IR 05000254/1998009
| ML20236M113 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 07/02/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20236M004 | List: |
| References | |
| 50-254-98-09, 50-254-98-9, 50-265-98-09, 50-265-98-9, NUDOCS 9807130300 | |
| Download: ML20236M113 (36) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION lli Docket Nos.:
50-254;50-265 License Nos.:
50-254/98009(DRP); 50-265/98009(DRP)
Licensee:
Commonwealth Edison Company Facility:
Quad Cities Nuclear Power Station, Units 1 and 2 i
Location:
22710 206th Avenue North Cordova,IL 61242 Dates:
April 1 through May 29,1998 l
Inspectors:
C. Miller, Senior Resident inspector K. Walton, Resident inspector L. Collins, Resident inspector l
l K. Selburg, Resident inspector J. Adams, Resident inspector, Braidwood Nuclear Plant R. Crane, Resident inspector, LaSalle Nuclear Plant J. Hansen, Resident inspector, LaSalle Nuclear Plant
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T. Jones, Operator Licensing i
R. Langstaff, Operator Licensing j
R. Lerch, Project Engineer, Branch 1 D. McNeil, Operator Licensing l
R. Ganser, Illinois Department of Nuclear Safety Approved by:
Mark Ring, Chief Reactor Projects Branch 1 9807130300 900702 PDR ADOCK 05000254 G
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EXECUTIVE SUMMARY Quad Cities Nuclear Power Station, Units 1 and 2 NRC Inspection Report 50-254/98009(DRP); 50-265/98009(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a resident inspection from April 1 to May 29,1998.
Operations Operators carefully controlled Unit 2 startup activities. Operator performance was good
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although the different operating crews exhibited different standards with respect to communications. A number of equipment problems occurred and operators responded appropriately (Section O2.1).
The control rod hydraulic and air systems were in good material condition, and were in
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the appropriate configuration for the current plant conditions (Section O2.2).
The inspectors and licensee both identified a negative trend in out-of-service
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performance. The licensee's evaluation of a failure to protect divers during a pump start was downgraded to an apparent cause evaluation, and the quality of the apparent cause i
evaluation and subsequent corrective action was poor. Operations management did not initially consider the event significant even though personnel safety and system
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r performance could have been adversely affected (Section 04.1).
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An individual operated out-of-service equipment in violation of plant procedures and
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Technical Specifications (TS). The out-of-service hung on the refuel bridge was i
insufficient to ensure the refuel bridge would not move when operation was attempted
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from the bridge control pendant. This event was also significant because the out-of-l l
service was being used as an equivalent method of reactivity controls for interlocks that did not meet Updated Final Safety Analysis Report (UFSAR) requirements (Section 04.2).
Control room operator actions in response to the loss of an offsite power supply were in
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accordance with procedures and were accomplished using both self-check and peer-check techniques (Section M1.1).
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Maintenance Poor quality maintenance resulted in the loss of one of two sources of offsite power. The
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investigation of this event was both timely and thorough. The inspectors also identified that the rework aspects of this event had not been identified by the licensee (Section M1.1).
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Maintenance workers failed to perform steps in an approved procedure and failed to i
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change the procedure prior to continuing the maintenance actions. Maintenance j
t supervision guidance contributed to the conclusion that this violation of TS requirements
was acceptable (Section M1.3).
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e During work on traversing incore probe components in April 1998, instrument
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Maintenance personnel did not comply with the out-of-service program and personnel protection controls. The failure to conduct work on this system in a safe and controlled manner was a violation of out-of-service procedures and TS requirements. Due to certain radiation protection requirements, and due to the low dose rate of the detector at the time of the evolution, there was no substantial potential for a radiological overexposure (Section M1.4).
The licensee was effectively tracking the numerous problems encountered with electrical
circuit breakers, and was repairing these problems in a timely manner (Section M2.1).
Enaineerina Issues involving the need to revise instrument calculations identified in 1991 and 1992
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were not resolved prior to 1998. Some TS related setpoints were determined to have a (
non-conservative margin of error. The Vulnerability Assessment Team report tracking
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item for this issue was closed without apparent justification. This was a violation of j
10 CFR Part 50, Appendix B requirements. Five instances of exceeding TS required j
setpoints for the scram discharge volume were identified by the licensee (Section E1.2).
Equipment problems with emergency diesel generators continued this period. The Unit 1
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emergency diesel generator failed to start on demand during surveillance testing. The cause of the failure was a malfunctioning autostart logic relay. Other problems were identified by the licensee and corrected prior to their affecting diesel operability. The causes of these failures were still under review by the licensee (Section E1.3).
A design change to replace the defective humidifier for the computer room was canceled
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in May 1995. No safety evaluation for this non-conformance with the UFSAR was performed, in violation of 10 CFR 50.59 requirements (Section E8.6).
Plant Support Chemistry and Radiation Protection personnel responded conservatively and quickly to a
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release of radioactive xenon-133 in the chemistry laboratory. No adverse personnel or environmental hazards resulted from this release (Section R4.1).
Good radiological controls were noted during the performance of traversing incore probe
activities. These controls remained in place to provide personnel protection from radiological hazards, even though the out-of-service program projections were not left in place (Section M1.4).
