IR 05000335/1999001
| ML17229B091 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 04/05/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17229B090 | List: |
| References | |
| 50-335-99-01, 50-335-99-1, 50-389-99-01, 50-389-99-1, NUDOCS 9904150284 | |
| Download: ML17229B091 (48) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-335, 50-389 License Nos:
50-335/99-01; 50-389/99-01 Licensee:
Florida Power 8 Light Co.
Facility:
St. Lucie Nuclear Plant, Units 1 8 2 Location:
6351 South Ocean Drive Jensen Beach, FL 34957 Dates:
January 24 - March 6, 1999 Inspectors:
T. Ross, Senior Resident Inspector D. Lanyi, Resident Inspector G. Warnick, Resident Inspector B. Crowley, Regional Inspector (Sections M1.6, M8.2)
George Kuzo, Regional Radiation Specialist (Sections R1.4, R5.1, R7.1, R8.2)
Approved by:
L. Wert, Chief Reactor Projects Branch 3 Division of Reactor Projects 9904150284 990405 PDR ADQCK 05000335
PDR Enclosure
s rh EXECUTIVE SUMMARY St. Lucie Nuclear Plant, Units 1 8 2
'RC Inspection Report 50-335/99-01, 50-389/99-01 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a 6-week period of resident inspection; in addition, it includes the results of inspections by a regional reactor maintenance inspector and a Radiation Specialist.
Operations Shield building ventilation system operability and configuration were appropriate to
~ support plant operations.
The system component engineer was knowledgeable of system operation and status.
Material condition and housekeeping of the system were acceptable (Section 02.3).
Improper communications between Operations, Engineering, and Chemistry and a lack of attention to detail resulted in incomplete corrective actions associated with a containment isolation valve. Although a CR was initiated to address the condition adverse to quality, corrective actions were not fully implemented.
A non-cited violation was identified (Section 02.4).
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The licensee established several actions to improve the corrective action process.
Previous problems with the Plant Manager's Action Item program have been corrected.
Detailed reviews by the licensee continue to identify minor problems with proposed corrective actions.
The licensee initiated corrective actions to address the identified issues (Section 08.1).
Maintenance r
Contingency preparations for mitigating a potential failure of the emergency cooling canal discharge valves during routine surveillance testing were not fully implemented.
Transfer of responsibility for installation of ultimate heat sink stop logs from Maintenance Services to the Mechanical Maintenance department had not been well executed (Section M1.2).
Several human performance errors and procedural deficiencies were identified following a routine emergency diesel generator (EDG) surveillance test.
During the test, the 1A EDG was unintentionally overloaded when a control room indication failed to operate properly. Operator decision making was not conservative.
Operators and Engineering personnel lacked knowledge of EDG load ratings.
Engineering and Operations conducted a thorough investigation of the event.
Detailed inspections were completed to verify EDG operability. The human performance and procedural deficiencies were effectively corrected as evidenced during subsequent EDG tests (Section M1.3).
Troubleshooting efforts for a failed containment isolation valve were successful once Instrumentation and Control supervision became involved, helping the crew focus on problem identification. Clearances were observed to provide the necessary safety boundary for completion of the work. Replacement and post maintenance testing of the
valve were successfully completed by skillful and knowledgeable maintenance personnel (Section M1.4).
In general, scaffolds observed by the inspector were well constructed and properly restrained to prevent damage to safety-related electrical equipment from planned work or a seismic event.
However, the inspector did identify a non-cited violation involving several instances of improperly constructed scaffolds over safety-related electrical equipment.
Procedural requirements were not met (Section M1.5).
Observed maintenance and surveillance activities were performed in a quality manner and documentation was appropriate.
Procedures were in place and were being conscientiously followed by knowledgeable and qualified maintenance personnel.
Interface between maintenance and operations personnel was good (Sections M1.1 and M1.6).
. The quarterly system health review meeting between management, engineering, and maintenance relative to equipment status and the status of corrective actions for equipment problems was effective (Section M1.6).
~En ineerin
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Engineering support and written evaluations to address questions involving the accuracy of Unit 1 feedwater flow indications were comprehensive and technically sound.
Management decisions throughout the investigation were conservative.
Facility Review Group involvement was evident (Section E1.1).
The licensee continued to consolidate low-level radioactive waste storage areas and reduce quantities of solid radioactive waste stored onsite. A poor radiological practice resulting in decreased effectiveness of labels, contamination controls, and As Low As Reasonably Achievable program implementation was identified associated with the Unit 1 drumming facility locked-high radiation area.
Excluding the Unit 1 drumming facility, selected radiological control area locations were uncluttered.
Area postings, container labels, and radiological controls were maintained in accordance with regulatory requirements (Section R1.1).
Radiation Monitor System (RMS) detector and electronic calibrations were conducted at required frequencies and met established acceptance criteria. The Unit 2 emergency core cooling system particulate sample line installation contained 90 degree bends immediately preceding the sample filter housing.
This configuration is not recommended and could adversely affect sample accuracy.
In general, RMS equipment and sample lines were installed in accordance with the Updated Final Safety Analysis Report, configuration control diagrams, and acceptable industry practices (Section R1.2).
Chemistry technicians and operators demonstrated appropriate knowledge of procedures and proficiency in completing a containment mini-purge release (Section R1.3).
Processing, packaging, and shipment of radioactive waste for disposal met regulatory requirements (Section R1.4).
Hazardous materials training and testing for personnel processing, handling and shipping radioactive material and wastes was conducted in accordance with 49 CFR 172.704 requirements (Section R5.1).
The licensee identified that a Health Physics technician exceeded Technical Specification overtime limits by working 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period. A non-cited violation was issued (Section R6.1)
Counting room gamma-spectroscopy Quality Control activities and inter-laboratory analyses were implemented appropriately and no negative trends were identified. The addition of standard deviation to the observed value of a quality control spiked sample in order to meet acceptance criteria was identified as a poor practice (Section R7.1).
Re ort Details Summa of Plant Status Unit 1 operated at full power during the entire period, except for three small unplanned downpowers.
On February 12, 1999, power was reduced to 98 percent after a question was identified involving the accuracy of reactor power indications.
Power was returned to 100% on March 2, 1999, after a detailed investigation (see Section E1.1).
Failure of the 43 turbine throttle valve shaft and an erratic feedwater regulation valve positioner resulted in two other small downpowers.
Unit 2 operated at full power during the entire period, except for a downpower to approximately 95 percent that commenced on January 30, 1999, and lasted for one week to repair a main condenser tube leak.
I. 0 erations
Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of plant operations including observations of the Main Control Room (MCR). In general, pre-job briefings and plant evolutions were observed to be conducted in a professional and safety-conscious manner.
Early in the report period, phone traffic that was not related to MCR activities was observed to be a distraction to operators.
MCR activities were often interrupted by these calls. A new phone policy was implemented on February 8, 1999, to reduce this unnecessary burden through the use of an automated system to screen out nonessential phone calls. Following the February 8 transition, the inspectors observed that the MCR operators continued to receive some unnecessary phone calls. Operators questioned by the inspectors stated that although nonessential phone calls have been reduced, they have not yet been fullyeliminated.
During a troubleshooting activity by Operations personnel, an Instrumentation and Control (I8 C) technician was observed making an entry in the operator's logs without their knowledge.
The log entry involved a Technical Specification (TS) controlled item and was accurate.
The inspector questioned the Operations Supervisor to determine if this practice was consistent with management expectations.
The Operations Supervisor acknowledged that this was not an acceptable practice, and corrective actions were implemented to prevent this from reoccurring.
Operational Status of Facilities and Equipment 02.1 General Tours of Safet -Related Areas (71707)
General tours of safety-related areas were performed by the inspectors to examine the physical condition of plant equipment and to verify that safety systems were properly maintained and aligned.
These general walkdowns included the accessible portions of
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safety-related structures, systems, and components (SSC).
