IR 05000373/1999002
| ML20205R550 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 04/16/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20205R548 | List: |
| References | |
| 50-373-99-02, 50-373-99-2, 50-374-99-02, 50-374-99-2, NUDOCS 9904230091 | |
| Download: ML20205R550 (26) | |
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U.S. NUCi. EAR REGULATORY COMMISSION REGION lli Docket Nos:
50-373,50-374 License Nos:
50-373/99002(DRP); 50-374/99002(DRP)
Licensee:
Commonwealth Edison Company Facility:
LaSalle County Station, Units 1 and 2 Location:
2601 N. 21st Road Marseilles,IL 61341 Dates:
February 17 - March 31,1999 Inspectors:
M. Huber, Senior Resident inspector J. Hansen, Resident inspector R. Crane, Resident inspector Approved by:
Melvyn N. Leach, Chief Reactor Projects Branch 2 Division of Reactor Projects i
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EXECUTIVE SUMMARY LaSalle County Station, Units 1 and 2 Inspection Report 50-3'73/99002(DRP); 50-374/99002(DRP)
This inspection report included aspects of licensee operations, maintenance, engineering and plant support. The report covers a 6-week period of inspection conducted by the resident staff.
Plant Operations in general, the inspectors observed the continued good performance of Unit 1 and
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timely and safe completion of the Unit 2 fuel load. The operators' response to events on Unit 1 including failure of the 'B' reactor recirculation flow control valve rotational variable differential transformer controller and the fuel element leak was safe and in accordance with procedures. (Section O1.1)
In some instances, operations personnel were willing to accept degraded equipment
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status or operating practices and less than expected levels of support from other organizations. (Section O1.1)
The licensee's Restart issues Review Committee and the Plant Operations Review
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Committee meetings were etructured and comprehensive. Licensee management on the committees exhibited a questioning attitude and ensured that Unit 2 was ready to load fuel. Detailed system readiness reviews ensured that station management was aware of issues relevant to each system in the process, and the level of senior station management participation in the process indicated the high priority the licensee placed in the process. (Section O1.2)
The licensee effectively implemented its restart action plans regarding operator work-
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arounds, temporary modifications and system readiness reviews. The inspectors identified a valve controller designed for automatic operation that was being operated in the manual mode, which the licensee did not have in the operator work-around or operator challenge program. The licensee stated its intention to reevaluate the operating practice for the valve. (Section O1.3)
The preparation and movement of fuelin Unit 2 included timely completion of work
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activities, in depth reviews and approvals by senior licensee management, thorough training of fuel handling personnel, and significant oversight by the Nuclear Oversight organization. These preparations resulted in fuel moves being completed in a safe and efficient manner. (Section 01.4)
The inspectors idontified discrepancies on main control room panel indications on both
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Unit 1 and Unit 2. In addition, the inspectors found a Unit 2 main control panel switch with an out-of-service card affixed which did not have a label indicating switch position.
l Although control room indicators were operating correctly and measured parameters were within the range of acceptable values, operators conunued to accept parameters indicating outside the green band with some indicating in the red band. (Section O2.1)
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Maintenance The Division 11 and Division ill emergency core cooling system integrated response time
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tests were completed satisfactorily in accordance with plant procedures and in conformance with Technical Specifications. (Section M1.1)
During engineering safety feature system walk-downs, the inspectors identified that
poor maintenance practices and inadequate cleanup of the Unit 2 'B'/'C' residual heat removal and high pressure core spray corner rooms resulted in several housekeeping deficiencies. The cumulative impact of these items caused the inspectors to question the operatslity of the 'B'/'C' residual heat removal systems. No safety significance existed as fuel was not yet loaded in the Unit 2 reactor. The licensee stated that programs were in p! ace to ensure room cleanliness prior to Unit 2 fuel load.
(Section M2.1)
The licensee identified several maintenance program weaknesses during its
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investigation into the repetitive failures of a safety-related transformer supplying control power to the primary containment isolation air assisted check valves. The investigation performed to identify the cause of the repetitive failure was thorough. The licensee formulated acceptable plans to correct identified weaknesses and incorporated the plans into its corrective action program. (Section M4.1)
Enaineerina The engineering department's response to indications of a leaking fuel rod was timely,
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deliberate, and appeared appropriate. The licensee determined that a fuel clad leak occurred and initiated actions in accordance with plant procedures. The inspectors reviewed a preliminary plan formulated by the station reactor engineer to minimize the impact of the event. The plan appeared acceptabie. (Section E2.1)
E! ant Sunoor.1 Radiation protection and chemistry personnel provided prompt and effective support to
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operations shift personnel subsequent to the licensee's discovery of a potential fuel leak i
in the Unit 1 reactor. (Section R1.2)
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket Nos:
50-373,50-374 License Nos:
50-373/99002(DRP); 50-374/99002(DRP)
Licensee:
Commonwealth Edison Company Facility:
LaSalle County Station, Units 1 and 2 Location:
2601 N. 21st Road
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Marseilles,IL 61341 Dates:
February 17 - March 31,1999 Inspectors:
M. Huber, Senior Resident inspector J. Hansen, Resident inspector R. Crane, Resident inspector i
Approved by:
Melvyn N. Leach, Chief
Reactor Projects Branch 2 Division of Reactor Projects
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EXECUTIVE SUMMARY LaSalle County Station, Units 1 and 2 inspection Report 50-373/99002(DRP); 50-374/99002(DRP)
This inspection report included aspects of licensee operations, maintenance, engineesing and plant support. The report covers a 6-week period of inspection conducted by the resident staff.
