checking practice The licensee responded to this violation via letter dated November 3, 1993. Corrective actions included counseling the operator who made the error, as well as reviewing the event with all other operations personnel emphasizing the need for greater self-verification, especially when tasks were interrupted. The inspectors reviewed operations personnel training records verifying that these corrective actions had been complete (Closed) VIO 50-261/94-13-01: Operator Left At-the-Controls Area, in Violation of 10 CFR 50.54 Requirements CP&L's operations management manual procedure OMM-001, Operations Conduct of Operations, requires in part that the control operator on duty must remain within the area defined by "...the walled partition, the 230 kilovolt line panel and the black stripes bordering the control room carpet."
Contrary to the above, on April 22, 1994, with the unit operating at 100 percent power, the control operator on duty was not present at the controls area for a short period of tim The licensee responded to this violation, including corrective actions to prevent recurrence, by letter dated June 29, 1994. The inspector verified that the following corrective actions were taken by the licensee for the above discrepancy: (1) the Operations Manager issued a memo to all licensed operations personnel describing the circumstances and consequences of the Enclosure 2
5 event, procedure requirements and management expectations, (2) a formal process for shift turnover was established, (3) training was given to operations personnel on this incident and simulator training now covers shift turnover and the formal performance of duties at all times, (4) two operations night orders were issued providing guidance and expectations, and, (5) OMM-001, "Operation Conduct of Operations," was revised to include turnover requirements. The inspectors determined that licensee corrective actions had been adequately implemented. This item is close (Closed) VIO 50-261/94-15-03:
Failure to Take Adequate Corrective Action to an Out-of-Specification BAST Boron Concentration On May 4, 1994, control room operators failed to take prompt corrective actions after being provided with chemistry sample results which indicated that the boric acid concentration in the A Boric Acid Storage Tank was in excess of the concentration allowed by TS 3.2.2c. The fact that the boric acid concentration was in excess of the maximum allowable concentration went unrecognized for almost seven hour The licensee responded to this violation via letter dated July 15, 199 During this inspection, the inspector examined the following corrective actions taken by the licensee for the above discrepancy: (1) operations shift crew members were reassigned to different crews to reduce complacency and improve the collective knowledge and doilities of the operating crews, (2) a stand-down meeting was conducted with operations personnel, (3) chemistry procedure CP-001 was revised to reflect the limits of appropriate parameters (the revision also included notifying the shift supervisor when limits were exceeded and re-sampling when exceeding any limit), (4) the manual graph for trending BAST boron concentration was updated on the days the tanks are sampled and analyzed to more quickly identify out-of-specification concentrations, and (5) chemistry technicians/supervisors were counselled on the importance of procedure adherence and resampling/reporting of out-of-specification parameters. The inspectors determined that licensee corrective actions had been adequately implemented. This item is close (Closed) VIO 50-261/94-16-01:
De-energized Containment Vessel Water Level Instrument On May 26, 1994, control room operators failed to detect that safety related level instrument LI-802, Channel II, Containment Vessel Water Level, was de-energized for approximately an hour, until a related display of CV water level was questioned by the inspector Enclosure 2
The licensee responded to this violation via letter dated August 5, 1994. The inspectors verified that the following corrective actions for the above discrepancy had been implemented by the licensee: (1) the event had been reviewed with all operation crews, (2) OMM-008, Minimum Equipment List and Shift Relief, was changed to require a full scale reference check of the CV water level channels twice per month instead of once per shift, since TSs only require this check once per shift, (3) a review was also performed to determine if there were any other readings/manipulations being done that were unnecessary, and, (4)