Overall material conditions for Unit 1 and Unit 2 SSCs were good. Minor equipment and housekeeping problems identified by the inspectors were reported to the licensee for resolution.
Corrective actions were implemented to address these items.
02.2 En ineered Safet Feature S stem Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to conduct a general walkdown of accessible portions of the Unit 1 and 2 Instrument Airand the Unit 1 Diesel Fuel Oil Transfer Systems.
Equipment operability, material condition, and housekeeping were acceptable in all cases.
Applicable valves and breakers were appropriately aligned.
The inspectors identified no substantive concerns during the walkdowns.
02.3 Unit 2 Shield Buildin Ventilation S stem SBVS Walkdown The inspector performed a detailed walkdown of the Unit 2 SBVS.
Observations and Findin s The inspector performed a detailed walkdown of accessible portions of the SBVS with the responsible system component engineer (SCE). The SCE was interviewed during this walkdown and considered to be knowledgeable of equipment operation and status consistent with the guidelines of Administrative Procedure (ADM) 17.12, Duties and Responsibilities of SCEs.
Valves and dampers in the main flowpath and electrical breakers associated with SBVS components were verified to be in the correct position per system drawings and normal operating procedures.
Technical Specifications (TS) and the Updated Final Safety Analysis Report (UFSAR) were reviewed for accuracy and consistency and found to be adequate.
Recent surveillance and maintenance records were also reviewed by the inspector for completeness and TS compliance.
Equipment operability, material condition, and housekeeping were observed to be acceptable.
Conclusions SBVS operability and configuration were appropriate to support plant operations.
The SCE was knowledgeable of system operation and status.
Material condition and housekeeping of the SBVS were acceptable.
02.4 Periodic Verification of Containment Isolation Lineu Unit 2 containment isolation status was inspected during a walkdown of accessible containment isolation valves (CIVs), pipe penetrations, and applicable power supplies.
Additionally, plant procedures and the Updated Final Safety Analysis Report (UFSAR)
were reviewed and compared against control room indications to verify that the CIVs were properly aligned.
Observations and Findin s The material condition of CIVs and pipe penetrations was acceptable, associated pipe hangers were in place, and proper labeling and locking of valves was evident.
Power supplies were properly aligned and in good condition.
Condition Report (CR)-99-0022 addressed apparent discrepancies associated with the alignment of several CIVs. During a review of the disposition of CR-99-0022, the inspector identified two problems.
One of these problems involved V5202, Pressurizer Steam Space Sample Isolation Valve. During the CIV inspection, this valve was found open which disagreed with the corrective actions for CR-98-1212.
This CR had attempted to resolve an environmental qualification concern associated with the qualified life of V5202. Following the November 1998 Unit 2 refueling outage, V5202 was supposed to remain de-energized shut.
The CR's corrective actions revised OP 2-0120024, Pressurizer Steam Space Venting, directing operators to maintain V5202 shut.
But the CR inadvertently failed to update some procedural controls.
Furthermore, despite the procedural guidance given in OP 2-0120024, the CR disposition was not effectively communicated to Operations.
Inadequate corrective action implementation resulted in Operations continuing to maintain V5202 open based on past operational experience.
Another problem identified by the inspector during the review of CR 99-0022 involved the disposition of V6741, Nitrogen Supply Valve. The inspector found several basic errors in" the description and technical disposition of the alignment of V6741. These errors were caused by a lack of attention to detail. The errors went undetected through the Engineering and Operations review for final resolution, and through the procedure change review for document revisions.
Although the valve was correctly positioned, documentation did not support resolution of the issue.
These problems were discussed with the licensee and subsequently the CR was revised for proper corrective action development.
The pressurizer steam space sample isolation valve issue constituted a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions which requires that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.
In this instance a condition adverse to quality was not promptly corrected.
The CIV safety functions were satisfied since the valve receives an automatic containment isolation signal. The valve was positioned correctly by the licensee.
This Severity Level IVviolation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy, and is identified as NCV 50-389/99-01-01, Inadequate Corrective Actions. This violation is in the licensee's corrective action program as CR-99-033 c.
Conclusions Improper communications between Operations, Engineering, and Chemistry and a lack of attention to detail resulted in incomplete corrective actions associated with a containment isolation valve. Although a CR was initiated to address the condition adverse to quality, corrective actions were not fully implemented.
A non-cited violation was identified.
Operations Procedures and Documentation 03.1 Emer enc 0 eratin Procedure Review (42001 and 71707)
The inspector performed a review of two Emergency Operating Procedures (EOPs), 1-EOP-3, Loss of Coolant Accident and 1-EOP-6, Total Loss of Feedwater.
For both procedures, the inspector verified that entry and exit conditions were clear. Transitions between and within the normal operating procedures, abnormal operating procedures, and EOPs were appropriate and well defined.
The inspector confirmed that EOP actions which required operators to perform activities outside the control room, were capable of being performed.
Additionally, all required equipment was available.
Discussions with four control room operators confirmed they had a detailed knowledge of the requirements and processes of these EOPs.
Additionally, the inspector discussed the EOPs with three non-licensed operators (NLOs). Although their knowledge of the procedures and bases was not as complete as the licensed operators, all of the NLOs interviewed understood their duties sufficiently to complete the EOP actions.
They were also knowledgeable of the equipment used in the procedures.
During the inspection process, the inspector noted that all of the EOPs were undergoing a revision to correspond with the latest revision of the Combustion Engineering Emergency Procedure Guidelines.
Based upon the procedural review and personnel interviews, the'inspector concluded that the current revision of the EOPs was understood by Operations personnel, and they were appropriate and easy to follow. Equipment required by the EOPs located outside of the control room was available and ready for use.
Miscellaneous Operations Issues 08.1 Closed VIO 50-335 389/98-06-03: Corrective Action Program Lacks Focus on Correction of Problems.
a.
Ins ection Sco e(92901 and 40500)
The inspectors reviewed the corrective actions for the violation. Additionally, a sample of recently closed Condition Reports (CRs) was reviewed for adequacy of corrective action Observations and Findin s Violation 50-335,389/98-06-03 was cited with three examples.
The first example of insufficient corrective actions identified 29 procedure revisions that were required to correct deficiencies, but had yet to be issued.
The licensee identified this as a weakness in their Plant Manager's Action Item (PMAI) program.
At that time, the program failed to assign due dates to required procedure revisions.
The licensee revised the PMAI procedure to require due dates for all corrective action procedure changes commensurate with the plants'eeds.
The inspectors reviewed 12 procedure change related PMAls, both opened and closed, and did not identify any deficiencies.
In the second example, five significant conditions adverse to quality were identified that had insufficient corrective actions to prevent recurrence.
The licensee immediately instituted additional corrective actions to address the five concerns.
Additionally, the licensee enhanced Facility Review Group (FRG) responsibilities for ensuring significant condition reports have appropriate corrective actions.
The inspector observed the FRG conduct a review of about ten CRs. These reviews identified other occurrences of inadequate corrective actions to be resolved.
Additionally, the licensee utilized the Corrective Action Group (CAG). The CAG's responsibility included up-front and close-out reviews of all condition reports.
A re'presentative of the CAG reported to senior management each day on any significant CRs and the status of outstanding CRs and PMAls.
The inspector iridependently reviewed 30 randomly selected, recently closed CRs.
This review concluded the licensee was developing adequate corrective actions, particularly in cases where there was a significant condition adverse to quality. However, the licensee (through the CAG and FRG) continued to identify a few CRs with inadequate corrective actions.
These problems were mainly in the area of documentation and administration.
In these cases, the licensee issued a subsequent CR to document.and correct the deficiencies.
The third example of the violation was a failure to perform root cause evaluations as required by procedure AP-0006130, Condition Reports.
The licensee revised the procedure to clearly define the responsibilities of the Plant General Manager for assigning the level of root cause analysis.
