IR 05000335/1999003
| ML17241A392 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 06/25/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17241A391 | List: |
| References | |
| 50-335-99-03, 50-335-99-3, 50-389-99-03, 50-389-99-3, NUDOCS 9907070027 | |
| Download: ML17241A392 (21) | |
Text
U.S. NUCLEAR REGULATORYCOMMISSION
REGION II
Docket Nos:
50-335, 50-389 License Nos:
50-335/99-03, 50-389/99-03 Licensee:
Florida Power & Light Co.
Facility:
St. Lucie Nuclear Plant, Units 1 & 2 Location:
6351 South Ocean Drive Jensen Beach, FL 34957 Dates:
April 18 - May 29, 1999 Inspectors:
T. Ross, Senior Resident Inspector D. Lanyi, Resident Inspector G. Warnick, Resident Inspector Approved by:
L. Wert, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
'P907070027 990b25 PDR ADQCK 05000335
EXECUTIVE SUMMARY St. Lucie Nuclear Plant, Units 1 L 2 NRC Inspection Report 50-335/99-03, 50-389/99-03 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a 6-week period of resident inspection.
~Oerations
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Two examples were identified in which control room operators did not apply a questioning attitude or properly pursue resolution of important equipment operability issues (Section 01.1).
Senior site management initiated actions to improve the utilization of the corrective action program.
These actions addressed recent findings that some work groups were not using Condition Reports to address problems (Section 07.1).
Maintenance The licensee's overall resolution of Intake Cooling Water pump shaft corrosion problems was effective. While initial efforts to investigate the pump shaft failure were not aggressive, once the shaft corrosion was identified, the licensee's actions were reasonable and prudent.
Mechanical maintenance activities were conducted according to written work instructions by skilled personnel.
Maintenance supervision provided active oversight and direction of the work.
Engineering support of the work activities, resolution of emergent problems, and root cause investigation was effective. (Section M1.2).
Foreign material exclusion controls in the spent fuel pool areas were effective for routine day-to-day entries.
However, long term accountability and control of items left in the areas were not adequate.
A non-cited violation was identified regarding inadequate procedural guidance for these aspects of foreign material exclusion controls (Section M2.1).
Operations and Instrumentation and Controls personnel properly performed an Auxiliary Feedwater Actuation System relay test using effective pre-job briefings, three part communications, and peer checking.
Attention to detail by the involved technicians resulted in a test procedure error being identified and corrected (Section M4.1).
Encnineerinq Program requirements for implementing Technical Specification 6.8.4.a(i) regarding preventive maintenance and visual inspection of potential highly radioactive primary coolant leaks outside containment were not well defined.
Other existing plant processes were adequately minimizing leakage.
Engineering conducted a thorough review of the issue and developed corrective actions for providing additional controls to ensure leakage limits were maintained within the safety analysis assumptions (Section E3.1).
The licensee identified several errors in the analysis of a main steam line break in containment.
A re-analysis, using more appropriate assumptions, indicated that Unit 1 containment pressure could exceed the value specified in the Updated Final Safety Analysis Report and Technical Specification bases.
The licensee completed an evaluation which concluded that the Unit 1 containment was operable and continued
operability was justified per the guidance of Generic I etter 91-18. The licensee's immediate corrective actions were comprehensive and additional actions are planned (Section E8.2).
Plant Su ort Security officers completing Fire Protection Program requirements for roving fire watches as part of their dedicated patrols were knowledgeable of their fire watch responsibilities.
The fire watch tours were routinely being accomplished more frequently than specified by regulatory requirements (Section S1.1).
I
Re ort Details Summa of Plant Status Both units operated at essentially full power for the entire report period.
01.1 Conduct of Operations Control Room Observations (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of plant operations including observations of Main Control Room (MCR) activities.
In general, the conduct of Operations was professional and safety-conscious.
Operator knowledge of plant status, system configuration, and existing alarms was excellent.
However, two examples were identified of inadequate questioning and resolution on the part of control room operators regarding equipment operability issues.
These deficiencies were discussed with Operations management and addressed in the corrective action program.
On May 18, the power supply for Unit 1 pressurizer level channel LI-1110Y failed. Since LI-1110X was already out of service (OOS), both pressurizer level indicators at the remote shutdown panel were inoperable.