Plant Operations In general, the inspectors observed the continued good performance of Unit 1 and
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timely and safe completion of the Unit 2 fuelload. The operators' response to events on Unit 1 including failure of the 'B' reactor recirculation flow control valve rotational variable differential transformer controller and the fuel element leak was safe and in accordance with procedures. (Section 01.1)
In some instances, operations personnel were willing to accept degraded equipment
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status or operating practices and less than expected levels of support from other organizations. (Section O1.1)
The licensee's Restart issues Review Committee and the Plant Operations Review
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Committee meetings were structured and comprehensive. Licensee management on the committees exhibited a questioning attitude and ensured that Unit 2 was ready to load fuel. Detailed system readiness reviews ensured that station. management was aware of issues relevant to each system in the process, and the level of senior station management participation in the process indicated the high priority the licensee placed in the process. (Section O1.2)
The licensee effectively implemented its restart action plans regarding operator work-
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arounds, temporary modifications and system readiness reviews. The inspectors identified a valve controller designed for automatic operation that was being operated in the manual mode, which the licensee did not have in the operator work-around or operator challenge program. The licensee stated its intention to reevaluate the operating practice for the valve. (Section O1.3)
The preparation and movement of fuel in Unit 2 included timely completion of work
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activities, in depth reviews and approvals by senior licensee management, thorough training of fuel handling personnel, and significant oversight by the Nuclear Oversight organization. These preparations resulted in fuel moves being completed in a safe and efficient manner. (Section O1.4)
The inspectors identified discrepancies on main control room panel indications on both
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Unit 1 and Unit 2. In addition, the inspectors found a Unit 2 main control panel switch with an out-of-service card affixed which did not have a label indicating switch position.
Although control room indicators were operating correctly and measured parameters were within the range of acceptable values, operators continued to accept parameters indicating outside the green band with some indicating in the red band. (Section O2.1)
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Maintenance The Division ll and Division 111 emergency core cooling system integrated response time
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tests were completed satisfactorily in accordance with plant procedures and in conformance with Technical Specifications. (Section M1.1)
During engineering safety feature system walk-downs, the inspectors identified that
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poor maintenance practices and inadequate cleanup of the Unit 2 'B'fC' residual heat removal and high pressure core spray corner rooms resulted in several housekeeping deficiencies. The cumulative impact of these items caused the inspectors to question the operability of the 'B'/C' residual heat removal systems. No safety significance existed as fuel was not yet loaded in the Unit 2 reactor. The licensee stated that programs were in place to ensure room cleanliness prior to Unit 2 fuel load.
(Section M2.1)
The licensee identified several maintenance program weaknesses during its
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investigation into the repetitive failures of a safety-related transformer supplying control power to the primary containment isolation air assisted check valves. The investigation performed to identify the cause of the repetitive failure was thorough. The licensee formulated acceptable plans to correct identified weaknesses and incorporated the plans into its corrective action program. (Section M4.1)
Encineerina The engineering department's response to indications of a leaking fuel rod was timely,
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deliberate, and appeared appropriate. The licensee determined that a fuel clad leak occurred and initiated actions in accordance with plant procedures. The inspectors reviewed a preliminary plan formulated by the station reactor engineer to minimize the impact of the event. The plan appeared acceptable. (Section E2.1)
Plant Suocort Radiation protection and chemistry personnel provided prompt and effective support to
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operations shift personnel subsequent to the licensee's discovery of a potential fuel leak in the Unit 1 reactor. (Section R1.2)
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Report Details Summary of Plant Status During this inspection period, the licensee operated Unit 1 at or near full power for the entire period. Near the end of the period, Unit 1 experienced a fuelleak resulting in additional monitoring. Unit 2 remained shutdown with all fuel removed from the reactor until March 25,1999. Following completion of outage activities, surveillance tests, and management reviews, operators commenced loading fuel in the Unit 2 reactor. The licensee completed loading fuel on March 30,1999.
l. Operations
Conduct of Operations 01.1 General Observations a.
Inspection Scope (71707)
The inspectors evaluated operations personnel performance while attending operations department shift briefings, monitoring control room activities, reviewing daily logs, interviewing operations personnel regarding plant status, and monitoring fuelload activities on Unit 2. In addition, the inspectors observed the licensee's performance on March 25,1999, when Unit 1 experienced a fuel element leak. The inspectors reviewed the following procedures:
LOA-RR-101," Unit 1, Reactor Recirculation System Abnormal," Revision 2
LOP-CD-12," Establishing Condenser Vacuum While Shutdown," Revision 3
LAP-100-11,"LaSalle County Station Surveillance Program," Revision 17
b.
Observations and Findinas in general, the inspectors observed that operators were knowledgeable of plant and equipment status, operated equipment in accordance with approved procedures, monitored panels, and effectively communicated operationalinformation. Also, operations personnel responded well to Unit 1 equipment malfunctions:
On March 19,1999, the Unit 1 'B' reactor recirculation flow control valve, while
controlling on the rotational variable differential transformer (RVDT), started cycling and decreasing valve position. The operators locked up the 'B' flow control valve. Reactor power decreased from 100 percent to 94 percent due to the decrease in reactor recirculation flow. The operators implemented LOA-RR-101 and entered Technical Specification (TS) Limiting Condition of
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Operation (LCO) 3.4.1.3, due to unbalanced reactor recirculation flows. The i
operators switched from the RVDT to the linear variable differential transformer I
(LVDT) and restarted subloop 2 of the 'B' reactor recirculation hydraulic power unit. Following verification that the LVDT was operating properly, the operators
unlocked the flow control valve and slowly increased 'B' reactor recirculation loop J
flow, returning Unit 1 to full power.
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The failure of the Unit 1 feed water check valve electrical voltage regulating
transformer required the operators to enter a 4-hour TS shutdown LCO for the inoperability of two primary containment isolation valves. Following corrective maintenance, the operators declared the valves operable and exited the LCO.
However, the operators were required to reenter the LCO because the replacement of the transformer was not performed in accordance with the vendor manual instructions; the incorrect number of capacitors were wired in the transformer circuitry. Operations personnel made the appropriate operability determinations and adhered to the TS requirements. Failure of the maintenance personnel to correctly install the transformer resulted in an unnecessary challenge to operations personnel. (Section M4.1)
On March 25,1999, operators responded to plant indications and alarms which
indicated a fuel leak on Unit 1. The operators informed the Nuclear Engineering, Radiation Protection, and Chemistry departments of the fuelleak.
(Sections E2.1 and R1.1)
The inspectors noted severalinstances where operators accepted housekeeping, material condition, and procedure deficiencies.
The inspectors identified several housekeeping issues in the 'B'/'C' residual heat
removal (RHR) corner room following the 'B'/C' residual heat removal systems being declared operable. The inspectors questioned system operability due to internal flooding concerns. The inspectors determined that operations management had not been involved in the system operability walk-down, even though the systems had not been operable for over 2 years and significant work had been performed in the room. (Section M2.1)
The inspectors identified that action requests had not been initiated to repair
inaccurate local dial position indicators on motor operated valves in the RHR corner rooms. Several operators had been in the corner rooms and, in one instance, an operator had attached an out of service card to the valve specifying that the valve be closed and the local dial position indicator indicated full open.