The inspector reviewed more than 50 CRs, and did not find any further examples of an inadequate assignment of root cause analysis level.
Section 02.4 describes inspection findings involving inadequate corrective actions.
A lack of attention to detail and poor communications resulted in incomplete corrective actions.
Violation 98-06-03 involved different root causes. The corrective actions for this violation would not be expected to preclude the specific deficiencies addressed in Section 02.4. This violation is closed.
Conclusions
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The licensee established several actions to improve the corrective action process.
Previous problems with the Plant Managers'ction Item program have been correcte Detailed reviews by the licensee continue to identify minor problems with proposed corrective actions.
The licensee initiated corrective actions to address the identified issues.
08.2 Closed LER 50-335 389/98-08-00:
Inadequate Reactor Protection System Trip Bypass Technical Specification.
On October 8, 1998, FPL determined that the TS governing the trip bypass setpoints for the high rate of change of power {HRCP) reactor protection system (RPS) trip was in error. The error was caused by a poorly worded TS that did not explicitly exclude decay heat from the power level at which the RPS trip bypass was required to be removed.
An exigent TS amendment request was submitted to clarify the required power level for the RPS trip. The NRC approved the fS amendment pursuant to 10 CFR 50.91(a)(6) to support Unit 2 reactor startup following the recent refueling outage.
During reactor startups prior to the last Unit 2 refueling'outage, literal compliance with the TS for the RPS trip was not met. However, the RPS trip still would have performed its safety function since it was designed to be dependant on the reactor power generated only by the fission process and excluded the consideration of.decay heat.
Decay heat could be excluded since it is not a directly measurable parameter, does not reflect the reactivity condition of the reactor, and is not a variable normally associated with the rate of change of reactor power. This issue constitutes a violation of minor significance and is not subject to formal enforcement action.
II. Imalntenance M1 Conduct of Maintenance M1.1 Maintenance Work Order and Surveillance Observations a.
Ins ection Sco e (61726 and 62707)
The resident inspectors observed all or portions of the following maintenance and surveillance activities, including work orders (WOs), Operating Procedures (OP),
Chemistry Operating Procedures (COP), l8C Procedures (ICP), and post-maintenance testing (PMT):
WO 98025474 COP 1-COP-06.09 WO 98018903 ICP 1-1220052 OP 2-00110050 WO 99002822 WO 99001805 WO 98001516 Unit 1 Auxiliary Feedwater Flow Monthly Check Operability Test on the Unit 1 Post Accident Sampling System Replace Seal Flex on Motor Operator for Valve MV-08-19B Nuclear Instrumentation Monthly Surveillance Control Element Assembly {CEA) Periodic Exercise Unit 1 CEA ¹38 Troubleshooting and Repair Unit 2 CEA ¹84 Troubleshooting and Replacement Unit 1 Vital Train A Switchgear Room Block Wall (3-hour Fire Barrier) Repair
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c Additionally, the inspectors reviewed IBC Maintenance, Minor Maintenance, and Security Maintenance on various Security systems.
This included maintenance activities performed by security personnel on doors.
b.
Observations Findin s and Conclusions The inspectors found the work performed under these activities was skilled, conscientious, and consistent with the established work control processes.
The inspectors observed that maintenance supervision and Engineering were closely involved. Allwork observed was performed with the work package or procedure in active use and located in the immediate area.
Work practices exhibited by the craftsman and technicians were appropriate and met management expectations, with one exception (see below). The inspectors also observed that work activities were properly documented and problems encountered during the performance of the work activities were appropriately resolved.
The inspectors determined that maintenance activities performed by security personnel on doors were effectively controlled.
Procedural controls for minor maintenance and security maintenance were properly implemented.
The inspectors verified that Operations and Fire Protection personnel were appropriately informed of maintenance activities on doors.
During replacement of a printed circuit card for CEA ¹84, l8C technicians did not perform a side-by-side visual comparison of the new and old cards as a final check to ensure these cards were the same design and associated jumpers were properly configured.
Subsequent discussions with maintenance management confirmed this practice was contrary to their expectations.
Supervisors coached the l8C department on appropriate card replacement practices.
Specific discussions of additional maintenance and surveillance observations are presented in Sections M1.2 through M1.5 below.
M1.2 Pre arations For Installin Emer enc Coolin Canal Sto Lo s On January 20, 1999, the licensee conducted a quarterly stroke test of the barrier dam isolation valves for the ultimate heat sink (UHS) in accordance with OP 0360050, Revision 15, Emergency Cooling Water Canal - Periodic Test.
On January 26, an inspector completed an examination of the licensee's contingency actions taken to fulfill Step 4.6 of OP 0360050, which stated "Ensure that all equipment and personnel necessary to insert stop logs are onsite and available".
Ifthe UHS discharge valves fail during testing, TS 3.7.5.1 would require installing the stop logs within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
To.
provide the necessary instructions on implementing this test contingency, WO 98016560 had been preplanned for us b..
Observations and Findin s The Inspector reviewed WO instructions, interviewed responsible mechanical maintenance (MM)personnel, and walked down the UHS stop logs and associated equipment.
The following observations were made:
The stop logs were not inspected for use prior to the quarterly test.
The material condition of stop logs were degraded, some significantly (e.g.,
badly rusted pad eyes, spalding concrete, cracked and/or niissing seals), and at least one appeared to be unuseable.
Only the mobile crane was reserved for contingency use, the necessary fork lift was not.
Necessary rigging to remove and reinstall vehicle intrusion barriers and manipulate the stop logs was not staged.
Divers needed to assist with inserting stop logs were not contacted or placed on call.
Responsible MM personnel were not familiar with the process for inserting UHS stop logs.
The inspector discussed these findings with responsible MM and Maintenance Services supervisors.
Except for reserving the mobile crane, the inspector concluded that very little effort had gone into contingency preparations.
The supervisors agreed that the contingency actions taken in January were considerably less than what was done before, and inconsistent with their expectations.
They attributed the difference'primarily to a poor "hand-off'etween MM and Maintenance Services who was previously responsible for this activity.
After further discussions, the inspector concluded that equipment and personnel were sufficiently available to install the stop logs within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition to improving their contingency preparations for UHS discharge valve testing in the future, the supervisors indicated this experience would be factored into their lessons learned for other responsibilities undergoing change management.
c.
Conclusions Contingency preparations for mitigating the potential failure of the emergency cooling canal discharge valves during routine surveillance testing were not fully implemented.'ransfer of responsibility for the installation of UHS stop logs, from Maintenance Services to the Mechanical Maintenance department had not been well executed.
M1.3 1A Emer enc Diesel Generator EDG Overloaded Durin Testin a.
Ins ection Sco e (61726 and 71707)
An inspector observed performance of the 1A EDG monthly surveillance by Operations, data collection and troubleshooting by Engineering, and corrective actions to address an unintentional overloading of the 1A EDG. The inspector also observed subsequent surveillance runs of the 1A EDG and 28 ED /
b.
Observations and Findin s On February 4, 1999, the inspector attended briefings conducted by both Operations and Engineering for the 1A EDG surveillance run. Pre-job briefings were adequate in that they covered the precautions and limitations, and discussed past and potential problems.
An inspector accompanied the NLO during the surveillance test. The NLO assigned to perform the EDG test was knowledgeable of the procedures and system operation.
Initial preparations and pre-start checks for the EDG test were effectively performed by the NLO, with good coordination with the control room.
During the 1A EDG surveillance run, a discrepancy was discovered between the local
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and remote (MCR) kilowatt (KW) indications.
Control room operators became aware of the KWvariation 15 minutes into the EDG run through radio communications with the NLO. The NLO was initiallyinformed that remote indication was reading 3450 KW, which was within the required test band of 3300-3500 KW, and that the NLO should commence his first set of EDG log readings.