Operators entered a 30-day action statement as required by Technical Specification (TS) 3.3.3.5.
However, the power supply failure also affected the operability of the Channel A subcooling margin monitor. The operators considered entering the action statement for accident monitoring (TS 3.3.3.8), but despite some confusion on how to interpret the TS requirements, they decided not to enter the action statement.
The inspectors questioned this interpretation.
Licensing subsequently determined that TS 3.3.3.8 was incomplete and initiated Condition Report (CR) 99-0745.
Apparently, an error occurred during processing of a previous license amendment and the TS did not provide definitive guidance regarding the inoperability of one subcooling margin monitor. Operations management decided that the previous interpretation was incorrect and the 30 day action statement for TS 3.3.3.8 was entered.
Corrections were made to the OOS logs. No TS violations occurred. The operators did not apply conservatism regarding entry into the action statement and did not initiate a CR when the TS question was initiallyidentified.
On May 25, the 2A Qualified Safety Parameter Display System (QSPDS) plasma monitor was declared inoperable.
While Instrumentation and Control (l&C)technicians conducted troubleshooting and repair activities, operators considered 2A QSPDS operable because the TS 3.3.3.8 required parameters for subcooling margin, reactor vessel level, and core exit temperatures could be read off a local QSPDS cabinet behind the control boards.
However, when questioned, by an inspector on how these parameters would actually be obtained, the operating crew was unfamiliar with operation of the cabinet.
The procedure (and the operator's discussion) indicated that a complex process was required to obtain the readings.
It appeardd to the inspector that it would not be practical to obtain the readings in an emergency.
Subsequently, it was identified that the readings were actually much more directly available.
Some indication problems were noted with these displays which were resolved.
The other channel of QSPDS was operable and no TS action statement entry was required.
CR 99-0783 was initiated to provide additional training and guidance to operator.1 Operational Status of Facilities and Equipment General Plant Tours (71707)
The inspectors performed frequent tours of the plant. The inspectors noted that plant housekeeping, although generally adequate, had declined recently.
For example, the
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inspectors identified, on several occasions, unsecured equipment (ladders and vacuum cleaners) near safety related equipment.
Additionally, the inspectors noted minor oil and water leaks throughout the units. The cleanliness of equipment in the 2B emergency diesel generator room had declined. 'o operability issues were identified and the licensee addressed the items.
02.2 En ineered Safet Feature S stem Walkdowns (71707)
General walkdowns of accessible portions of the Unit 1 high pressure safety injection and containment spray systems, and the Unit 2 post accident sampling and intake cooling water systems were conducted by the inspectors using Inspection Procedure 71707.
Material condition, equipment operability, and general housekeeping were acceptable.
Applicable valves and breakers were noted to be properly aligned.
Only minor discrepancies were identified by the inspectors.
These were forwarded to the licensee and placed into the corrective action program for resolution.
Operator Knowledge and Performance Unit 2 Senior Nuclear Plant 0 erator SNPO Tour (71707)
On May 22, 1999, an inspector accompanied the Unit 2 SNPO on a routine plant tour.
The SNPO was knowledgeable of the systems and component operation in his areas of responsibility, and aware of outstanding deficiencies associated with the equipment.
The tour was performed deliberately as the operator took his time to thoroughly examine conditions to detect abnormalities or changes in equipment operation.
Additionally, as the SNPO progressed from one location to the next, he carefully observed conditions of the surrounding structures, systems, and components.
When new equipment deficiencies were identified, appropriate actions were taken by the SNPO to address the problem.
Overall, the SNPO conducted a thorough tour using his familiaritywith the systems and components to detect abnormal or changing conditions.
Quality Assurance in Operations 07.1 Utilization of the Corrective Action Pro ram (40500 and 71707)
,In response to a.finding described in Section S7,.4 of IR 50-335, 389/99-10, the licensee initiated Condition Report (CR) 99-0620 to address an NRC concern that the Security organization was not effectively utilizing the established corrective action program.
This finding was similar to an earlier determination by the licensee that the Training department had not been using the CR process effectively.
The licensee conducted a comprehensive evaluation of CR usage by various departments throughout the plant. The licensee identified that several departments (e.g., Work Control, Health Physics, Nuclear Materials, Maintenance) did not appear to be using the CR process on a frequent basis for resolving problems.