(Section M2.1)
On March 30,1999, the operators were breaking condenser vacuum in
accordance with LOP-CD-12. The operators were aware that a problem existed with the ability of the turbine building sumps to contain all the water following the breaking of condenser vacuum. To resolve the sump problem, operators had incorporated steps in LOP-CD-12 requiring pumping down the sumps prior to breaking vacuum. Then, operators were directed to immediately start the sump pumps when water entered the sump. On this occasion, these actions failed to maintain water in the sump and resulted in an area of the turbine building basement becoming contaminated.
l The operational design of the control switch for the high pressure core spray
(HPCS) diesel generator cooling water pump had resulted in the unexpected trip of the pump. This deficiency haa been accepted by operations without administrative controls in place to protect the equipment. Specifically, there were no procedure cautions or caution cards that warned the operators of the potential for pump damage from incorrect operation of the control switch. While operator I
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training had been performed, the inspectors determined that some licensed control room operators were not familiar with the problem. (Section O1.4)
The reactor feed water pump minimum flow control valves, designed to ba
operated in automatic, were being operated in manual. The operators accepted this condition as a normal operating practice. The operator work-arobnd review board was not critical of the condition and failed to identify the condkion as an operator work-around even though it met the exact example pwided in support of the work-around definition. (Section 01.3)
Several control room indications were often out of the normal indicated green
band and many were in the red marked portion of the indicator. (Section O2.1)
The inspectors questioned the Unit 2 reactor operator regarding inconsistencies
in the source range monitoring (SRM) instrument readings a few hours prior to fuelload. The reactor operator was not knowledgeable of the discrepancy and did not investigate the reason for the discrepancy following the discussion with the inspectors. When questioned, the Unit Supervisor indicated the difference in the readings was due to a neutron source stored in the vessel following SRM testing. Twenty minutes following the inspectors leaving the control room, licenwe senior management identified the knowledge deficiency and counseled operations management on expectations regarding control board awareness.
While these items indicated that operators accepted equipment in degraded status, they also indicated that previously identified problems with the ability of first line supervisors to provide adequate oversight have continued. In the case of the SRM, the Unit Supervisor was aware of the source being installed, but had not informed the reactor operators of the source. The inspectors noted that where senior management has provided direct oversight, the licensee's expectations were being effectively implemented.
During a review of the licensee's response to the failure of Unit 1 RHR service water keepfill check valves, the inspectors determined that the Shift Manager declared the check valves operable without requiring an engineering evaluation be completed. On March 18,1999, the operators completed the check valve reverse flow test and determined that the acceptance criteria which required no back leakage could not be met. The operators initiated a problem identification form (PlF), which indicated the valves each leaked.5 to 1 gpm. Following discussions with the system engineer, the Shift Manager determined that a procedure change was required to allow for some leakage in the acceptance criteria. The Shift Manager directed a procedure change request be initiated, and declared the valves operable. However, the PIF generated by the Shift Manager did not require an engineering evaluation of the surveillance procedure as required by LAP 100-11. The licensee's failure to follow the station surveillance procedure is a violation of 10 CFR Part 50, Appendix B, Criterion V (50-373/99002-01(DRP). This Severity Level IV Violation is being treated as a
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Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. The licensee entered the surveillance evaluation into the corrective action tracking program (PIF number L1999-01434). Also, a degraded equipment log entry was not initiated as recommended by the procedure to track the degraded check valves until the evaluation was completed. In addition, the event screening committee did not identify the need for
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the engineering evaluation during the initial review of the PIF and closed the PlF to the procedure change request.
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While the support provided to operations department was acceptable, some problems did exist. For example, during the operations pre-shift brief following the Unit 1 fuel leak, the Shift Manager requested the radiation protection technician at the brief to status the operators on changes in plant radiation levels. The technician was not aware of the fuelleak or of any changed radiological conditions. The Shift Manager briefed the crew on radiological conditions. The Shift Manager did not challenge the technician on attending the brief unprepared to support operations department even though the most recent operations significant event was on poor radiological practices.
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Conclusions in general, the inspectors observed the continued good performance of operators on Unit 1 and timely and safe completion of the Unit 2 fuelload. The operators' response
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to events on Unit 1 including failure of the 'B' reactor recirculation flow control valve RVDT controller and the fuel element leak was safe and in accordance with procedures.
However, in some instances, operations personnel were willing to accept degraded equipment status or operating practices and less than expected levels of support from other organizations.
01.2 Restart Reviews a.
Insoection Scoce (71707)
The inspectors observed meetings of the Restart issues Review Committee and the Plant Operations Review Committee (PORC). In addition, the inspectors observed portions of the System Readiness Review process including a review of the supporting documentation.
b.
Obsentations and Findinos Licensee management conducted comprehensive reviews of the station's readiness to reload the reactor core on Unit 2. The Restart issues Review Committee and PORC reviewed the departmental readiness to support fuelload, the status of the systems required for fuel load, the mode change checklists, results of the integrated Operations Performance Reviews, and other specific issues related to equipment problems. The committees conducted thorough and structured reviews to assess the readiness of the station to support the fuelload. Licensee management thoroughly questioned the plant staff who made presentations to the committees. Based on the reviews, the committees concluded that issues were appropriately addressed and Unit 2 personnel we.a ready to reload the reactor core, in addition, the licensee's Nuclear Oversight organization addressed reviews of PIFs, open corrective actions, and other items such as ongoing investigations, and concluded that Unit 2 was ready for fuel load.
The licensee System Readiness Review process included a review of all action items associated with each system. The review included an examination of relevant work requests, surveillances, licensee event reports, vendor and NRC information notices, and items in the corrective action system database. System engineers presented the results of the system reviews to members of senior station management from each
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department. The inspectors found the documentation and presentation of systems to be thorough and well prepared. The level of station management participation in the
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process reflected the high degree of importance the licensee placed on the reviews.