However, the NLO and,inspector observed that local EDG load indicated in excess of 4000 KWwhich was more than 500 KW above the specified surveillance range.
Remote indication in the MCR was reading 500-700 KW lower than local indication, and oscillating although actual load demand was not changing.
Engineering personnel were also present at the EDG conducting planned troubleshooting of local voltage fluctuations.
But they did not initiallycontribute any feedback to Operations regarding the apparently excessive EDG load. Operations staff and the engineers were unfamiliar with EDG design load ratings for the generator or diesel.
Neither immediately recognized that a potentially serious equipment problem was occurring. Once the indication problem was fully recognized, engineering personnel decided to collect data and perform a calculation to determine actual EDG load.
The inspector proceeded to the MCR from the EDG shortly after the discovery of the KW discrepancy to observe troubleshooting activities. After approximately 45 minutes of EDG operation at a load of approximately 4000 KW, control room operators and engineering personnel determined that the remote indication was in error and that the EDG was loaded greater than specified in the procedure.
With this information, the Assistant Nuclear Plant Supervisor (ANPS) instructed the Reactor Control Operator (RCO) to reduce load to a control room indicated load of 2000 KW. The EDG was maintained at 2000 KWfor some time to support troubleshooting and data collection efforts. Afterwards, the EDG was secured and declared out-of-service from the time that the first abnormal KW indication was discovered.
Condition Report 99-0149 was generated to address the MCR KW recorder indication problems and the potential EDG damage due to the possible overload conditions.
Further review determined that the electrical generator was not operated outside of design capability, but the diesel engine horsepower rating was exceeded.
The licensee performed a detailed inspection of the generator and engine.
The results were discussed with the vendor, who concluded that no damage had occurred.
Troubleshooting of the control room KW indication included a successful bench test of the recorder and replacement of the transducer which transmits the KWsignal to the control room chart recorder.
The original transducer was examined and showed signs of
dielectric leakage from several capacitors, however extensive testing failed to duplicate the problem of low KWoutput.
Following the replacement of the suspect transducer, PMT was successfully performed and the 1A EDG was returned to service.
In review of the response to the failed instrumentation, several human performance and procedural weaknesses were identified by the inspector and the licensee.
Human performance weaknesses included Operations personnel making a non-conservative decision by using the erratic remote indication in place of the higher reading local KW meter.
Engineering personnel involved were slow to communicate to the operators that the EDG may be overloaded, and personnel were not familiar with the EDG load ratings.
Procedural weaknesses included a lack of specific guidance regarding limitations on EDG amperage and KW loading.
Equipment and human performance issues associated with the EDG excessive loading event were entered in the licensee's corrective action program.
Operations and engineering supervision have held several briefings with Operations department crews regarding the lessons learned, emphasizing the importance of maintaining a questioning attitude, not waiting for the system experts to give guidance, and the importance of conservative decision making in all areas of operations.
Plant procedures have been revised to include precautions for KW limits and a table of expected amperage values for KW loading.
These corrective actions were observed to be successful during a PMT run of the 2B EDG on February 26, 1999.
During this run, operators and inspectors noted the KW and amperage readings did not precisely correspond to the table recently incorporated in the procedure.
EDG loading was stopped, and supervision was notified. An extra NLO was stationed locally at the EDG to continuously monitor amperage and KW indication.
Conservative decision making was apparent by the operators.
Another incident not directly observed by the inspectors occurred on March 4, 1999, during the 1A EDG monthly surveillance test. After the EDG reached test load requirements, the RCO noted a KWdrop on the control room recorder without a corresponding change in amperage or load. Operators stabilized the load using the recently implemented procedural guidance'to successfully complete the surveillance run.
Subsequently, a determination was made that the indication problem was caused by the recorder.
Further engineering review concluded that the KW indication problems from February and March were both caused by the chart recorder itself. Human performance and procedural weaknesses that led to EDG overloading in February were effectively corrected to aid the operators in making informed, conservative decisions to identify the source of the KW indication problem and safely operate the EDG within required limits.
Conclusions Several human performance errors and procedural deficiencies were identified following a routine surveillance test.
During the test, the 1A EDG was unintentionally overloaded when a control room indication failed to operate properly. Operator decision making was not conservative.
Operators and Engineering personnel lacked knowledge of EDG load ratings.
Engineering and Operations conducted a thorough investigation of the even Detailed inspections were completed to verify EDG operability. The human performance and procedural deficiencies were effectively corrected as evidenced during subsequent EDG tests.
Unit 2 Containment Isolation Valve CIV Failure The inspector observed troubleshooting efforts, replacement, and post maintenance testing of valve V5200, the CIVfor the reactor coolant loop 2A hot leg sample line.
Observations and Findin s On February 9, 1999, the inspector observed troubleshooting activities on V5200 to determine why the valve was failing to operate in the open direction. V5200 had failed to open following a surveillance conducted on the Post Accident Sampling System (PASS).
The failure of V5200 rendered PASS inoperable.
The clearance to support troubleshooting was reviewed and found to be adequate.
Initial troubleshooting by the operators and l8C technicians appeared unorganized.
There was a lack of direction and understanding as multiple attempts were made to determine the root cause of the valve failure. Later that day, troubleshooting recommenced with l8C supervision involved that was effective in collecting relevant data, and focusing on problem identification to determine the reason for the valve failure.
Efforts by the licensee to expedite the valve repair and minimize maintenance rule OOS time for PASS were observed by the inspector.
Conservative decision making by those involved was observed as plans were developed and materials were acquired for completion of the task.
The pre-job briefing conducted by Operations and Health Physics (HP) on February 12 adequately addressed all aspects of the work. Valve replacement was conducted in accordance with approved procedures, work orders, and applicable foreign material exclusion procedures.
The valve crew was skillful and efficient in replacing the valve with minimal problems, and minimizing the exposure received.
Post maintenance leakage rate testing was successfully completed by the test engineer due to his knowledge of the equipment and questioning attitude regarding proper system response.
Conclusions The licensee's troubleshooting efforts for a failed containment isolation valve were successful once l8C supervision became involved, helping the crew focus on problem identification. Clearances were observed to provide the necessary safety boundary for completion of the work. Replacement and post maintenance testing of the valve were successfully completed by knowledgeable maintenance personne '12 M1.5 Scaffoldin Installation a.
Ins ection Sco e(62707)
During the first week of March, an inspector walked down a number of scaffolds built, or being built, in the Unit 1 cable spreading room (CSR) and vital switchgear rooms.
The inspector also toured these scaffolds with the responsible Scaffolding Supervisor, and then again with knowledgeable civil engineers, to ensure compliance with administrative procedure ADM-27.11, Revision 0, Scaffold Control.
b.
Observations and Findin s Of the scaffolds observed, some were quite large and complex when considering physical obstructions and importance of surrounding electrical equipment.
In general, the scaffolds observed by the inspector appeared to be well constructed and properly restrained to prevent damage to safety-related electrical equipment from planned work or a seismic event.
However, as listed below, the inspector did identify several discrepancies between the way these scaffolds were constructed and the instructions of ADM 27.1:
Two of the scaffolds were tied-off at several points to unistrut supports attached to the wall.
One scaffold lacked adequate protection for preventing tools and/or material from dropping on a vital motor control center.
A scaffold was directly tied-off to the 1A3 Pressurizer Heater Transformer.
Three scaffolds were in physical contact with various safety-related cabinets and switchgear causing minor damage.
One horizontal scaffold pole projected inside an electrical junction box (cover had been removed allowing entry).
These discrepancies were contrary to the specific instructions provided by ADM-27.1 regarding allowable clearances between scaffolding and sensitive safety-related equipment, protection of equipment from possible unwanted actuation, and allowable methods for attaching horizontal restraints.
The inspector discussed these observations with the scaffolding supervisor and a civil engineer.