Subsequent
actions were immediately taken by senior site management to stress the importance and promote utilization of the CR process as an integral part of the site corrective action program at regular management meetings.
In addition, the site Vice President issued a memo to each department manager identified above requesting them to provide a written action plan for imgoving their department's utilization of the CR process and monitoring its effectiveness.
Furthermore, in "A Message from the Site Vice President" to plant employees, utilization of the CR process for identifying and resolving problems was re-emphasized.
Since these efforts, NRC inspectors and licensee personnel have noted a marked increase in the number of CRs initiated.
II. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Work Order and Surveillance Observations The inspectors observed portions of the following Plant Work Orders (PWO) and Instrumentation and Controls Procedure (ICP) maintenance and surveillance activities:
PWO 99005738 PWO 97026632 ICP 1-1220052 ICP 2-1400198 ICP 2-1400160 1B Hydrogen Analyzer Monthly Replace Valve V14163 Linear Power Range Safety Channel Quarterly Calibration Reactor Protection System Channel Calibration Variable High Power Quarterly Delta -T Power Channel Calibration Quarterly b.
Observations Findin s andConclusions Work was performed consistent with the established work control processes.
Maintenance supervision and Engineering were closely involved in the work activities.
The tasks were competently performed by knowledgeable workers actively using applicable work packages and procedures.
The inspectors observed that work activities were properly documented.
Additionally, problems encountered during the performance of the work activities were appropriately resolved, with one minor exception.
On May 24, during the conduct of ICP 2-1400198, the inspector observed that the
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Variable High Power Trip Reset button of reactor protection system (RPS) channel C would not reset when pushed.
On two occasions, the technician had to push the button several times before the variable high power trip would reset.
The inspector questioned whether this equipment problem warranted initiating a condition report or PWO. The technicians did not consider either one necessary.
After the testing was completed, the inspector discussed the matter with the Instrumentation and Controls Supervisor.
The supervisor reviewed the issue and subsequently reported that a PWO would be initiate M1.2
Unit 1 Intake Coolin Water Pum ICW Shaft Failure And Re airs Ins ection Sco e (62707)
b.
The inspectors observed and reviewed portions of the licensee's activities associated with an ICW pump shaft failure. The inspectors observed boroscope examinations of the 1B and 2C ICW pump shafts, reviewed failure analysis reports, and held discussions with maintenance and engineering personnel.
Observations and Findin s On April 9, the 1A ICW pump shaft sheared while the pump was operating.
Operators promptly placed the idle 1C ICW pump in service on the A ICW train to meet operational and Technical Specification (TS) requirements.
Condition Report (CR) 99-0463 was written to address the sudden failure. However, disassembly of the 1A ICW pump to investigate the failure mechanism did not begin until April 15. Once disassembled, the licensee identified that a localized area of the shaft had experienced a severe pitting-type of corrosive attack which reduced the nominal shaft diameter from four inches to 2~/~ inches.
Subsequent metallurgical failure analysis concluded the ultimate failure of the shaft resulted from torsional overload after wastage and corrosion-induced fatigue cracking reduced the shaft cross section below its load carrying capacity.
The corrosive attack was determined to be caused by stray currents from the cathodic protection system discharging between the shaft and pump casing due to poor shaft ground connection during pump operation.
A series of direct current (DC) potential measurements of the ICW pumps indicated that the shafts of the idle pumps were normally grounded to the casing through the motor bearings, but during pump operation a nonconductive oil film formed on the bearing surfaces creating a significant electrical potential difference.
Based on these readings, the operating pumps were deemed to be more susceptible to stray currents and thus, the corrosion mechanism.
The 1C and 2C ICW pumps are usually idle, while the 1A, 1B, 2A and 2B pumps are run continuously.
Maintenance history indicated that the 1A pump had been in service for almost eight years since its last overhaul.
Allthe other pumps had similar maintenance histories except the 2A and 2B pumps which were overhauled just a couple of years ago.
The licensee decided to examine the 1B ICW pump shaft after repairing the 1A pump.
The 1A ICW pump was replaced, including the shaft, on an expedited schedule and returned to service on May 7. On May 10, a boroscope examination of the 1B ICW pump shaft showed severe degradation (similar to the 1A ICW pump shaft) with a reduced diameter of 2 7/8 inches.