disciplinary action was taken with the individuals involved. The inspectors determined that the licensee's corrective actions were sufficient to prevent recurrence and had been completed. This item is close.0 MAINTENANCE (61726, 62703, and 92902) Maintenance Observations The inspectors observed maintenance activities on systems and components to determine if the activities were conducted in accordance with regulatory requirements, approved procedures, and appropriate industry codes and standards. The inspectors reviewed selected administrative materials, testing, radiological, and fire prevention controls requirements to determine licensee complianc The inspectors witnessed and/or reviewed portions of the following maintenance activities:
WR/JO 95-AIMY1 Replacement of SGB System Valve SGB-38A WR/JO 95-ADFIH Replacement of SGB System Valve SGB-58A WR/JO 95-APNC1 Replacement of SGB System Valve SGB-56A WR/JO 95-ADSA1 Replacement of Valve Position Indicator Lights and Sockets for Valve FP-248 WR/JO 95-ADSC1 Replacement of Valve Position Indicator Lights and Sockets for Valve FP-256 WR/JO 95-ADSD1 Replacement of Valve Position Indicator Lights and Sockets for Valve FP-258 WR/JO 95-ADSB1 Replacement of Valve Position Indicator Lights and Sockets for Valve FP-249 WR/JO 95-APWD1 Repair of IA compressor C Free Air Regulator WR/JO 95-ALPJ1 Replace Motor Pinion Key on Motor Operator for Valve SGB-VI-31 WR/JO 95-APUW1 Troubleshooting Al Battery Charger Current Fluctuations 3.1.1 WR/JOs 95-AIMY1, 95-ADFI1, and 95-APNC1 were issued to replace leaking SG A Blowdown System manual valves. Similar valves had also been leaking and were replaced for the other two SGs. Discussions with the system engineer revealed that Enclosure 2
- these manual valves were leaking due to seat/disc erosion because they were being used as throttling valves. The manual globe valves had been used for throttling to the flash tank. The regular throttling valves were ineffective due to a design flow of 300 gpm versus a needed flow of 50 gpm. Plans are to replace the throttling valve internals by June, 199 For the WR/JOs associated with replacement of the SGB valves, the inspectors reviewed the in-process work packages and observed various in-process work activities, including valve disassembly and/or removal, preparation of piping for new valves, and welding of the new valves into the syste Craft knowledge and qualification for the tasks performed were reviewed/evaluated. In addition, for WR/JO 95-APNC1, the inspectors witnessed liquid penetrant inspection of the root pass for welds WI and W2 and verified examiner qualification and the use of certified penetrant material Also, for all welds associated with WR/JOs 95-AIMY1, 95 ADFI1, and 95-APNC1, the inspectors reviewed welder qualification and welding material testing and certification record.1.2 WR/JOs 95-ADSA1, 95-ADSBl, 95-ADSC1, and 95-ADSD1 were issued to change out the MCC indicating lights and sockets for Fire Protection system valves FP-248, FP-249, FP-256, and FP-258. This was being done as part of a management decision to standardize indicating lights for all safety related MCCs. The inspectors observed change-out of the lights and sockets, observed post-maintenance testing (valve cycling) after the change-out, reviewed the in-process work packages, verified compliance with applicable procedures, verified use of appropriate calibrated tools, and verified qualification of technicians. This work was accomplished under a TS four hour LCO. The inspectors verified that TS requirements were met for the LC.1.3 WR/JO 95-APWD1 was issued to troubleshoot and repair the C IA compressor. The compressor relief valve was lifting after the compressor unloaded. The inspectors observed a test run of the C IA compressor following maintenance repair of the Free Air Regulator. This repair did not correct the problem with the relief valve lifting. Next, the Pressure Suction Unloaders were removed and leak tested. The inspectors observed removal, leak testing, and disassembly of the Unloaders. The Unloaders had not been re-installed at the close of the inspectio.1.4 WR/JO ALPJ1 was issued to replace the motor pinion key on SGB system motor operated valve SGB-VI-31. The inspectors Enclosure 2
observed post-maintenance testing (valve cycling) after replacement of the pinion key and reviewed the completed work package, including Attachment 8.22 (Maintenance Data Sheet) for CM-113, Motor Operator Overhau.1.5 WR/JO 95-APUW1 was initiated on December 12, 1995, to investigate current fluctuations on the Al 125 Volt DC station battery charger. This work request package contained detailed precautions for work on the charger while in the standby mode of operation. Good engineering involvement was observed in determining the necessary data to obtain for troubleshooting the problem. The current fluctuations were decreased by the replacement of the charger amplifier board and firing modules, however, small fluctuations were still observed on both the Al, and A battery chargers. Engineering personnel believed the