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. Conclusions i
The licensee's Restart issues Review Committee and PORC meetings were structured and comprehensive. Licensee management on the committees exhibited a questioning attitude and ensured that Unit 2 was ready to load fuel. Detailed system readiness reviews ensured that station management was aware of issues relevant to each system
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in the process, and the level of senior station management participation in the process I
indicated the high priority the licensee placed in the process, j
01.3 Review of Restart Plan Items a.
Insoection Scope (71707)
The inspectors reviewed the licensee's restart plan items regarding operator work-arounds (OWAs), temporary modifications (TMODs), and system readiness reviews, l
and verified the implementation of each plan item. The inspectors evaluated the impact f
of the OWAs and TMODs that the licensee did not have scheduled for resolution prior to the restart of Unit 2. As part of the evaluation, the inspectors reviewed the following licensee procedures:
LaSalle Administrative Procedure (LAP)-200-3 Section 21, " Conduct of
Operations - Operator Challenges," Revision 36 Common Work Pract;';s Instruction (CWPl)-NSP-OP-1-3, " Operator Work-
Around Program," Revision 0 b.
Observations and Findinas The licensee implemented its restart action plan items regarding OWAs. Restart plan items included developing a plan for the resolution of each Unit 2 OWA prior to startup.
Three OWA's required startup testing prior to final closure, and the inspectors verified that the required testing was appropriate and included in the integrated Unit 2 restart schedule. The inspectors considered the five OWA's not scheduled for completion as part of the Unit 2 restart effort to be minor and noted that the licensee had plans in place for the permanent resolution following the restart of Unit 2.
As part of the OWA review, the inspectors identified that the reactor feed water pump minimum flow control valve, designed to operate in automatic, was being operated in manual on Unit 1. Operations personnel stated the reason the valve was operated in manual was due to the historically poor performance in the automatic mode of operation of the controller. Although the operation of the valve in manual met the licensee's definition of an operator challenge as defined in LAP-200-3, the station work-around board decided not to include it in the OWA or operator challenge program. Senior station management indicated to the inspectors that design and maintenance issues regarding the automatic mode of the controller had been resolved and intended to reevaluate whether the operators would continue to operate the valve in manual mode.
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The inspectors found acceptable the licensee's restart action plans regarding the removal of TMODs installed to support the Unit 2 refueling cutage. The inspectors reviewed the status of the licensee's resolution of other Unit 2 TMODs and found them to be progressing according to the Unit 2 recovery schedule. In addition, the inspectors considered the impact of the TMODs installed in Unit 2 which would not be removed prior to the Unit 2 restart to be minor and found the licensee's plans for permanent resolution of the TMODs acceptable.
The inspectors also reviewed the licensee's restart plan item requiring the development of a schedule for Unit 2 system readiness reviews. The inspectors found that the reviews were being performed according to the licensee's schedule and would be completed prior to system turnover to the operations departrnent. The inspectors'
assessment of the conduct of the system readiness reviews is discussed in Section O1.2.
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Conclusions The license effectively implemented its restart action plans regarding OWAs, TMODs and system readiness reviews. The inspectors identified a valve controller designed for automatic operation that was being operated in the manual mode, which the licensee did not have in the OWA or operator challenge program. The licensee stated its intention to reevaluate the operating practice for the valve.
O1.4 Preparation and Comoletion of Irradiated Fuel Movements in Unit 2 a.
Inspection Scoce (71707)
The inspectors reviewed the fuel handler training material and observed job performance measures conducted using the Unit 2 refueling bridge. Also, the inspectors reviewed procedures controlling fuel movement activities and observed irradiated fuel moves and core refueling activities from the refueling bridge and Unit 2 control room. Additionally, the inspectors observed performance of the bridge following design change packages (DCPs) implemented during the outage. Documents reviewed included:
LAP-1200-14, " Unit Fuel Load Departmental Responsibility Checklist,"
Revision 6 LOS-AA-03," Reactor Mode Changes," Revision 9
LaSalle initial License Training System Description, Module Chapter 67, " Fuel
Handling System," Revision 00 LaSalle Limited Senior Reactor Operator - Continuing Training, Module
Technical Specifications," Technical Specification Section 3/4.9 Refueling Operations," Revision 00 LaSalle initial License Training system Description, Module Chapter 02, " Reactor
Pressure Vessel and Internals (RPV)," Revision 00 LaSa!!o County Station - Job Performance Measure P-FH-05, " Place a Fuel
Assembly in a Fuel Pool Rack from the Normal Up Position," Revision 2 Prior to fuel movements commencing, the inspectors reviewed several items including the degraded equipment log, Technical Specifications (TS), and Updated Final Safety Analysis Report (UFSAR) to ensure that Unit 2 and common equipment necessary to
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support fuel movements was operable. In addition, the inspectors verified that the licensed senior operators reactivated their license under the direction of the SROs prior to directing fuel movements. The inspectors also observed portion of the fuel load activities.
b.
Observations and Findinas Trainina of Fuel Handfina Personnel On March 10,1999, the inspectors observed job performance measures administered to fuel handlers on the refuel bridge by a senior reactor operator with a license limited to fuel handling, in addition, the inspectors reviewed several lesson plans pertaining to moving irradiated fuel assemblies. The lesson plans were accurate and discussed the fuel moving equipment operation including recent design changes. The operators were knowledgeable of equipment changes and operation.
Reauirements for Fuel Movements One item identified was a degraded equipment log entry for the high pressure core spray (HPCS) diesel generator cooling water pump. The pump trips unexpectedly if the control switch is taken to start to match the switch target following an automatic start and the removal of the automatic start signals. The unexpected pump trip resulted in Licensee Event Report 94-011-00, which was closed based on identified corrective actions. However, the inspectors determined that information regarding the potential for a pump trip when the switch target was matched was not incorporated into procedures and a caution tag regarding the switch operation had been removed from the operating switch. Also, the inspectors determined that not all the Nuclear Station Operators (NSOs) were aware of the unexpected tripping condition.
The systems necessary for fuel movement as required by the TS were delineated in LAP-1200-14 and LOS-AA-03, with one minor concern. Technical Specification 3.8.3.3 requires thermal overload protection to be bypassed by an operable bypass device internal with the motor starter on valves which are required to be operable. However, this TS was not identified on the LOS-AA-03 checklists applicable to fuel moves. The Unit 2 Unit Supervisor was informed of the administrative deficiency. The deficiency was corrected prior to fuel moves. In addition, Nuclear Oversight identified several administrative fuel handling procedural deficiencies that required resolution.