Condition report 99-0636 was written to address the problem. Subsequent metallurgical analysis of the shaft confirmed the corrosive mechanism was the same, but no fatigue cracking was found. An initial engineering evaluation concluded the 1B pump shaft was degraded, but operable.
The shaft was repaired, and the 18 ICW pump returned to service on June 7. During this time, the 1C ICW was in service and aligned to the B train.
The licensee also performed a boroscope examination of the 2C ICW pump shaft on May 24. This examination did not identify any significant degradation.
The 2C ICW pump was returned to service the next day.
A boroscope examination of the 1C ICW
pump was scheduled for June 15.
The 2A and 28 pump shafts were not examined due to their recent overhauls.
Allmaintenance'activities observed by the inspectors were conducted according to written work instructions and administrative requirements, with only a few minor exceptions that were promptly addressed.
Mechanics were knowledgeable and skilled.
Maintenance supervision was actively involved in directing and overseeing work activities throughout the repair evolutions.
Engineering support of maintenance work, resolution of emergent problems, and root cause investigation was effective. Although the formal root cause investigation was still in progress, the engineering disposition of CR 99-0463, along with the metallurgical failure analyses of both the 1A and 18 pumps, were thorough. The final engineering disposition of CR 99-0636 was also in progress, and is expected to address any reportability issues regarding common cause failures.
The two remaining long term corrective actions from CR 99-0463 were to complete the root cause investigation and explore installation of a grounding device.
Overall, the inspectors considered the licensee's approach and timetable for resolving the ICW pump shaft corrosion problems were reasonable and prudent once the corrosion of the A ICW shift was identified. However, the initial investigation of the failed 1A ICW pump was delayed for several days. This did not seem appropriate given the failure occurred unexpectedly and the cause was not known.
In response to the inspector concerns, the licensee initiated CR 99-0819.
Conclusions The licensee's overall resolution of Intake Cooling Water pump shaft corrosion problems was effective. While initial efforts to investigate the pump shaft failure were not aggressive, once the shaft corrosion was identified, the licensee's actions were reasonable and prudent.
Mechanical maintenance activities were conducted according to written work instructions by skilled personnel
~ Maintenance supervision provided active oversight and direction of the work.
Engineering support of the work activities, resolution of emergent problems, and root cause investigation was effective.
Maintenance and Material Condition of Facilities and Equipment Forei n Material Exclusion Control of the S ent Fuel Pool Areas An inspector toured the Unit 1 and 2 fuel handling buildings, including the spent fuel pool (SFP) areas.
During these tours, the inspector reviewed the SFP Access Control Logs for thoroughness and completeness.
The inspector reviewed Quality Instruction (Ql) 13-PR/PSL-2, Foreign Material Control, Housekeeping, And Cleanliness Control Methods and interviewed responsible Maintenance and Health Physics (HP)
supervisors.
Observations and Findin s The SFP Access Control Logs were used to document personnel access and material accountability in and around the SFPs.
According to Ql 13-PR/PSL-2, the areas posted
immediately around the Unit 1 and 2 SFPs were established as a foreign material exclusion (FME) area 1 and received the highest level of FME controls.
The inspector noted that the Access Control Logs were being used routinely for short duration entries into the SFP FME area.
Although these logs were well maintained for short-term activities, the inspector was unable to determine the status of material left in the SFP FME area on a long term basis.
There were no logs available that provided material accountability for the numerous pieces of equipment and material left in both SFP FME areas.
Subsequent discussions with responsible Maintenance and HP supervisors indicated that an inventory of long-term items in the SFP FME areas was not being maintained.
No documented inventory of equipment and material in the Unit 1 SFP FME area existed.
For Unit 2, a complete survey of material and equipment left in the SFP FME area had been conducted in December 1998 after the fast refueling outage, but had not been updated since.
This lack of material accountability represented a loss of FME integrity per section 5.15.7.A of Ql 13-PR/PSL-2.
In response to the inspector's findings, the licensee promptly surveyed both SFP FME areas to re-establish material accountability. The Unit 2 SFP survey compared favorably with the prior December 1998 survey.
Condition Report (CR) 99-0014 was initiated to resolve control of long term items in the SFP FME areas.
On a day-to-day or short term basis, the SFP FME barriers and controls were effective.