Allthe identified discrepancies were promptly corrected, and CR 99-328 was initiated. Further discussio'ns and walkdowns with the licensee's civil engineering staff satisfied the inspector that seismic qualification of affected safety-related electrical equipment had not been significaritly impacted.
St. Lucie Unit 1 TS require written procedures be established, implemented, and maintained as recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Section 9 of Appendix A of RG 1.33 requires that maintenance that can affect the performance of safety-related equipment shall be performed in accordance with written procedures.
Failure to construct scaffolds in the. Unit 1 CSR and vital switchgear rooms in accordance with ADM-27.1 constituted a violation of a maintenance procedure required by TS 6.8.1. This Severity Level IVviolation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy, and will
be identified as NCV 50-335/99-01-02, Scaffolding Construction Discrepancies.
The violation is in the licensee's corrective action program as CR 99-328.
c.
Conclusions In general, the scaffolds observed by the inspector were well constructed and properly restrained to prevent damage to safety-related electrical equipment from planned work or a seismic event.
However, the inspector did identify a Non-Cited Violation involving several instances of improperly constructed scaffolds over safety-related electrical equipment.
Procedural requirements were not met.
M1.6 Maintenance and Surveillance Observations a.
Ins ection Sco e (61726 and 62700)
A regional maintenance inspector observed all or portions of the following preventive maintenance (PM) and surveillance testing activities:
Work Order (WO) 99000981 01, PM on Blowdown Heat Exchanger 2A WO 99000126 01, Monthly Functional Test of Radiation Monitor for Plant Stack Exhaust (RCS-26-1)
WO 99000827 01, Bi-monthly PM on ERDADS WO 98025302 01, PM on EH Reservoir Desiccant WO 98025262 01, Replace Filters in Various 4160V and 6.9KV Motors In addition to observation of the above work activities, the inspector attended the 4~ quarter, 1998 system health status review meeting.
b.
Observations Findin s and Conclusions Allobserved PM activities and surveillance testing were performed in accordance with work instructions, procedures, and applicable clearance controls. Work performed during these activities was accomplished by knowledgeable and experienced personnel who were familiar with their specific tasks.
The work package or procedure was routinely present and in active use at, the work site. The inspectors observed that maintenance supervision was closely involved with the maintenance work. Good interface between maintenance and operations personnel was observed.
The inspectors also observed that work activities were properly documented and problems encountered during the performance of the work activities were appropriately resolved.
In the quarterly system health review meeting, engineering personnel presented to plant management the performance status, including recovery plan and corrective actions, for maintenance rule equipment in a white or yellow status.
Equipment performance was rated by Engineering using the following colors: green - excellent, white - acceptable, yellow - needs improvement, and red - unacceptable.
The inspectors noted good exchange between management, engineering, and maintenance relative to the performance status, recovery plans, and corrective action status for equipment problem Conclusions Observed PM and surveillance activities were performed in a quality manner and documentation was appropriate.
Procedures were in place and were being conscientiously followed by knowledgeable and qualified maintenance personnel.
Interface between maintenance and operations personnel was good.
The quarterly system health review meeting between management, Engineering, and Maintenance relative to equipment status and the'status of corrective actions for equipment problems was effective.
miscellaneous Nlaintenance Issues Closed Ins ectorFollowu Item IFI 50-335389/98-10-01:CriticalMaintenance Management (CMM) Scheduling Practices. (92902)
An inspecto'r interviewed the Work Control Manager and walked through the important elements of the licensee's recent revision of the entire CMM process.
The inspector also reviewed the newly issued procedure ADM-10.01, Revision 0, Critical Maintenance Management, that became effective January 19, 1999. This new ADMwas a major enhancement over the previous CMM program.
More structure and detail were added to the administrative controls for planning and executing critical online maintenance activities.
Budgeting equipment unavailability throughout the year, and ensuring activities that affect reliability are considered as critical path items, are now integral parts of the CMM process.
The licensee already has several critical maintenance activities working their way through the new CMM process (e.g., Unit 1 and 2 EDGs, AFW, and ECCS). An example of the effectiveness of the new process was management's decision to defer the 1A EDG CMM scheduled for early March. This decision was based on the system engineer's determination that the 1A EDG had already accumulated significant out-of-service hours for so early in the year. Additionally, the 1A EDG did not have any pressing reliability issues and the planned work did not include significant improvements to reliability. This IFI is considered closed.
Closed Ins ection Follow-u Item IFI 50-335 389/97-11-04, Follow-up to PM Program Changes.
This IFI was opened to track the licensee's updating of the PM program and to evaluate the reasons for the high number of PM Change Requests (PMCRs). At the time this issue was opened the licensee had a PM Basis Project in progress.
The objective of the PM Basis Project was to review and document the technical bases for a large number of equipment PMs for each unit to determine if PM frequencies could be reduced or canceled, if no longer needed or justified. During an inspection documented in NRC Inspection Report Nos. 50-335 and 50-389/98-09, the inspectors reviewed the PM change process, including a large number of routine PMCRs (PMCRs not part of the basis project) issued in 1998.
For the PMCRs reviewed, the inspectors found documentation problems.
Specifically, for a number of PMCRs, technical justification for extending due dates was not well documented, and in many cases, the required
engineering review was not documented.
In all cases, the changes could be technically justified. The licensee issued Condition Report (CR) 1329 for this documentation issue.
At the time of the current inspection, the PM Basis Project had been completed for the targeted PMs (all PMs performed last outage for both units and all daily PMs with a frequency less than 18 months).
Documentation of the basis for these PMs resulted in deleting some PMs and extending the frequency for a significant number of PMs.
No changes were made that would affect compliance with Technical Specification (TS),
Final Safety Analysis Report (FSAR), or other regulatory requirements.
The inspectors reviewed all of the routine PMCRs issued since the inspection documented in NRC Inspection Report 50-335 and 50-389/98-09 (approximately 200 PMCRs) and a sample of approximately 35 PMCRs resulting from the PM Basis Project.
In addition, the corrective actions for CR 98-1329 were reviewed. Although the review found that problems still existed with documentation of some PM changes, improvements had been made in the process, resulting in improvements in the quality of technical justifications for PM changes.
During the review, the inspectors noted that for PM changes for equipment that was not TS/FSAR, safety-related, or EQ, the PM procedure did not require engineering review. This could allow PM changes for maintenance rule non-safety-related equipment without engineering review to consider maintenance rule aspects of the change.
No problems relative to maintenance rule compliance were noted in review of the above PMCRs.
In many cases system engineers had reviewed the PMCRs, even though not required by procedure.
As part of the corrective actions for CR 98-1329, engineering management had been reviewing all PMCRs.
On January 21, 1999, prior to the current NRC inspection effort, CR 99-0073 was issued to document and take additional corrective actions for the documentation problems identified by the management reviews. The preliminary
'orrective action plans developed before the end of the inspection effort included modification of the PMCR process to ensure that engineering review is required for all maintenance rule equipment PM changes.
Based on the above review, the inspectors concluded that documentation problems still exist with the PM change process.
Although the changes could be technically justified, the licensee had not adequately documented the justifications. The problems were documented in CR 99-0073 and are being corrected.
The reasons for the large numbers of PMCRs were: (1) the large number of PMs reviewed as part of the PM Basis Project, and the fact that a PMCR was issued to document the basis whether or not the review resulted in a change to the PM, and (2) routine PMCRs were issued for any change in PM frequency, regardless of whether it was permanent change or just a temporary change (for example, if a non-outage PM was due during an outage and could not be performed or did not need to be performed during the outage, a PMCR was issued.)
This IFI is close III. En ineerin Conduct of Engineering Unit 1 MFW Flow Indication Anomalies Ins ection Sco e (37551)
The inspectors monitored licensee efforts to resolve apparent differences in Unit 1 main feedwater (MFW) flow indication as measured by the normally installed MFW flow venturis versus a temporarily installed acoustic flow measuring device.