Fuel Movement in the Unit 2 Fuel Pool in Preoaration for Reactor Core Reload The operators inspected completed fuel movements in the Unit 2 fuel pool in preparation for Unit 2 reactor core fuel load. Nuclear Oversight identified that operators did not proactively terminate fuel movements when squeaking noises were heard from the refueling bridge. A refueling bridge crane wheel failed and the fuel movement stopped while the wheel was replaced.
Unit 2 Core Reload and Verification On March 25,1999, operators commenced the Unit 2 core reload. The inspectors observed portions of the reload and noted that the fuel handlers followed the core reload procedure, implemented effective communication techniques, and remained attentive
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during the repetitive task. Nuclear Oversight monitored approximately 50 percent of the core reload. No significant issues were identified during the reload. However, Nuclear Oversight did identify several minor operating and radiological protection issues which were communicated to management. The reload was completed and verified accurate on March 30,1999.
c.
Conclusions The preparation and movement of fuel in Unit 2 included timely completion of work activities, in depth reviews and approvals by senior licensee management, thorough
training of fuel handling personnel, and significant oversight by the Nuclear Oversight organization. These preparations resulted in fuel moves being completed in a safe and efficient manner.
Operational Status of Facilities and Equipment
O2.1 Deficiencies in Main Control Board Indications and Controls i
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Inspection Scope (71707)
The inspectors reviewed the Unit 1 and Unit 2 main control room panel distractions and discussed identified discrepancies with the licensed operators on shift in the control room.
b.
Observations and Findinas inspection Repor! 50-373/99001; 50-374/99001 identified that several main control board indicators operated outside the normal control band (green band). Additional instances of control room indicators on the main control room control boards were identified by the inspectors which indicated that the measured parameter was operating in the red band. These included the Unit 1 electro-hydraulic control pressure set, and main generator electric output. Operators continued to accept indications outside the green band as normal. Actual values of the measured parameters were acceptable. In addition, the inspectors observed the reactor feed flow / steam flow recorder and indicators indicated a 0.5E6 lbm/hr difference between feed and steam flow. The operators were aware of the difference and directed the inspectors to the operator logs which allow a maximum of 0.5E6 lbm/hr difference.
On March 25,1999, during control room observations, the inspectors identified that the Unit 2 Nuclear Station Operator (NSO) was not aware that a neutron source was installed in the Unit 2 vessel. The 'D' source range monitor (SRM) indicated 6 cpm when the other SRMs indicated no counts. The NSO was not able to explain why the indication was different. The inspectcrs determined that a neutron source had been installed to support the performance of discriminator plots on the nuclear instruments.
Also, the inspectors determined that, while the Unit Supervisor was aware that the source was installed in the Unit 1 vessel, the Unit Supervisor had not communicated the presence of the source to the NSO or the shift technical advisor.
The inspectors found that the Unit 2 residual heat removal (RHR) discharge to main condenser valve handswitch did not have a position label affixed. An out-of-service card
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was affixed to the switch and the indicating lights were extinguished. The operators considered this acceptable since the switch pointed to the correct valve position light.
The inspectors discussed the lack of the switch position label on a main control room
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panel with operations management personnel. Operations management personnel
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indicated that the lack of labeling and the operators' acceptance of the condition, did not meet station operations department standards. Operations management initiated actions to correct the condition.
c.
Conclusions The inspectors identified discrepancies on main control room panel indications on both Unit 1 and Unit 2. In addition, the inspectors found a Unit 2 main control panel switch with an out-of-service card affixed which did not have a label indicating switch position.
Although control room indicators were operating correctly and measured parameters were within the range of acceptable values, operators continued to accept parameters indicating outside the green band with some indicating in the red band.
Operations Organization and Administration O6.1 Institute of Nuclear Power Ooerations (INPO) Review The inspectors reviewed the March 17,1999, report documenting the evaluation of LaSalle Station completed by INPO. The INPO evaluation did not identify any additional safety-significant or risk-significant issues not previously identified by the NRC or the licensee.
' Quality Assurance in Operations O7.1 Intearated Operator Performance Review (IOPR) Assessment a.
Inspection Scooe (71707)
The inspectors observed the licensee's self-evaluation of the Division ll and 111 emergency core cooling system (ECCS) response time tests by plant management as i
part of the licensee's IOPR process. In addition, the inspectors reviewed the IOPR observation package and the completed performance summaries.
b.
Qhservations and Findinas Members of the IOPR team attended the operator briefing prior to the Division 11 and lil response time tests and determined that the briefings were adequate. The IOPR team identified a significant number of observations including most of the operator i
performance deficiencies that the inspectors identified. The observations were evaluated against predetermined acceptance criteria defining " good" operations. The IOPR team determined that the operators and plant equipment preformed well with some exceptions.
Although the IOPR process yielded valuable operational ir. sights the first scheduled review did not meet management expectations because the intention to use the scorecard methodology was not communicated to all members of the IOPR evaluation team, in addition, the nuclear oversight organization identified that the issuance of the
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IOPR for the Division 111 response time test was not timely and would not allow
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adequate time for incorporation of lessons learned prior to the division ll response time test.
c.
Conclusions The IOPRs performed for the Division ll and 111 response time tests were critical of plant personnel performance and provided an adequate assessment of the integrated plant performance during those plant evolutions.
Miscellaneous Operations issues (92700)
O8.1 Previousiv Identified Violations The Severity Level IV violation listed below was issued in a Notice of Violation prior to the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because the violation would have been treated as a Non-Cited Violations in accordance with Appendix C, it is being closed out in this report.
Violation number 50-373/97015-01: This violation is in the licensee's corrective action program as PlF L1997-05559.
08.2 (Closed) Unresolved item (URll 50-373/98019-02: During an inspection of the Unit 1 drywell on July 22,1998, the inspectors identified a valve that was not appropriately secured. The valve was in the required position with a lock and chain installed.
However, the chain was not properly attached and would allow the valve handle to be manipulated. A similar issue regarding the licensee's locked valve program was addressed in a previous inspection report and the licensee performed an Apparent Cause Evaluation to review the issues related to the locked valve program. From the Apparent Cause Evaluation, the licensee concluded that non-licensed operators required additional training on how to properly install a chain and lock. The inspectors reviewed the Apparent Cause Evaluation and discussed the issue with non-licensed operators and concluded that the licensee's actions were appropriate. This item is closed.