Also, the inspectors have observed that dedicated FME monitors assigned during periods of high work activity (e.g., refueling) were also effective. However, no one group appeared to have overall responsibility for monitoring and maintaining accountability of SFP FME inventory throughout the operating cycle. Further review of Ql 13-PR/PSL-2 identified a tack of specific instructions for maintaining accountability and establishing responsibilities for control of foreign material left in the SFP FME area.
This lack of procedural guidance for an activity affecting quality constituted a violation of 10CFR50, Appendix B, Criterion V. This Severity Level IVviolation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of the Enforcement Policy, and is identified as NCV 50-335,389/99-03-01, Inadequate Foreign Material Accountability Controls For The Spent Fuel Pool Areas. This violation is in the licensee's corrective action program as CR 99-0014.
C.
Conclusions M4 M4.1 Foreign material exclusion controls in the spent fuel pool areas were effective for routine day-to-day entries.
However, tong term accountability and control of items left in the areas were not adequate.
A non-cited violation was identified regarding inadequate procedural guidance for these aspects of foreign material exclusion controls.
Maintenance Staff Knowledge and Performance Unit 2 Auxilia Feedwater Actuation S stem AFAS Rela Test On April28 and 29, 1999, an inspector observed the performance of an AFAS relay test.
Observations included the pre-job briefing'conducted by the Assistant Nuclear Plant Supervisor (ANPS), test performance, and plant manipulations conducted by Operations to support testin b.
Observations and Findin s C.
A pre-job briefing was satisfactorily conducted by the ANPS using the guidance and checklist provided in administrative procedure ADM-0010120, Conduct of Operations.
Precautions and limitations, past operational experience, worker expectations, and potential contingency actions were adequately addressed during the briefing.
Operations and Instrumentation and Control (I&C)testing activities were well performed; three part communications were consistent, peer checking was used when warranted, and paperwork controls met administrative requirements.
During the relay testing, the l&Ctechnicians identified a procedural error that needed to be resolved prior to continuation.
Upon discovery of the error, l8 C and Operations personnel stopped the testing, restored the system to a normal configuration, and processed a temporary change to the procedure.
A Condition Report (CR) was written to determine the cause of the procedural error and verify that it did not affect past relay tests.
The CR response identified that a word processing error during the latest revision was the source of the error. This relay testing was the first conducted with the procedure revision containing the error.
Conclusions Operations and l8C personnel properly performed an AFAS relay actuation test using effective pre-job briefings, three part communications, and peer checking.
I&C technicians exhibited a questioning attitude. A test procedure error was identified and corrected.
M6.1 Maintenance Organization and Administration Fix It Now FIN Team Im lementation (62707)
An inspector reviewed the administrative controls associated with the recently implemented FIN team process.
The FIN program is used to mobilize resources, commence troubleshooting, and gather information to effectively plan for high priority plant work orders.
Interviews were conducted with the program administrator, supervisors, and several journeymen to assess program capabilities, limitations, and actual implementation.
The inspector determined that the procedures associated with the FIN process adequately described the process and provided appropriate administrative controls for work items assigned to the FIN team.
There have been examples of maintenance tasks not meeting the FIN criteria being initiallyassigned to the FIN team.
However, the screening process and established administrative barriers ensured that the proper work control process was used to perform the work. The inspectors concluded that the FIN program has adequate supervisory oversight and administrative guidelines to effectively control high priority maintenance activitie III. En Ineerin E2 E2.1 Engineering Support of Facilities and Equipment Plant S stem Health Meetin (37551)
E2.2 An inspector attended the quarterly plant system health meeting on May 25 presented by Engineering as part of the licensee's Maintenance Rule program.
In general, the health of most systems was trending steady or improving. The responsible system engineers discussed the status of the recovery plans for those systems which were rated as red (unsatisfactory) or yellow (marginal). Overall, the recovery plans appeared to be well structured and were restoring the affected systems to satisfactory performance.
Plant Confi uration Mana ement (37551)
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E3.1 An inspector conducted an evaluation of the configuration controls associated with plant changes or modifications (PC/Ms). Several completed PC/Ms were reviewed to assess design control procedural adherence.
Administrative guidance for configuration controls, as provided in procedure QI-3-PSL-1, Revision 4, Design Control, were followed for each PC/M reviewed.
Design change close out was verified to be adequate through review of design change package documentation and revisions to procedures and drawings.