problem was actual system load fluctuations on the battery bus. At the end of the report period, the licensee was continuing to troubleshoot this proble The maintenance activities observed were well-planned and conscientiously executed. Personnel were qualified for the tasks performed. No violations or deviations were identified. Based on the information obtained during the inspection, the maintenance program was adequately implemente.2 Surveillance Observations The inspectors evaluated certain surveillance activities to determine if these activities were conducted in accordance with license requirements. For the surveillance test procedures listed below, the inspectors determined that precautions and LCOs were adhered to, the required administrative approvals and tagouts were obtained prior to test initiation, testi.ng was accomplished by qualified personnel in accordance with an approved test procedure, test instrumentation was properly calibrated, the tests were completed at the required frequency, and the tests conformed to TS requirements. Upon test completion, the inspectors verified the recorded test data was complete, accurate, and met TS requirements, test discrepancies were properly documented and rectified, and the systems were properly returned to servic Specifically, the inspectors witnessed and/or reviewed portions of the following test activities:
MST-14 Steam Generator Pressure Protection Channel Testing (Monthly)
MST-20 Reactor Protection Logic Train "A" at Power (Monthly)
MST-22 Safeguard Relay Rack Train "A" (Monthly)
Enclosure 2
The test procedures contained detailed instructions that clearly delineated the individuals (either I&C technician or operator) who were responsible for performing each step. Each -st was preceded by an operations pre-brief detailing the scope of the test, necessary precautions, and contingencies for potential problem The inspectors noted operations and I&C personnel using sound powered headsets which contributed to promoting good communications. Coordination observed between the individuals was goo I&C technicians were verified to be qualified for the tests performed and were observed to be knowledgeable of the procedures used and equipment operate For the maintenance and surveillance activities observed, the inspectors concluded that the maintenance and surveillance programs were being effectively implemented. No violations or deviations were identified in this functional are.3 Inadequate Safety Injection Accumulator Level Transmitter Calibrations On November 29, the licensee determined that as a result of level transmitter calibration errors, actual water volume in the B and C SI Accumulators had been less than that indicated since startup from the previous refueling outage in June 199 Accumulator level transmitter discrepancies were first identified on November 22, 1995, after repairing a nitrogen gas leak in the sensing line (dry reference leg) associated with LT-926, one of the two B accumulator level transmitters. When the transmitter was returned to service, it indicated approximately 7 percent higher than the indication prior to the repairs (66 percent), and the other B accumulator level transmitter (LT-924) indicatio As-found calibrations were performed on LT-924 and LT-926, which confirmed they were approximately 318 millivolts (equivalent to 7.9 percent level) above the allowable calibration upper toleranc The licensee assembled a team to investigate the root cause of the level transmitter discrepancies. From review of transmitter calibration records performed during the previous refueling outage (June 1995), the licensee discovered that the output calibration for LT-926, as well as LT-928, one of the two C accumulator transmitters, had been "zero shifted" after initial calibration by large amounts. These calibration shifts were performed in order to force the output indication of the two transmitters on the same accumulator to agree with each other. As a result of this discovery, the licensee performed an as-found calibration check of LT-928 and LT-930, the C accumulator transmitters. The results of this check revealed that indicated level was also higher than actual level by approximately 6.7 and 7.3 percent, respectivel Enclosure 2
Transmitter calibrations were performed using Process Instrument Calibration Procedure, PIC-012, Accumulator 'evel Transmitter The inspectors reviewed PIC-012 and completed records for the transmitter calibrations performed during the previous refueling outage. The practice of shifting transmitter output after initial calibrations originated from the desire to eliminate any potential level indication differences between the two transmitters on the same accumulator. This was accomplished by selecting one of the transmitters as the "Master" and the other as the "Slave."