II. Maintenance M1 Conduct of Maintenance M1.1 Division ll and lil Emeroency Core Coolina Svstem Response Time Testina a.
Inspection Scope (61726)
The inspecters observed the preparation and conduct of the Division ll and lli ECCS integrated response time tests in addition, the inspectors reviewed supporting test documentation, specifically, LaSalle Technical Surveillance (LTS) 500-210 (211), " Unit 2 Integrated Division ll (111) Response Time Surveillance," Revision 6 (7), evaluated test results, and assessed the extent of rework identified during the divisional testing program.
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b.
Observations and Findinas On March 9,1999, the inspectors observed the pre-job heightened level of awareness (HLA) briefing and performance of LTS-500-210, " Unit 2 Integrated Division 11 Response Time Surveillance," Revision 6. The operators thoroughly defined the responsibilities of test support personnel and discussed all aspects of the test during the HLA brief.
Additional control room operators monitored the testing activities while the operators assigned to the units maintained oversight responsibility. The engineers directed the test and provided initial evaluation of the test results. Nuclear Oversight and lOPR personnel were present for the HLA brief and observed the test. Plant equipment performed as designed with two exceptions.
The power supply to the 'D' control room ventilation radiation monitor failed to
retum to service when bus voltage was restored during the loss of off-site power in conjunction with the loss of coolant accident portion of the test. The power supply had performed satisfactorily during earlier portions of the test. Power was ultimately restored to the 'D' channel by removing and reinstalling the power supply fuses. This problem had been experienced in July of 1998 and surge protectors were installed to eliminate the high current condition. The licensee implemented corrective actions to determine the cause of the failure.
The 2C RHR pump did not achieve the initial flow rate of 7600-8000 gpm which
was indicated in Step E.3.18 of the procedure. The pump did attain the required safety-related flow of 7200 gpm. Engineering personnel evaluated that the 7400-7500 gpm achieved was acceptable and initiated a procedure change.
c.
Conclusions The Division ll and Division lll ECCS integrated response time tests were completed satisfactorily in accordance with plant procedures and in conformance with Technical Specifications.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Enaineered Safetv Feature System Walk Downs a.
Inspection Scone (62707)
The inspectors walked down accessible portions of the following essential safety feature systems.
emergency diesel generators (Units 1 and 2)
i residual heat removal (RHR) (Units 1 and 2)
high pressure core spray (HPCS) (Units 1 and 2)
Each system was chosen based on the system's inclusion on the LaSalle Probabilistic Risk Assessment listing of key plant equipment and the relative values of the system's risk achievement worth. In addition, the inspectors reviewed the following licensee procedures.
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LOP-AA-04," Operation of Valves," Revision 14
LOS-HP-Q2, " Unit 1 HPCS Valve in service Test for Operating, Startup and Hot
Shutdown Conditions," Revision 9
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b.
Observations and Findinos f
On Unit 1, the inspectors did not find any potential nonconformances which would render the equipment inoperable and determined material condition was acceptable, i
However, on Unit 2 the inspectors identified minor material condition deficiencies and housekeeping discrepancies in the RHR corner rooms which could have rendered the
'B'/C' RHR systcms inoperable during intemal flooding. The items were brought to the licensee's attention and were either corrected or entered in the work request program.
However, the licensee did not initiate a PlF to enter the issues into the corrective action program. Specifically, on March 12,1999, the inspectors peiformed an inspection of the Unit 2 'B'fC' RHR pump and heat exchanger corner rooms. The 'B'/C' RHR systems had been declared operable on March 10, following a 2-year outage. The inspectors identified significant debris from maintenance and painting activities on all levels (i.e., loose tape, velcro straps, paint chips, loose insulation, rags, painters tarps and lead blanketing). The lead blanketing was inappropriately stored on the 'C' RHR pump
' minimum flow line piping. The UFSAR Section 3.4, " Water Level (Flood) Design,"
indicated this was a flood control area and that drains and sump pumps were provided for protection against internal flooding. Additionally, signs posted in the area indicated that the floor should be kept free from debris. However, this housekeeping concern was of minimal safety significance as Unit 2 was defueled. The licensee stated that programs were in place to ensure room cleanliness prior to Unit 2 fuel load.
During further review of the housekeeping deficiencies, the inspectors determined that operators had declared the 'B'/C' RHR systems operable for fuel load without the systems being walked down by operations management. The Shift Manager tasked
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with detarmining system readiness for operability requested that an operations field I
supervisor inspect the areas. However, the field supervisor assigned the walk-down to an equipment attendant. The equipment attendant forwarded the list of items identified
- to the outage control center. Personnel in the outage control center were not able to I
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locate the list and had not resolved the issues. In the entry describing 'B'fC' RHR system operability, the unit logs indicated that a walk-down had been performed and housekeeping issues identified and forwarded to outage control center for resolution.
Although several non-licensed operators had been in the room, these operators had not informed operations management of the room status or initiated actions to have the rooms cleaned. As part of the corrective actions to the 'B'/C' RHR comer room issues, operations management issued a Daily Order which required that the Shift Manager perform a walk-down of all systems being declared operable to ensure that management expectations were being met.
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The inspectors toured the Unit 2 'A' RHR comer room and identified several minor housekeeping issues. In addition, the inspectors identified that local valve position indication dials on safety-related motor operated valves in the RHR corner rooms did not meet accuracy requirements specified in LOP-AA-04. The inspectors informed the licensee's motor operated valve engineer who stated his intention to initiate action requests to adjust the position indicators to within the required tolerance.
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The licensee declared the Unit 2 HPCS system operable during the inspection period following an extended lay-up of the system. The inspectors verified that the work completed on the HPCS system was sufficient to support the licensee's operability determination. Furthermore, the inspectors verified that the Unit 2 HPCS system configuration was in accordance with design documentation. The inspectors did not identify any nonconformances which would render HPCS equipment inoperable and the overall material condition of the system appeared acceptable. However, the inspectors found the junction box connected to the cable from the HPCS motor thermocouple was not adequately supported. The system engineer stated that the motor thermocouple did not perform a safety-related function. In addition, while performing a walk-down of the Unit 2 HPCS system, the inspectors identified numerous housekeeping deficiencies such as construction debris left in a safety-related cable tray, and painters' equipment left behind HPCS room ventilation ductwork. The discrepancies were brought the licensee's attention and the licensee initiated actions to correct each identified item.