Plant configuration management has adequate administrative controls to properly implement PC/Ms. Configuration controls were effectively implemented for the PC/Ms reviewed.
Engineering Procedures and Documentation Prima Coolant Sources Outside Containment Ins ection Sco e 37551 b.
An inspector reviewed the procedures and implementation of the licensee's program to meet TS 6.8.4.a "Primary Coolant Sources Outside Containment."
Observations and Findin s TS 6.8.4.a requires the licensee to establish a program to monitor and reduce potential highly radioactive leakage from certain systems outside containment (i.e., Shutdown Cooling, High Pressure Safety Injection, Containment Spray, and Reactor Coolant System Sampling) to levels as low as practical.
Current plant operating procedure (OP)
1-1300054, Reactor AuxiliaryBuilding Fluid.Systems Periodic Leak Test, established the program requirements for section (ii) of TS 6.8.4.a regarding leak testing on a refueling interval basis.
However, no specific procedure existed to establish the program requirements for section (i) of TS 6.8.4.a regarding preventive maintenance and periodic visual inspections.
Instead of an explicit procedure for TS 6.8.4.a(i), the licensee relied on other established programs to fulfillthe TS requirements.
These. programs contained requirements for periodic visual inspections of the subject systems, such as during operator rounds and quarterly inservice testing. Additionally, the work control process and corrective action
program were used to ensure identified leaks were repaired.
These efforts were effective at identifying leaks and scheduling them for repair.
However, except for.
throughwall leaks and active leaks that posed operational, radiological, or maintenance problems, there'was no apparent guidance to ensure primary coolant leaks were reduced to as low as practical and maintained below safety analysis assumptions.
UFSAR Section 15.4.1.7 defined the maximum potential leakage to be about two liters per hour for offsite dose calculations of large break loss of coolant accidents.
This corresponds to little more than six drops a second of total primary coolant leakage outside containment.
Excess leakage could constitute an unanalyzed condition.
To address the inspector's concerns, the licensee initiated CR 99-0831. After conducting a detailed review of their TS 6.8.4.a program, responsible Engineering personnel met with the inspector.
They presented evidence that the most recent periodic leak test data indicated primary coolant source leakage for Unit 1 during the previous fuel cycle was at or just below the UFSAR limits, and the Unit 2 leakage was well below the limits.
Current identified leaks (although not specifically quantified)
appeared to be within UFSAR limits for both units. The licensee indicated that in light of the extremely low quantity of leakage assumed by the UFSAR, additional corrective actions would be implemented to ensure leakage was maintained within safety analysis assumptions.
Conclusions Program requirements for implementing Technical Specification 6.8.4.a(i) regarding preventive maintenance and visual inspection of potential highly radioactive primary coolant leaks outside containment were not well defined. Other existing plant processes were adequately minimizing leakage.
Engineering conducted a thorough review of the issue and developed corrective actions for providing additional controls to ensure leakage limits were maintained within the safety analysis assumptions.
Miscellaneous Engineering Issues (92901 and 92903)
Closed Licensee Event Re ort LER 50-389/99-001; Inadequate Technical Specification Surveillance Requirements for Safety Injection Tank and Shutdown Cooling Isolation Valves. The LER reported the licensee's identification of certain discrepancies between the Unit 2 Technical Specification (TS) surveillance requirements for the safety injection tank isolation valve and the shutdown cooling system isolation valve interlocks and the plant procedures used to implement the surveillances.
The interlocks were being tested conservatively with regards to the intended design and TS requirements.
The wording of the TS does not appear to be consistent with the intended design requirements.
An inspector verified that the licensee had submitted a license amendment request to clarify the surveillance requirements.
Additionally, the inspector reviewed the applicability to Unit 1. Only a minor procedural deficiency was identified and this was placed into the licensee's corrective action program. This LER is considered closed.
Closed LER 50-335/98-009; Non-Conservative Main Steam, Line Break Analysis Inputs Result in Operation of Facility Outside Design Basis
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The inspectors performed a review of the LER and the licensee's actions to address the issues.
Observations and Findin s On December 23, 1998, as part of a self-initiated project to rebaseline the main steam line break (MSLB) safety analysis, St. Lucie Engineering personnel determined that a Unit 1 MSLB in containment could result in a higher peak containment pressure (approximately 56 psig) than the value described in the UFSAR and the TS bases (44 psig). The licensee attributed the difference between the new analytical results and the old analysis to several non-conservative assumptions in the original calculations.