The output voltage of the slave transmitter was then shifted until it agreed with the output voltage of the Master transmitter within 0.020 Volts DC. The inspectors noted that the procedure provided no guidance or limitations on allowable voltage.shifts. During review of PIC-012, the inspectors also noted that the method used to valve the transmitters in and out of service was not in accordance with typical industry practices or vendor recommendations for capacitance sensor transmitter Specifically, the transmitter was not equalized prior to opening/closing the high/low side valves. Equalizing the pressure is important to preventing the possibility of overpressure conditions which can cause a shift in transmitter zero calibration. The licensee performed transmitter overpressure testing to determine if this could have resulted in a calibration shift. Results of this testing indicated that this valving process did not result in voltage output shifts. The licensee recognized, however, that this was not a good practice which prompted a revision of PIC-012 to correct this situatio Transmitter calibration records reviewed showed that on June 14, LT-928 had been shifted up 428 millivolts (10.7 percent level) to match the output indication of LT-930. Similarly, on June 17, LT-926 had been shifted up 335 millivolts (8.4 percent level) to match the output indication of LT-924. The licensee postulated that gas bubbles were present in the wet leg sensing lines of LT-924 and LT-930 when they were initially calibrated which resulted in the large output voltage differences identified between their sister transmitters. The existence of trapped gases was not recognized by the technicians at the time of the calibrations. A gas bubble in a vertical section of the wet sensing line would result in the transmitter indicating higher than actua Therefore, when LT-926 and LT-928 were shifted to match the respective output indications of LT-924 and LT-930, this resulted in all of the transmitters indicating a higher than actual level.
The inspectors reviewed CR 95-02762, and discussed details with licensee personne The licensee's root cause investigation was comprehensive and included necessary planned corrective actions to address the problems identified. Among other weaknesses Enclosure 2
identified by the licensee that contributed to the calibration errors included the following:
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Inadequate I&C Personnel Decision Making: During the June 14, calibration of LT-926, the I&C technicians consulted with their supervisor about the large output voltage differences observed. The supervisor involved was not familiar with the particular calibration and relied upon the guidance of the technicians. A decision was subsequently made to perform the calibration shifts without adequately investigating or understanding the proble Transmitter Sensing Line Configuration Problems:
While the transmitter sensing lines are vented as part of the calibration process, the configuration of the wet sensing line makes it difficult to remove all gases that may be trapped. For example, the wet sensing line tubing enters the transmitters from the top and the transmitter vents are located on the bottom. Therefore, gasses can get trapped in the transmitter inner chamber during the venting proces Gases can also accumulate where the 3/8-inch sensing line (tubing) connects to the 2-inch piping from the accumulator tank. In addition, a previous condition report (ACR 91-100)
dating back to 1991 pointed out similar problems with measuring and maintaining accurate accumulator level indication. The recommendations to modify the transmitter sensing line configurations were eventually canceled by plant managemen The inspectors noted that besides the accumulator transmitter sensing line configuration problems, similar gas entrapment problems have been experienced in other instrumentation. For example, NRC Violation 50-261/94-17-02 identified a case where improperly sloped sensing lines for RHR flow transmitter FI-605 resulted in conditions conducive to the trapping of gase Corrective actions for this incident addressed the proper sloping of sensing lines associated with flow transmitters; level transmitters were not included. Recently, gas entrapment problems have again been identified with FI-605. The inspectors concluded that the licensee had not effectively resolved transmitter sensing line configuration problems that were conducive to gas entrapmen The safety consequences of the accumulator level discrepancies was determined to be minimal since level in none of the accumulators reached a point lower than the minimum level necessary for core protection during postulated design basis events. However, initially the licensee believed that the C Accumulator level had been slightly below the TS limit due to the calibration shift. As such, this issue was reported in LER 95-009-00, dated December 25, 1995. On January 3, 1996, the licensee alerted the inspectors Enclosure 2