Inspectors reviewed applicable engineering evaluations, interviewed responsible engineers, discussed implications on unit operation with management, and attended facility review group (FRG) meetings.
Observations and Findin s On February 12, 1999, management decided to reduce power on Unit 1 to 98% power due to information that the MFW flow input to the secondary calorimetric may be slightly inaccurate.
This information came from a recently installed, temporary acoustic flow measuring device that indicated MFW flowwas approximately 1.5% higher than the differential pressure instrument readings of the permanently installed MFW flow venturis.
Ifthe acoustic MFW flow readings were accurate, then the potential existed that thermal power was actually closer to 102% rather than the 100% calculated by calorimetric using venturi data.
Management's decision to decrease power was a conservative response to the anomalous data.
Subsequent investigations by the licensee with support from the vendor did not disprove the acoustic flow readings.
However, the licensee was able to refine the data and reduce the flow discrepancy to only 1.14% and thereby increase reactor power back to 98.5%.
On February 19, 1999, the licensee contracted with the nuclear steam supply system (NSSS) vendor to conduct another MFWflow measurement test using a chemical dye tracer methodology.
The chemical tracer test was considered a more precise'method than'either the flow venturis or acoustic devices.
Results from the chemical tracer tests confirmed the venturis were accurately representing Unit 1 MFW flow. On March 2, Unit 1 was returned to full power operation.
Engineering support and written evaluations to address the diverse flow measurements, reconcile the anomalous indications, and recommend specific corrective actions were comprehensive, thorough and technically sound.
The conclusions and recommendations made by engineering were reviewed and discussed at length by the FRG. Insightful questions and appropriate directions were provided at the FRG meetings to ensure the issue was fully resolved.
Conclusions Engineering support and written evaluations to address questions involving the accuracy of Unit 1 MFW flow indications were comprehensive and technically sound.
Management decisions throughout the investigation were conservative.
Facility Review Group involvement was eviden I
E7 Quality Assurance In Engineering Activities E7.1 0 erabilit andRe ortabilit Assessments ofConditionsAdverseto ualit (40500)
An inspector reviewed the initial operability assessment of the following "three-day" condition reports (CR), and discussed applicable details with the responsible engineers:
CR 99-0091, Intake Cooling Water Check Valves Not Tested To Verify Maximum Accident Condition Flow; and CR 99-0080, Fast Bus Transfer From AuxiliaryTo Startup Transformers During Emergency Diesel Generator Testing Could Cause Damage Each of these CRs identified potential operability issues that the on-shift NPS determined would require prompt attention.
The inspector verified that operability assessments were completed. within three working days as required by Administrative Procedure No.
0006130, Revision 15. The content and detail of both assessments were sufficient to adequately address the relevant operability concerns. They were prepared and verified.
by experienced engineers, and approved by engineering supervision.
In conclusion, the operability assessments of "three-day" CRs were handled in an expeditious and technically sound manner consistent with administrative requirements.
ES Miscellaneous Engineering Issues E8.1 Closed LER 50-335 389/98-007-00: Inadequate Procedure Could Cause Station Blackout Recovery Complications, (92903 and 42001)
While investigating an anomaly with a Unit 2 simulator station blackout recovery exercise, Engineering discovered that one of the non-preferred methods to restore electrical power could not be performed as described in the applicable emergency operating procedure (EOP). A review of the design documents confirmed that the circuitry for the emergency diesel generator (EDG) output breaker could cause a recovered EDG to unexpectedly parallel with the other unit's EDG that was supplying power yia the station blackout (SBO) cross-tie.
The licensee determined that this could complicate the recovery from a SBO condition in that an uncontrolled synchronization between the two EDGs could cause one or both of the generators to fail. However, the probability that operators would reach this contingency action was low since there were other preferred procedural options.
The operators would be able to recover the situation in a relatively short period ifthe problem occurred.
The inspectors concluded that the safety significance of this problem was low.
This problem was caused by inadequate SBO recovery procedures (1,2-EOP-10, Station Blackout and 1,2-EOP-99 Appendices/Figures/Tables)
that were not validated as part of the modification that installed the SBO cross-ties between the units. The inspector verified that the licensee completed changes to the appropriate SBO procedures and that they had also reviewed other SBO circuitry for additional discrepancies.
The inspector concluded that the licensee exhibited a good questioning attitude in ide'ntifying and correcting the procedure deficiencie The licensee identified and reported that procedures 1,2-EOP-10 and 1,2-EOP-99 were deficient. This is not in compliance with Technical Specification 6.8.1.a, which requires establishment, implementation, and maintenance of procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, which specifically includes loss of electrical power. This TS non-compliance constitutes a violation of minor significance and is not subjected to formal enforcement action.
IV. Plant Su ort Radiological Protection and Chemistry (RP & C) Controls Conduct of Radiolo ical Protection Controls Ins ection Sco e (84750 and 86750)
Radiological controls associated with eNuent releases, radioactive waste processing, and solid radioactive waste and material storage areas were reviewed.
General housekeeping, personnel radiological monitoring, area postings, container labels, and controls for high radiation areas (HRAs) and locked-high radiation areas (LHRAs) were evaluated.
The inspectors toured Radiological Control Areas (RCAs), observed work activities in progress, discussed procedural requirements with Health Physics Technicians (HPTs), and verified selected radiation survey results.
Procedural guidance and established radiological controls were compared against applicable sections of the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS) and 10 CFR Part 20 requirements.
Observations and Findin s The inspectors verified the on-going consolidation and reduction of on-site solid radioactive waste inventories.
Main storage areas included the Unit 1 (U1) drumming facility and shielded containers located in the U1 and Unit 2 (U2) cask wash areas.
As of January 29, 1999, approximately 4870 cubic feet (ft') of radioactive waste material was stored onsite.
The material included, 2570 ft'fresins, 140 ft'ffilters, 75 ft'f secondary side solids, and 1585 ft'fdry active waste (DAW).
Housekeeping practices within the Auxiliary Buildings, the effluent processing, and the solid radioactive waste processing and storage areas were considered acceptable.
Physical controls for HRAs and LHRAs met procedural, TS, and 10 CFR Part 20 requirements.
Excluding the U1 drumming facility, no concerns with housekeeping and cleanliness within the observed processing and storage areas were noted.
During the week of January 25, 1999, the inspectors observed and,,reviewed radiation controls for activities within the U1 drumming facility DAWsorting and LHRA waste storage areas.
The DAWsorting area was cluttered with extensive numbers of bags containing contaminated materials awaiting processing.
The inspectors verified the adequacy of established radiological controls for the DAWsorting activities including HPT coverage, protective clothing, personnel dosimetry use, and air sampling.
Doses
from external and internal radioactive exposure for workers sorting DAWin the U1
. drumming room were small fractions of regulatory limits. Within the U1 drumming facility LHRA, the inspectors noted several examples of bagged radioactive waste materials that were tom or ripped, numerous mop heads beneath bags to absorb leaking liquids, degraded containers, and several bags with difficultto read labels.
Cognizant licensee representatives stated that to minimize entry into the subject LHRA, bags containing DAW and wet filters occasionally were dropped over the wall into the secured area which resulted in the observed damage and the random orientation of the labels on the bags.
Although discussions with responsible licensee representatives indicated that personnel entries into the subject LHRAwere made with appropriate controls, the inspectors noted that the practice of occasionally dropping the bagged material into the area reduced the effectiveness of contamination controls, As Low As Reasonably Achievable (ALARA)program initiatives, and label visibilityto workers entering the area.
Licensee representatives stated that a condition report would be issued to track development and implementation of an action plan for the identified poor practices within the U1 Drumming Facility LHRA.
Conclusions The licensee continued to consolidate low-level radioactive waste storage areas and reduce quantities of solid radioactive waste stored onsite. A poor radiological practice resulting in decreased effectiveness of labels, contamination controls, and ALARA program implementation was identified associated with the U1 drumming facility LHRA.