Some of the construction debris was identified by the licensee as being left over from initial construction.
The inspectors noted that the Unit 1 and Unit 2 HPCS pump discharge relief valve piping configuration differed. The Unit 1 relief valve discharged to piping routed to a sump in the HPCS room. The Unit 2 relief valve did not have piping attached to the discharge and would discharge directly into the ceiling area of the room in the vicinity of the pump motor. The differing configurations between units had previously been identified by the licensee in 1996 and an engineering request had been generated and approved to attach discharge piping to the Unit 2 valve. However, the engineering request had been canceled in 1998 citing the fact that the relief was installed for protection against thermal expansion of an isolated section of HPCS piping. Therefore, only a small quantity of water would be discharged upon relieving and thus would not pose a personnel safety hazard. The inspectors reviewed the UFSAR discussion on ECCS piping overpressurization and identified no concerns.
During the HPCS procedure review, the inspectors identified that Step 5.c of LOS-HP-02, directed the operators to isolate a!! HPCS water leg pump suction sources without stopping the pump. This step was preceded by a note to minimize the time that the pump suction was isolated to prevent damaging the pump. The licensee indicated that the procedure would be revised to stop the pump prior to isolating all suction sources.
C.
Conclusions Overall, the material condition of both Units and general housekeeping in Unit 1 appeared acceptable. However, poor maintenance practices and cleanup of the Unit 2
'B'/'C' RHR and HPCS corner rooms resulted in several housekeeping deficiencies. The cumulative impact of these items caused the inspectors to question the operability of the
'B'/'C' RHR systems. The licensee stated that programs were in place to ensure room cleanliness prior to Unit 2 fuel load.
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M4 Maintenance Staff Knowledge and Performance M4.1 Work Analysts Did Not identifv Wirina Chanaes Necessary for Reolacement of Voltaae Reaulatina Transformer a.
Insoection Scoce (62707)
The inspectors observed portions of the troubleshooting and maintenance following the March 15,1999, failure of the voltage regulating transformer which supplied control ud indication power to the two parallel primary containment air assisted feed water injection check valves. In addition, the inspectors interviewed maintenance and engineering personnel and members of the root cause team assigned to investigate the event.
b.
Observations and Findinos On March 15,1999, Unit 1 control room operators observed that the valve position indication for the feed water air assisted injection check valves was extinguished on the main control room panel. The check valves were part of the primary containment isolation boundary and were safety-related. The operators declared the check valves inoperable and entered the appropriate TS LCO. Subsequent investigation by the licensee revealed that the circuit breaker to the regulating transformer supplying the control and indication power for the check valves had tripped. Licensee personnel quickly recognized that the safety-related transformer assembly had previously failed and had been replaced in January 1999.
The failure analysis had not been completed from the January 1999 failure. Therefore, the results could not be used to assist in the troubleshooting efforts for the March 1999 failure. Maintenance personnel completed a like-for-like replacement of the transformer assembly. Following the transformer replacement and measurement of the output voltages, the check valves were declared operable and the TS LCO was exited.
The licensee's engineering personnel developed a troubleshooting plan to determine the cause of the repetitive failure of the transformer. Licensee engineers identified that the capacitor wiring associated with the January 1999 replacement of the transformer assembly had not been modified in accordance with the vendor manual prior to installation and resulted in the premature thermal degradation and failure of the
- transformer. In addition, licensee personnel recognized that the March transformer assembly capacitor wiring also had not been properly modified. The licensee removed the transformer from service and corrected the transformer capacitor wiring.
The licensee's investigation revealed several underlying causes for the event.
Programmatic weakness identified included the following.
Insufficient follow-up and field verification of work performed was allowed for an
"A" priority work request. An "A" priority work request allows maintenance personnel to commence field work prior to completion of the work package.
Insufficient investigation of the original transformer failure and failure to track the
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The treatment of the transformer replacement on both occasions as a like-for-like without recognizing that the assembly as received from the vendor required modification.
The inspectors reviewed the licensee's corrective actions as stated in the preliminary investigation report. The actions appeared adequate to address the identified root causes. The licensee's final investigation was due to be complete in April 1999, and was in the licensee's corrective action program.
c.
Conclusions
The licensee identified several maintenance program weaknesses during its investigation into the repetitive failures of a safety-related transformer supplying control
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power to the primary containment isolation air assisted check valves. The investigation j
performed to identify the cause of the repetitive failure was thorough. The licensee j
formulated acceptable plans to correct identified weaknesses and incorporated the
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plans into its corrective action program.
Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Promot Resoonse by Reactor Enaineerina to Unit 1 Fuel Rod Leak a.
Insoection Scope (37551)
On March 25,1999, the inspectors observed the response of reactor engineering personnel when notified by operations shift personnel of a potential leaking fuel rod on
. Unit 1. In addition, the inspectors reviewed engineering personnel's implementation of the licensee's requirements delineated in Nuclear Station Procedure (NSP)-ER-1001,
" Failed Fuel Response Process Description," Revision 0.
b.
Observations and Findinas Reactor engineering personnel responded in an expeditious manner after receiving notification from operations shift personnel of a potential leaking fuel rod on Unit 1. The station reactor engineer was present in the main control room and performed reviews of the radiochemistry data and other associated parameters in order to determine if fuel clad integrity had been compromised and which action level response was warranted in accordance with NSP-ER-1001. The engineer concluded that fuel clad integrity had been compromised and made an initial action level determination based on the : Activity J
of the sum-of-the-six noble gases. The baseline coolant noble gas activity was 450 microCurles per second. Initial radiochemistry analysis indicated a peak noble gas activity of 6200 microCuries per second and the engineer appropriately determined that i
action level 1 had been entered. Subsequent radiochemistry analysis revealed a dose J
equivalent iodine activity of 0.01 microCuries per gram and the engineer concurred with l
the Shift Manager's recommendation to enter action level 2.
The station reactor engineer ensured the required notifications were made in accordance with NSP-ER-1001 and initiated an assessment of the fuel performance data in conjunction with the corporate fuel reliability engineer in addition, the two
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engineers, with recommendations from the fuel vendor, began developing a plan for reactor operation to minimize the potential for additional loss of cladding integrity and to mitigate the consequences of the existing failure on plant operation.
c.