that an error had been identified in the accumulator channel scaling calculation. This error involved the failure to compensate for the weight of pressurized nitrogen on the low pressure side of the transmitters. As a result of this error, the transmitters would indicate lower than actua Therefore, instead of exceeding the TS low water volume limit, most likely, the TS high water volume limit was exceeded. The inspectors will followup on this new information during the next inspection report perio TS 6.5.1.1, Procedures, Tests, and Experiments, requires in part, that written procedures be established, implemented, and maintained, covering the activities recommended in Appendix A of Regulatory Guide 1.33, Rev. 2, 1978, including procedures for calibrating safety-related instrumentatio Contrary to the above, PIC-012 was inadequate in that, it did not provide adequate instructions for ensuring that the accumulator level transmitters were properly calibrated. This issue is considered a violation of the requirements of TS 6.5.1.1 and is identified as Violation 50-261/95-30-01:
Inadequate Accumulator Level Calibration Procedur.4 Inadequate Oil Lubrication Sample of Spent Fuel Pool Cooling Pump During a routine tour of the auxiliary building, the inspectors noted that the sightglass for the outboard bearing "constant level oiler" of the B SFP cooling pump was empty. At the time, this pump was being used as the backup cooling pump. In the backup mode, the electrical breaker to the pump was administratively controlled open as a precaution to prevent operation of both pumps at the same time. The A SFP cooling pump was being operated as needed to cool the spent fuel poo The licensee was notified of this problem and the sightglass was subsequently filled. The inspectors learned that a maintenance technician had collected an oil sample from this pump several hours earlier on the same day of this observation. The oil sample was taken as part of routine preventative maintenance using predictive maintenance procedure PDM-001, Equipment Lube Oil Sampling. The inspectors reviewed the procedure and discussed it with the maintenance technician who obtained the sample. The sample was taken by removing the sightglass bulb and accessing the oil using a syphon bulb and tubing. A step in the procedure required that oil be restored to its proper level following sampling. The technician indicated that after replacing the sightglass bulb which was filled with oil, level did not change, therefore, he decided that it was not necessary to add oil to the bearing reservoir. Apparently, after the technician left, oil in the sightglass dropped as it slowly filled the bearing reservoir. This process may have been slowed by the cold environmental temperatures that existed at the tim Enclosure 2
The inspectors determined that the technician did not have a good understanding of the bearing reservoir volume or fundamental principles involved in the operation of the oile The inspectors questioned the licensee's controls for proper oiler installation and maintenance as it relates to the correct elevation setting of sightglasses on constant level oiler Correct oiler installation and elevation setting is critical to maintaining adequate lubrication to the bearings. While licensee procedures addressed the desired oil level in the oiler sightglasses, specific guidance did not exist to address the elevation of the oilers. As a result of these questions, the licensee conducted a field inspection of the oilers on safety related pumps. While there were no operability problems identified, several minor problems were found. These minor problems included a missing oiler level control mechanism in the A SFP cooling pump. On numerous other oilers, the locking mechanism which secures the sightglass to its base, was not tightene Maintenance work orders were initiated to correct these discrepancies. The licensee indicated that lubrication procedures would be revised and training provided to address the proper control of oil level settings. The inspectors concluded that these actions would be adequate to address this issu.5 Containment Related Preventative Maintenance and Surveillance Activities On December 2:, the inspectors witnessed various aspects of a containment entry by licensee personnel to conduct preventative maintenance and surveillance activities. Major activities performed by the licensee included the following:
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OST-902, Containment Fan Coolers Component Test: The purpose of this test was to assess the operational readiness of the four containment fan coolers and associated valves and dampers in accordance with the requirements of TS 4.5.1.6. Operational readiness was verified through visual checks of fan cooler damper positions, acceptable valve stroke times for service water cooling flow, and, verification of proper service water cooling flows. This test was completed satisfactorily without any major discrepancies noted in the equipment performance. During the conduct of this testing, the inspectors noted that grease was extruding from the inboard bearing of the No. 4 Containment Fan Cooler and the bearing oil level was slightly low. This was brought to the attention of the operators performing OST-902. A WR/JO was initiated to investigate/repair the oil leak and to fill the oil bearing reservoi Enclosure 2