The most significant of these assumptions involved feedwater flow, feedwater isolation, and initial containment pressure.
The original MSLB of record was developed jointly by Combustion Engineering (mass energy input) and EBASCO (containment performance).
The licensee subsequently concluded that the Unit 1 containment remained operable.
Condition Report (CR) 98-2114 stated that Technical Specifications 3/4.6.1.2, Containment Leakage, and 3/4.6.1.6, Containment Vessel Structural Integrity were based on a peak containment pressure of 39.6 psig for the limiting design basis Loss of Cooling Accident (LOCA), and did not apply to the MSLB event. The LER presented a
"best estimate" analysis performed to determine the response of the plant to "normal" plant conditions instead of the conservative design basis assumptions.
The peak containment pressure was calculated to only reach 43 psig under those conditions, and therefore would remain below the design pressure.
The LER also stated that the Individual Plant Examination submittal had estimated, in accordance with NUREG/CR-2442, a containment failure pressure of 95 psig. The licensee justified continued operation of the unit with this potential overpressure condition based on the guidance in Generic Letter 91-18.
The inspectors discussed the CR with the licensee's Licensing and Engineering staff.
The inspector noted that the basis for Technical Specification 3/4.6.1.4, Containment Systems Internal Pressure, was to ensure that "...the containment peak pressure does not exceed the design pressure of 44 psig during steam line break conditions." The licensee stated that this was incorrect and it would be corrected in the near future.
After discussions with the NRC, the licensee amended the CR to include additional justification for their operability determination.
The licensee reviewed the containment predicted stresses at 56 psig and compared those stresses to the American Society of Mechanical Engineers (ASME)Section III code allowable stresses.
The licensee determined'hat the allowable stresses were 20 percent greater than the calculated stresses at the higher pressures.
Therefore, the containment was operable.
The inspector reviewed the licensee's calculations and documentation.
They appeared accurate and supported the licensee's position.
The licensee plans to correct the problem in two phases.
During the next refueling outage (September 1999) the licensee plans to install a modification to trip both main feedwater pumps upon a main steam isolation signal. This should eliminate the containment overpressure concerns.
The second phase will involve installing different actuators on the main feedwater isolation valves so they willshut more rapidly. This
modification would not be ready for installation until the following outage planned for the Spring of 2001.
The licensee identified, in a self-initiated review, that a condition existed in which the containment pressure could exceed the values described in the UFSAR and TS bases during a MSLB. Criterion III of Appendix B to10 CFR 50, Design Control, requires, in part, that measures shall be established to ensure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions.
Contrary to the above, since initial plant construction, the licensee did not correctly translate the design basis of the containment as described in UFSAR Section 6.2.1.1 into design specifications.
Specifically, conservative assumptions for feedwater flow, feedwater isolation, and initial containment pressure were not used in the Unit 1 main steam line break (MSLB) containment analysis.
Subsequent re-analysis by the licensee using more accurate design assumptions resulted in a peak containment pressure of 56 psig which exceeded the maximum internal pressure design of 44 psig as described in the UFSAR. The licensee determined that the ASME Section III code allowable stresses were 20 percent greater than calculated stresses at the higher peak pressure and concluded that the containment was operable.
In accordance with the "General Statement of Policy and Procedures for Enforcement Actions" (Enforcement Policy), NUREG-1600, this violation normally would be categorized as a Severity Level IVviolation. However, as provided in Section VII.B.3of the Enforcement Policy, the NRC may refrain from issuing a Notice of Violation (Notice)
which involves a past problem, such as an old engineering, design, or installation deficiency, provided that certain criteria are met.
After review of this violation and in consultation with the Director, Office of Enforcement, the NRC has concluded that while a violation did occur, enforcement discretion is warranted and issue of a Notice is not appropriate in this case, The specific bases for the decision to exercise enforcement discretion are:
(1 ) this old design issue was licensee-identified as result of a self-initiated comprehensive review; (2) the licensee's corrective actions to date were comprehensive and additional actions are planned; (3)
this issue was not likelyto be identified by the licensee's routine surveillance or quality assurance activities; and (4) this issue occurred during the initial plant construction.
This LER is closed.
Conclusions The licensee identified several errors in the analysis of a main steam line break in containment.