Excluding the Unit 1 drumming, facility, selected RCA locations were uncluttered.
Area postings, container labels, and radiological controls were maintained in accordance with regulatory requirements.
R1.2 Radiation Monitor S stem RMS Installation and Calibrations Ins ection Sco e (84750)
The inspectors reviewed and evaluated installed process and effluent Radiation Monitoring System (RMS) detectors, electronics, sampling lines and flow meters to implement Offsite Dose Calculation Manual (ODCM) and 10 CFR Part 20 requirements.
The evaluation included, as applicable, Unit 2 RMS equipment walk-downs with comparisons against UFSAR commitments, configuration control documents, design specifications, and recommendations detailed in American National Standards Institute (ANSI) N13.1-1969, American National Standard Guide to Sampling Airborne Radioactive Materials in Nuclear Facilities.
Approved calibration guidance and results for the Plant Vent RMS and Containment High Range Monitors (CHRMs) were reviewed and discussed.
Both radiation source and electronic calibrations were reviewed and evaluated.
Calibration activities were evaluated against applicable UFSAR sections, and TS and ODCM requirements.
For the CHRMs, special calibrations to meet Three Mile Island (TMI)Action Item II.F.1 were reviewe Observations and Findin s Monitor calibrations were conducted at the required frequencies and no negative performance trends were identified.
In general, RMS equipment was installed in accordance with UFSAR descriptions, configuration control diagrams, and established industry recommendations.
However, a potential concern for the U2 Emergency Core Cooling System ECCS airborne particulate sampling line was identified. During system walk-downs on January 26, 1999, the inspectors observed that contrary to the recommended ANSI N13.1 guidance, the normal system line-up resulted in 90 degree bends in the line immediately preceding the particulate sample filter housing.
Although the licensee was not committed to ANSI N13.1, the subject RMS system was required by Regulatory Guide (RG) 1.97 which recommends eNuent sampling should be performed in a manner that ensures procurement of representative samples.
The inspectors noted that the observed line bends may result in deposition of particulates which could affect the sample representativeness and reduce the accuracy of the particulate filter measurement.
Further, the inspectors noted that use of an alternate sample line on the ECCS RMS skid could be used to eliminate the observed line bends.
Licensee representatives stated that this issue would be reviewed further. A condition report was issued to address the adequacy of the effluent particulate sample line 90 degree bend radii.
Conclusions Radiation Monitor System (RMS) detector and electronic calibrations were conducted at required frequencies and meet established acceptance criteria.
In general, RMS equipment and sample lines were installed in accordance with UFSAR, configuration control diagrams, and acceptable industry practices.
The U2 ECCS particulate sample line installation contained 90 degree bends immediately preceding the sample filter housing.
This configuration is not recommended and could adversely affect sample accuracy.
Radioactive ENuent Processin Anal sis and Release Licensee activities for a January 26, 1998 U2 containment mini-purge effluent release were evaluated through direct observation and evaluation of pre-release sampling, quantitative radionuclide analyses, system valve line-ups, and release processing conducted by chemistry technicians and operators.
Equipment operability, procedural adequacy, and staff proficiency were reviewed.
In addition, release permit data for a
'anuary 25, 1999 liquid release were reviewed and discussed.
Licensee program guidance, actions, and results were evaluated against applicable sections of 10 CFR Part 20, TS, ODCM, and approved procedural requirement ~'.
~,
Observations and Findin s Both chemistry technicians and operations personnel demonstrated appropriate knowledge of procedural requirements and proficiency in completing assigned tasks.
Technicians conducting pre-release sampling and radionuclide analyses were knowledgeable of equipment and procedures.
Control room operators double-verified valve line-ups in preparation for the release and demonstrated knowledge of the effluent system capabilities and operations.
However, the use of a 1000 cubic centimeters per minute (cc/min) flow meter to verify the 1000 cc/min collection flow rate for the pre-release containment air sample was identified as a practice which could affect the accuracy of subsequent radionuclide analysis.
The inspectors noted the recommended practice is to use a flow rate meter which allows the specified sample flow to be monitored between 25 to 75 percent of the equipment's measurement range.
Licensee representatives initiated a condition report to evaluate the specified flow rate of 1000 cc/min and the subject flow measurement device currently used for a 20 minute sampling period.
Conclusions Chemistry technicians and operators demonstrated appropriate knowledge of procedures and proficiency in completing a containment mini-purge release.
Radioactive Waste and Material Trans ortation Activities Ins ection Sco e 86750 Radiation protection (RP) program activities associated with characterization, packaging, and transportation of radioactive waste for subsequent burial were=reviewed.
For selected shipments made between January 1, through December 31, 1998, procedures, quality control (QC) records, shipping papers, and supporting documentation were reviewed and evaluated for accuracy and completeness.
Program guidance and implementation were evaluated against 10 CFR Parts 20, 61, and 71, and Department of Transportation (DOT) 49 CFR Parts 170-189 regulations.
Observations and Findin s Licensee procedural guidance met applicable regulatory requirements.
The 10 CFR Part 61 radionuclide analyses met guidance specified in the Final Waste Classification and Waste Form Technical Position Paper dated May 1983.
For the selected radioactive waste shipments reviewed, documentation was accurate and complete.
Conclusions Processing, packaging, and shipment of radioactive waste for disposal met 10 CFR Parts 20, 61, and 71, and 49 CFR Parts 170-189 requirement R5 Staff Training in Radiation Protection and Chemistry R5.1 Hazardous Material Trainin (86750)
Ins ection Sco e
Hazardous material (Hazmat) training was evaluated and discussed for selected personnel processing, packaging, and shipping radioactive waste in November 1998.
Training and testing frequencies, and associated documentation were compared against requirements specified in 49 CFR 172.704.
b.
Observations and Findin s Worker training was conducted at the required frequency and met the general awareness, function specific, and safety training requirements.
During review of worker records, the inspectors noted that although training and testing were conducted in accordance with the applicable regulations, the associated certification specified in 49 CFR 172.704(d)(5) could only be produced for several supervisors and HPTs prior to the end of the 'onsite inspection.
Review of shipment records indicated that none of the individuals without readily available Hazmat certifications were responsible for oversight and final authorization of hazardous material shipments.
Licensee representatives stated that action to improve availability of certification records would be initiated for all personnel involved in processing, packaging and shipping radioactive materials.
Conclusions Hazmat training and testing for personnel processing, handling and shipping radioactive material and wastes was conducted in accordance with 49 CFR 172.704 requirements, R6 Radiation Protection and Chemistry Organization and Administration R6.1 Health Ph sics Technician Exceeds Overtime Limits (71750)
In late December 1998, the Unit 1 HP technician responsible for safety-related activities in the radiological controlled area (RCA), and for meeting minimum emergency plan onsite staffing, exceeded the overtime (OT) limits established by TS 6.2.2.f.2.
More specifically, the technician worked greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period during December 24 through 26, 1998.
The technician was scheduled to work four eight-hour shifts within a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period. After reviewing the actual hours worked, excluding turnover times and lunch breaks, the licensee concluded his work amounted to 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period. The inspector discussed this issue with the Health Physics Supervisor and reviewed the technician's work schedule.
The inspector also reviewed the CR root cause evaluation which concluded the incident was a direct result of personnel error by both the technician and onshift supervisor.
Neither of these individuals used the computer based "OT Tracker" system for scheduling the technician's overtime, contrary to company policy. Furthermore, poor communications between the supervisor and technician caused them to misunderstand the amount of overtime already worked and the overtime requirement e
TS 6.2.2.f.2 requires in part that health physics technicians should not be permitted to work more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period. The inspector determined that the technician worked 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period during December 24 through 26, 1998, which constituted a violation of TS 6.2.2.f.2.