investigate/repair the oil leak and to fill the oil bearing reservoi WR/JO 95-AJMH1, Replace Flux Map Detector C:
This work request was for replacing an incore flux map detector that had failed during previous core flux mapping activitie The detector was removed and replaced using corrective maintenance procedure CM-308, Flux Mapping System Moveable Detectors. The removal was accomplished by cutting the detector cable close to the detector and placing the cut portion in a lead storage pig. The inspectors noted that special radiological considerations and controls were implemented for this potentially highly contaminated activit Plant Program Procedure PLP-006, CV Inspection or Closeout:
This monthly procedure was performed by operations personnel to control personnel entry into and out of containmen Especially noteworthy were the detailed containment housekeeping and material conditions checks conducted prior to exiting containment. While conducting an independent assessment of containment conditions, the inspectors noted that a screened door to a tool storage area located on the upper containment operating deck was damaged. The bottom corner of the door was bent outward. The inspectors noted that loose items (e.g., nylon ropes and equipment slings, plastic face shields) were stored inside the area. The inspectors were concerned that these items could be washed through the damaged section of the door during design basis accidents involving operation of the containment spray system or from piping ruptures. If this occurred, this type of material could migrate to.the containment recirculation sump screens resulting in adverse impact on ECCS recirculation flow. The licensee initiated a work order to repair this doo The inspectors attended the operations and ALARA pre-briefings held prior to the containment entr Important aspects of the various activities planned were discussed in detail, including special equipment needed, personnel responsibilities, and contingencies for exiting containment should adverse conditions occur. Overall, the inspectors concluded that these activities were well-controlled and adequately performe.6 Close Out Issues (Closed) VIO 50-261/94-17-05:
Failure to Include Wide Range Penetration Pressurization Flowmeters in Calibration Program Enclosure 2
- On June 23, 1994, the penetration pressurization system wide range flowmeters were not included in the licensee's calibration program. At the time of this observation the C train penetration pressurization system flow rate was being monitored by the wide range instrumen The licensee responded to this violation via letter dated September 14, 1994. The following corrective actions were taken by the licensee for the above discrepancy: (1) a team was formed to determine what other plant instruments were not in the calibration program that should be, (2) procedure MOD-010 was revised to reference a review of the applicable portions of the quality assurance manual, (3) training was given to design engineers, (4)
procedures MMM-006, Calibration Program, and APP-022 were revised to enhance their requirements, and (5) quality control personnel were counseled. The inspectors verified that these corrective actions had been implemented. This item is close (Closed) VIO 50-261/94-23-02:
Pressurizer Cooldown In Excess of Technical Specification Limits This violation identified that on February 26, 1994, the pressurizer cooldown rate exceeded 200'F per hour when operators were collapsing the pressurizer bubble. The licensee issued ACR 94-01223 to evaluate this condition and document corrective action LER 94-019 was issued based on the determination that the condition was reportable. Licensee investigations revealed that a number of other cooldown or heatup excursions occurred between 1980 and 1994. Corrective actions included:
(1) A detailed, quantitative analysis was performed by Westinghouse that confirmed and documented that exceeding the pressurizer cooldown rate had not adversely affected the structural integrity of the pressurizer and that continued operation was acceptable. The analysis enveloped all of the heatup and cooldown excursions since 198 (2) Licensee procedure GP-007, Revision 38, Plant Cooldown From Hot Shutdown to Cold Shutdown, was revised. Operating crews were informed of this procedure change as part of the most recent licensed operator re-qualification training cycl (3) Selected Operating Experience information from 1988 to the present was re-reviewed and evaluated for applicability to Robinso (4) Plant operating crews were counseled on the need to question past understandings and practices regarding TS complianc Enclosure 2