Conclusions The licensee's engineering response to indications of a leaking fuel rod was timely, deliberate, and appeared appropriate. The licensee determined that a fuel clad leak occurred and initiated actions in accordance with plant procedures. The inspectors reviewed a preliminary plan formulated by the station reactor engineer to minimize the impact of the event. The plan appeared acceptable.
E8 Miscellaneous Engineering issues (92902)
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i E8.1 The Severity Level IV violation listed below was issued in a Notice of Violation prior to l
the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because the violation would have been treated as a Non-Cited Violation in accordance with Appendix C, it is being closed out in this report.
Violation number 50-373/374-96016-02: This violation is in the licensee's corrective
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action program as Nuclear Tracking System item numbers 373-100-96-1602.01NOV through 373-100-96-1602.08NOV.
IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General in general, actions taken by the licensee were adequate to protect personnel from radiological hazards. However, the licensee continued to experience problems with personnel moving high radiation area boundary signs. Late in the inspection period, the Radiation Protection (RP) department implemented posting additional signs requiring each high radiation area access door to have two signs, one sign on the door and one on the doorjam. Access to high radiation areas other than through doors were protected by alarming swing gates whenever possible.
In addition, RP implemented more rigorous contamination control practices to limit the spread of contamination between contaminated work areas and an radiation protection control point. Specifically, radiation protection personnel survey all materials (tools, equipment, work packages, etc.) across all station radiologically contaminated area step-off-pads.
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R1.2 Radiation Protection and Chemistry Personnel Response to Unit 1 Fuel Leah b.
Insoection Scope (71750)
The inspectors observed the response of plant support personnel on idarch 25,1999, when operations shift personnel identified that plant conditions indicated a potential fuel leak in the Unit 1 reactor vessel.
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Observations and Findinas The inspectors observed that RP and chemistry personnel responded in a timely manner following the plant announcement that the offgas building radiological conditions had changed. Station RP personnel effectively performed radiological surveys in the offgas building and other plant areas where dose levels could potentially have changed as a result of a leaking fuel bundle. The RP personnel made appropriate changes to radiological postings after performing surveys. Although the response of RP personnel to the event was acceptable the inspectors noted that at the operations shift turnover briefing the morning following the event, the RP technician at the briefing was not aware of the preceding events and did not know of changes to plant radiological conditions.
The inspectors discussed this with RP management who indicated that it was their expectation the RP technicians attending the shift turnover briefing be familiar with changes to plant radiological conditions so that personnel attending the brief could be updated prior to assuming shift duties.
Station chemistry personnel obtained the coolant samples specified in the plant procedures and provided the appropriate analysis results to operations shift personnel in a prompt manner.
c.
Conclusions
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Radiation protection and chemistry personnel provided prompt and effective support to operations shift personnel subsequent to the licensee's discovery of a potential fuel leak in the Unit 1 reactor.
F8 Miscellaneous Fire Protection issues (92904)
F8.1 The Severity Level IV violation listed below was issued in a Notice of Violation prior to the March 11,1999, implementation of the NRC's new policy for treatment of Severity Level IV violations (Appendix C of the Enforcement Policy). Because the violation would have been treated as a Non-Cited Violation in accordance with Appendix C, it is being closed out in this report.
Violation number 50-373/374-96004-07: This violation is in the licensee's corrective action program as Nuclear Tracking System item number 373-100-96-00407.01.NOV.
V. Management Meetinas X1 Exit Meeting Summary j
The inspectors presented the results of these inspections to licensee management listed below at an exit meeting on March 31,1999. The licensee acknowledged the findings presented.
The inspectors asked the licensee if any materials examined during the inspection should be considered proprietary. The licensee identified none.
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PARTIAL LIST OF PERSONS CONTACTED J
Licensee
- S. Barrett, Maintenance Manager
- J. Benjamin, Site Vice President
- C Berry, Chief of Staff
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D. Bowman, Chemistry Supervisor E. Connell, Design Engineering Supervisor
- D. Farr, Operations Manager
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G. Kaegi, Site Training Manager
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I R. McConnaughay, Shift Operations Superintendent
- J. Meister, Engineering Manager
- T. O'Connor, Plant Manager R. Palmieri, System Engineering Manager
- J. Place, Radiation Protection Manager K. Poling, Work Control Manager
- J. Pollock, Support Engineering Supervisor
- J. Richardson, Human Resources Supervisor
- W. Riffer, O & SA Manager E. Shankle, Support Services Manager
- F. Spangenberg, Regulatory Assurance Manager R. Stachniak, Nuclear Oversight Assessment Manager j
- Present at exit meeting on March 31,1999.
INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events IP 92901:
Followup - Plant Operations IP 92902:
Followup - Maintenance IP 92903:
Followup - Engineering IP 92904:
Followup - Plant Support
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ITEMS OPENED, CLOSED, AND DISCUSSED Opened i
i 50-373/99002-01 NCV Failure to follow Surveillance procedure Qigsed
- 50-373/99002-01 NCV Failure to follow Surveillance procedure 50-373/97015-01 VIO Failure to meet TS Action as required 50-373/374/97016-02 VIO Failure to initiate a PIF and operability assessment of air operated valves 50-373/374/96004-07 VIO Failure to follow procedures for control of hot work Discussed None
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LIST OF ACRONYMS USED C W Pl Common Work Practice Instruction DRP Division of Reactor Projects.
DRS Division of Reactor Safety ECCS Emergency Core Cooling System FRE Fuel Reliability Engineer HPCS High Pressure Core Spray INPO Institute of Nuclear Power IOPR Integrated Operation Performance Review IR
Inspection Report
IFl
Inspection Follow-up Item
LAP
LaSalle Administrative Procedure
LSRO
License Limited to Fuel Handling
LTS
LaSallo Technical Surveillance
Linear Variable Differential Transformer
NSO
Nuclear Station Operator
Nuclear Station Procedure
Operator Work-Arounds
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NRC
Nuclear Regulatory Commission
PlF
Problem Identification Form
Plant Operations Review Committee
NRC Public Document Room
Radiation Protection
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Rotational Variable Differential Transformer
SRE
Station Reactor Engineer
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Source Range Monitor
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TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved item
Violation.
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