However, this Severity Level IVviolation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy, and is identified as NCV 50-335/99-01-03, HP Technician Exceeded TS Overtime Limits. The violation is in the licensee's corrective action program as CR 99-0151.
R7 Quality Assurance in Radiological Protection and Chemistry Activities R7.1 Countin Room Qualit Control C Activities (84750)
Ins ection Sco e
Selected January 1, 1998, through January 28, 1999, counting room effluent measurement and environmental monitoring quality control (QC) program activities were reviewed and discussed.
The review included program implementation and results for the gamma spectroscopy systems, quarterly eNuent composite blind spike samples, and the 1998 inter-laboratory cross-check analyses.
Program activities were evaluated against 10 CFR Part 20, TS, and ODCM, and procedural requirements.
b.
Observations and Findin s For the in-service gamma spectroscopy systems, no significant concerns nor negative trends were identified for QC performance check and background data.
Inter-laboratory analyses were conducted in accordance with TS and no significant negative trends were identified. However, a concern was noted for the licensee evaluation of a quarterly eNuent composite spiked particulate sample analyzed in July 1998.
For the strontium-90 (Sr-90) radionuclide, the comparison ratio of 0.647, i.e., vendor result to known value, was outside of established acceptance criteria of 30 percent less than the known value.
The licensee subsequently added the associated standard deviation to the reported vendor value,and recalculated a comparison ratio of 0.77 which was now within the acceptance criteria. No other analysis of the initial disagreement was conducted.
The inspectors noted that Chemistry Operating Procedure Number. C-72, Processing Gaseous Waste, specifies that for isotope analysis results outside of the established minus 30 to plus 100 percent acceptance criteria, the vendor should be requested to perform isotope analysis on the actual vent particulate samples.
The procedure did not specify that the standard deviation could be added to the reported value. The inspectors noted that adding the standard deviation to the'reported vendor value without analyzing an additional sample or attempting to identify the 'cause of the initial disagreement was a poor practice which could decrease the effectiveness of the established QC activity.
Licensee representatives initiated a condition report to review and evaluate the observed practic y, 0 ~
Conclusions Counting room gamma-spectroscopy QC activities and inter-laboratory analyses were implemented appropriately and no negative trends were identified.
The addition of standard deviation to the observed value of a quality control spiked sample in order to meet acceptance criteria was identified as a poor practice.
R8 Miscellaneous Radiation Protection and Chemistry Issues R8.1 Closed LER 50-389/98-10-00: Failure to Meet Reactor Coolant System (RCS) Boron Concentration Sample Frequency (92904)
On December 7, 1998, Unit 2 was starting up from a planned refueling outage.
RCS sampling for boron was required every 40 minutes per TS 3.1.2.9 since the boronometer was out of service to support chemical volume and control system (CVCS) maintenance.
A personnel error was made by control room supervision when an equipment clearance order was authorized that resulted in disabling the RCS sample line. Two minutes after the 40 minute requirement, control room personnel were notified by the chemistry technician that an RCS sample could not be drawn. The boron sample was obtained after the flow path was restored, 12 minutes beyond the TS required time limit.
The safety significance of the missed surveillance was minimal since the boron sample is redundant to the boron dilution alarm system (BDAS), which was operational during the entire period.
Corrective actions have been implemented to satisfactorily address the human performance and procedural inadequacies associated with this event.
Additionally, a license amendment has been submitted to eliminate the unnecessary.
boron sampling requirements of TS 3.1.2.9 since it is redundant to the BDAS. This non-compliance constitutes a violation of minor significance and is not subject to formal enforcement action.
R8.2 Closed VIO 50-335 389/97-13-02: Inadequate Radiation Worker Awareness of Radiation Work Permit (RWP) Requirements.
The inspectors reviewed the licensee's Reply to Notice of Violation dated January 14, 1998.
In addition, Daily Quality Summaries detailing acceptable results for radiation worker knowledge and practices from approximately June through December 1998 were reviewed.
The inspectors verified the corrective actions and found them as stated.
This item is closed.
S2 Status of Security Facilities and Equipment S2.1 Seconda Alarm Station SAS Tour(71750)
An inspector toured the secondary alarm station and interviewed the security guards on-watch. The SAS was appropriately manned.
Guards were knowledgeable of their duties and responsive to incoming alarms.
Allclosed circuit television (CCTV) cameras and displays appeared to be functioning properly and clearly. The guards were familiar with all outstanding security equipment deficiencies in the plant. They effectively
25'emonstrated the tracking system used to ensure equipment problems were being prioritized and fixed on a timely basis.
V. Mana ement Meetin s and Other Areas X1 Exit Meeting Summary The inspectors presented the inspection results to members of lice'nsee management at the conclusion of the inspection on March 9 and 18, 1999.
An interim exit meeting was held on January 29, 1999, to discuss the findings of Region based inspections.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
PARTIALLIST OF PERSONS CONTACTED Licensee M. Allen. Operations Manager C. Bible, Site Engineering Manager G. Bird, Security Manager W. Bladow, Site Quality, Manager D. Fadden, Training Manager D. Faulkner, Supervisor, Chemistry J. Holt, Maintenance Manager H. Jacobs, Mechanical Maintenance Supervisor E. Katzman, Supervisor, Health Physics & Chemistry W. Korte, Electrical Maintenance Supervisor C. Ladd, Operations Supervisor R. McCullers, Supervisor, Health Physics H. Mercer, Technical Supervisor, Health Physics K. Mohindroo, Plant Engineering Manager M. Moran, Operations Support Engineering Manager T. Patterson, System Engineering Manager A. Pawley, l8C Maintenance Supervisor A. Scales, Assistant Operations Supervisor A. Stall, St. Lucie Plant Vice President
'.
Weinkam, Licensing Manager C. Wood, Work Control Manager R. West, St. Lucie Plant General Manager
INSPECTION PROCEDURES USED IP 37551 IP 40500 IP 42001:
IP 61726:
,IP 62707:
IP 62700 IP 71707:
IP 71750:
IP 84750 IP 86750 IP 92?00:
IP 92702 IP 92901 IP 92902 IP 92903 IP 92904 Onsite Engineering
. Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Emergency Operating Procedures Surveillance Observations Maintenance Observations Maintenance Rule Observations Plant Operations Plant Support Activities Radioactive Waste Treatment and Effluent and Environmental Monitoring Solid Radioactive Waste Management and Transportation of Radioactive Materials Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities Followup on Corrective Action For Violations and Deviations Followup - Plant Operations Followup - Maintenance Followup - Engineering Followup - Plant Support ITEMS OPENED CLOSED AND DISCUSSED
~oened 50-389/99-01-01 50-335/99-01-02 50-335/99-01-03 Closed 50-389/99-01-01 50-335, 389/98-06-03 50-335, 389/98-08-00 NCV NCV NCV NCV VIO LER Inadequate Corrective Actions (Section 02.4)
Scaffolding Construction Discrepancies (Section M1.5)
HP Technician Exceeded TS Overtime Limits (Section R6.1)
Inadequate Corrective Actions (Section 02.4)
Corrective Action Program Lacks Focus on Correction of Problems (Section 08.1)
Inadequate Reactor Protection System Trip Bypass Technical Specification (Section 08.2)
50-335, 389/98-10-01 IFI 50-335,389/97-11-04
'FI CMM Scheduling Practices (Section M8.1)
Follow-up to PM Program Changes (Section M8.2)
50-335/99-01-02 50-335/99-01-03 50-389/98-10-00 50-335, 389/97-13-02:
Scaffolding Construction Discrepancies (Section M1.5)
HP Technician Exceeded TS Overtime Limits (Section R6.1)
Failure to Meet Reactor Coolant System (RCS)
Boron Concentration Sample Frequency (Section R8.1)
Inadequate Radiation Worker Awareness of Radiation Work Permit (RWP) Requirements (Section R8.2)
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0