The inspectors determined that the licensee's corrective actions were sufficient to prevent recurrence and had been adequately completed. This item is close.0 ENGINEERING (37551 and 92903) Engineering Support Activities Throughout the inspection period, engineering evaluations of problems and incidents were reviewed and discussions were held with engineering personnel to assess the effectiveness of the licensee's controls for identifying, resolving, and preventing problem Based on these inspections, the engineering staff was effective and timely in responding to plant problems and interfacing with operation.2 Close Out Issues (Closed) IFI 50-261/93-21-05:
Fuel Assembly Loose Part On October 11, 1993, during preparation for core load, the licensee discovered that loose parts (retaining nut and washer)
from a broken fuel inspection tool had dropped into a control rod guide tube of an assembly during fuel inspections by the vendo The licensee, along with the fuel vendor, evaluated the impact of the loose parts and determined that the parts were confined to the guide tube and presented no threat to fuel integrity. Operation with the assembly in the core was determined to be acceptable with these parts left inside the guide tub Details pertaining to the loose part were previously reviewed and documented in NRC Inspection Report 50-261/93-34, dated January 5, 1994. As part of that review, the root cause of the loose part was evaluated, the licensee and vendor'. foreign material exclusion controls were examined, and, the impact of the loose part was evaluated. The vendor's delay in repcrting the missing tool parts to the licensee was determined not to be deliberate, but, was considered a significant error in judgement by the vendor. The root cause of the broken fuel inspection tool was attributed to fuel vendor design control problems and inadequate licensee oversight. The vendor's original root cause analysis of the broken tool was found to be less than adequate because it did not determine the mechanical failure mechanism. The NRC agreed that the loose parts posed no threat to the core based on its location inside the guide tube. The inspectors were informed during review of this IFI that the assembly containing the loose parts was removed from the core during the previous refueling outage (June 1995).
The licensee has no plans to use this assembly in subsequent operating cycles. This item is close Enclosure 2
17 PLANT SUPPORT (71707, 71750 and 92904) Plant Support Activities The inspectors conducted plant tours, work activity observations, personnel interviews, and documentation reviews, to determine if plant physical security, radiological protection, and fire protection programs, were properly implemente.1.1 Physical Security Program The inspectors toured the protected area and observed the protected area fence, including the barbed wire, to ensure that the fence was intact and not in need of repai Isolation zones were maintained and clear of objects which could shield or conceal personne Personnel and packages entering the protected area were searched by detection devices or by hand for firearms, explosive devices, and other contraband. Vehicles were searched, escorted, and secured as required. No deficiencies were identified in this are.1.2 Radiological Protection Program The inspectors observed radiological control activities to ensure that they were conducted in accordance with regulatory and licensee requirements. Observations included personnel entry and exit from the Radiation Control Area, proper donning of radiological monitoring instrumentation and protective clothing when entering the RCA and contaminated areas, and, proper radiological area postings and controls. No deficiencies were identified in this are The inspectors considered noteworthy the ALARA pre-brief held for personnel entering containment on December 20, 1995, to conduct surveillance and maintenance activities discussed in paragraph 3.5. Among the information discussed at this pre-brief included: radiation work permits to be used and associated dose rate limits, general area dose rates, containment temperatures and personnel stay times, and, potential airborne radiological considerations. The inspectors observed that radiation control personnel supplied good support to maintenance personnel performing work activities inside containmen.1.3 Fire Protection Program The inspectors periodically reviewed aspects of the licensee's fire protection program including fire brigade staffing controls, flammable materials storage, Enclosure 2
- housekeeping, control of hazardous chemicals, and maintenance of fire protection equipment. No discrepancies were identifie.2 Close Out Issues (Closed) VIO 50-261/94-23-03:
Failure to Follow Physical Security Plan Contrary to paragraphs 4.5 and 3.2.1.6 of the licensee's Physical Security Plan, on September 15, 1994, an assigned escort left two visitors unattended in the turbine building while he used an adjacent restroom. In addition, one of the two visitors failed to display his security badge on the upper front torso while in the protected area (the badge was in the visitor's pocket).