A re-analysis, using more appropriate assumptions, indicated that Unit 1 containment pressure could exceed the value specified in the UFSAR and TS bases.
The licensee completed an evaluation which concluded that the Unit 1 containment was operable and continued operability was justified per the guidance of Generic Letter 91-1e. The licensee's immediate corrective actions were comprehensive and additional actions are planne m Radiological Protection and Chemistry Controls Locked Hi h Radiation Controls (71750)
The inspector reviewed the licensee's program to control locked high and very high radiation areas, and verified that the licensee was complying with this program.
Overall, the program was well implemented.
Alllocked areas were being verified daily, and keys were being appropriately controlled. The inspector identified only minor clerical errors, which the licensee promptly placed into the corrective action program (Condition Report 99-0746).
Conduct of Security and Safeguards Activities Dedicated Securi Patrols (71750)
An inspector reviewed security force instructions and patrol logs, interviewed numerous security officers and supervisors, and accompanied various officers on portions of their patrols. The inspector focused primarily on the conduct of roving fire watches.
At the present time, security officers fulfillFire Protection Program requirements for establishing roving fire watches as an integral part of their dedicated patrols. Without exception, all security officers and supervisors interviewed and observed were knowledgeable and keenly aware of their fire watch responsibilities.
Roving fire watch tours were being accomplished more frequently than specified in regulatory requirements.
Security force instructions state that dedicated patrols are to be performed every half hour which is more often than the Fire Protection Program required hourly frequency. The record review and interviews indicated that, since security officers began performing fire watches late last year, fire watches have been conducted in a timely manner.
From the inspector's review of the patrol logs, only one instance was identified in which roving fire watches were not completed within a half hour period.
On June 1, an assigned security officer did not make a fire watch tour within the allotted half-hour.
In this instance, the officer was dispatched to participate in a fire drill that lasted longer than the time allowed to complete his patrol. CR 99-0849 was initiated. The root cause was determined to be a lack of communication between the officer and supervisor.
The officer only missed one of his half-hour fire watch tours. Consequently, the Fire Protection Program requirement for hourly tours was not violated. Security management took prompt corrective actions to counsel both employees and reinforce management expectations with all security personnel.
Armed Res onse Drills (71750)
During the month of May, inspectors observed numerous armed response drills. The drills were challenging and appeared to represent realistic threats to plant security and safety. A team of intruders with simulated arms were assembled and deployed under the guidance of a security consultant.
The drills provided excellent training for the onsite security force. Almost all intrusions were interdicted in an effective manner.
Critiques were conducted after each drill, whether totally successful or not, to discuss lessons
learned and implement realtime adjustments to their armed response tactics.
Each intrusion drillwas subsequently documented for future reference and assessment.
Furthermore, meetings by security management and the security force were held following a particular series of drills to reflect on performance and develop changes to improve their overall armed response strategies.
V. Mana ement Meetin s X1, Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on June 1, 1999. The licensee acknowledged the findings presented.
On June 22, 1999, an additional discussion was held with plant management regarding the resolution of the containment overpressurization issue. 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, Protection Services Manager W. Bladow, Maintenance Manager, Acting R. De La Espriella, Quality Assurance Manager, Acting D. Fadden, Training Manager C. Ladd, Operations Supervisor A. Stall, St. Lucie Plant Vice President R. Wade, Business Systems Manager E. Weinkam, Licensing Manager R. West, St. Lucie Plant General Manager INSPECTION PROCEDURES USED IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92901 IP 92903:
Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving and Preventing Problems Surveillance Observations Maintenance Observations Plant Operations Plant Support Activities Followup - Operations Followup - Engineering
~Oened 50-335,389/99-03-01 Closed 50-335,389/99-03-01 50-389/99-001-00 50-335/98-009-00 ITEMS OPENED CLOSED AND DISCUSSED NCV inadequate Foreign Material Accountability Controls For The Spent Fuel Pool Areas (Section M2.1)
NCV Inadequate Foreign Material Accountability Controls For The Spent Fuel Pool Areas (Section M2.1)
LER Inadequate Technical Specification Surveillance Requirements for Safety Injection Tank and Shutdown Cooling Isolation Valves (Section E8.1)
LER Non-Conservative Main Steam Line Break Analysis Inputs Results in Operation of Facility Outside Design Basis (Section E8.2)