The licensee responded to this violation via letter dated October 31, 1994. During this inspection the inspector verified that the following corrective actions had been taken by the licensee for the above discrepancy: (1) the employee involved had been disciplined, (2) the incident was reviewed with other licensee and contract painters and pipe coverers, to reinforce escort requirements and responsibilities, (3) CP&L's Manager of Mechanical Maintenance reviewed this event with mechanical craftsmen on September 19, 1994, and (4) the Maintenance Unit Manager issued a memorandum to all plant maintenance personnel describing this incident and restating escort responsibilitie The inspectors determined that the licensee's corrective actions were sufficient to prevent recurrence and had been adequately completed. This item is close.0 OTHER NRC PERSONNEL ON SITE On December 4-8, 1995, Mr. J. Coley, a Region II Inspector in the Division or Reactor Safety, was on-site to followup on NRC open items in the maintenance and surveillance areas. Results of this inspection are contained within this repor On December 11-15, 1995, Mr. B. Crowley, a Region II Inspector in the Division or Reactor Safety, was on-site to perform routine inspections in the maintenance and surveillance areas. Results of this inspection are contained within this repor.0 EXIT The inspection scope and findings were summarized on January 3, 1996, with those persons indicated by an asterisk in paragraph 1. The inspectors described the areas inspected and discussed in detail the inspection results. A listing of inspection findings is provide Dissenting comments were not received from the license Enclosure 2
Type/Item Number Status Description and Reference Paragraph VIO 93-19-01 Closed Operator Deviat-on from OST-005 Results in Turbine Runback (paragraph 2.5).
VIO 94-13-01 Closed Operator Left At-the-Controls Area, in Violation of 10 CFR 50.54 Requirements (paragraph 2.5).
VIO 94-15-03 Closed Failure to Take Adequate Corrective Action to an Out-of-Specification BAST Boron Concentration (paragraph 2.5).
VIO 94-16-01 Closed De-energized CV Water Level Instrument (paragraph 2.5).
VIO 95-30-01 Open Inadequate Accumulator Level Calibration Procedure (paragraph 3.3).
VIO 94-17-05 Closed Failure to Include Wide Range Penetration Pressurization Flowmeters in Calibration Program (paragraph 3.6).
VIO 94-23-02 Closed Pressurizer Cooldown In Excess of Technical Specification Limits (paragraph 3.6).
IFI 93-21-05 Closed Fuel Assembly Loose Part (paragraph 4.2).
VIO 94-23-03 Closed Failure to Follow Physical Security Plan (paragraph 5.2). ACRONYMS ACR
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Adverse Condition Report ALARA -
As Low As Reasonably Achievable BAST
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Boric Acid Storage Tank CFR
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Code of Federal Regulations CP
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Chemistry Procedure CP&L
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Carolina Power & Light Company CR
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Condition Report CV
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Containment Vessel ECCS
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Emergency Core Cooling System FP
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Fire Protection GP
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General Procedure gpm
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gallons per minute IA
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Instrument Air I&C
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Instrumentation and Control IFI
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Inspector Followup Item LCO
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Limiting Condition for Operation
- iEnclosure2
LER
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Licensee Event Report MCC
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Motor Control Center MMM
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Maintenance Management Manual MST
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Maintenance Surveillance Test OMM
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Operation Management Manual OST
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Operations Surveillance Test RHR
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Spent Fuel Pool SG
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Steam Generator SGB
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Steam Generator Blowdown TS
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Technical Specification UFSAR -
Updated Final Safety Analysis Report VIO
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Violation WR/JO -
Work Request/Job Order Enclosure 2