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e4 Report Details Summary of Plant Status Both units remained in cold shutdown until May 23,1998, due to concems with the ability to meet 10 CFR Part 50, Appendix R safe shutdown requirements. On May 22,1998, the NRC completed a review of licensee actions taken to resolve safe shutdown concems and other startup related issues and issued a closure letter to Confirmatory Action Letter Rlll-98-001 which addressed safe shutdown concems. Following final startup preparations, operators commenced startup of the Unit 2 reactor on May 23,1998; the i
turbine generator was synchronized to the electrical grid on May 26,1998.
I 1. Operations
Conduct of Operations O1.1 General Comments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Normal shutdown activities were observed as well as unit startup activities on a 24-hour basis. Licensee oversight of startup activities was extensive, and included 24-hour coverage by management, Quality and Safety Assessment, and offsite representatives.
O2.
Operational Status of Facilities and Equipment O2.1 Unit 2 Startup Observations
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Inspection Scope (71707)
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The inspectors observed Unit 2 startup activities from initial control rod withdrawal i
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through 600 MWe. The inspectors observed activities both in the control room and in the plant. Ma,jor activities reviewed included control rod withdrawal to reactor criticality, high pressure coolant injection system, reactor core isolation cooling system and automatic
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depressurization system testing, main generator synchronization to the grid, and power l
ascension to full power.
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Observations and Findinas Operators commenced reactor startup on May 23,1998. The main generator was synchronized to the grid on May 26,1998. Conduct of startup activities was careful and controlled. Operator performance was good. However, the inspectors noted differences among the operating crews with respect to communication standards. Some crews always used formal communications while other crews were less consistent. Senior management and the Quality and Safety Assessment department provided oversight in the control room. Several equipment problems occurred and delayed startup activities.
In all cases, the problems were appropriately addresscd by the operating crew. Below is
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I a list of the problems which required operator attention during the startup.
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The "B" gland seal system tripped when placed into service.
- The "A" reactor feed pump ventilation fan tripped after being started.
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One Unit 2 power operated relief valve,2-0203-3E, failed the inservice timing test
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upon closure. Engineers performed an evaluation as required by the American Society of Mechanical Engineers (ASME) code and concluded that the valve would perform acceptably if required to operate.
One Unit 2 power operated relief valve,2-0203-3B, exhibited high tailpipe
temperatures, indicative of leakage. Temperatures exceeded the alarm setpoint and stabilized at approximately 235 degrees Fahrenheit with the reactor at full pressure. Engineers evaluated the condition and concluded that temperatures up to 250 degrees were acceptable.
l The reactor core isolation cooling system steam admission valve,2-1302-61,
failed the first inservice test upon closure. The valve closed faster than the lower limit of the test criteria.
l High temperature alarms for the drywell equipment drain sump were received,
although drywell leakage was within TS limits.
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The Transformer 21 (unit auxiliary transformer) to Dus 21 breaker would not close I
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to allow the main generator to supply power to plant equipment. Bus 21 remained powered from the switchyard.
Non-licensed operators identified extraction steam valves that appeared to be in
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the wrong position. A prompt investigation revealed that the discrepancies had
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been previously discovered during completion of valve lineup procedures. The j
startup procedure did not require these valves to be re-positioned. The valves
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were properly positioned and all open issues from valve lineups were reviewed.
While isolating a feedwater heater string to repair a leak at a relief valve threaded
connection, an air leak to the condenser was inadvertently introduced. Operators l
noted increased steam jet air ejector flow and took action before condenser i
vacuum decreased.
The Number 2 combined intercept valve would not reopen after testing.
- Engineers concluded that operation at 100 percent thermal power was allowed because the opposing valve was designed to allow 100 percent steam flow to the low pressure turbine. Repairs were scheduled for after Unit 1 startup.
These problems were sufficiently resolved by the licensee, including repairs and evaluations considering equipment operability and safety, to continue startup in a safe manner.
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Conclusions Operators carefully controlled Unit 2 startup activities. Operator performance was good although the different operating crews exhibited varying communication standards. A number of equipment problems required operator attention, and operators responded appropriately.-
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Inspection Scope (717071'
The inspectors performed detailed inspections of the control rod drive system to independently verify system operability. This included a review of the licensee's system -
line up procedure, system drawings, the Final Safety Analysis Report, and TS.
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Observations and Findinas
. The inspectors identified that the configuration of the control rod drive system was consistent with licensee procedures and drawings. The inspectors determined that accessible valves were in the correct position, power was available to the valves, major system components were appropriately labeled, lubricated, cooled and ventilated, and
. generally free of leakage, and selected instrumentation was appropriately installed. The overall material condition of the system was good. The inspectors identified one leaking scram valve on the control rod drive hydraulic system. The inspectors notified operators of the leak, and observed on subsequent inspections that the leak had been repaired.-
Some minor oil leaks were identified on the control rod drive pumps, however, these were also identified through the licensee's action request system. The inspectors noted that the 2-0301-196 valve (air scram valve) appeared restricted from opening by the adjacent 1828 valve body. The inspectors discussed the valve position with an equipment attendant who identified that the valve was open.
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The inspectors noted that the control rod hydraulic and air systems were in good material condition, and were in the appropriate configuration for the current plant conditions.
Operator Knowledge and Performance 04.1 Neoative Out-of-Service Performance Trend a.
Inspection Scope (71707)
The inspectors reviewed the details of several out-of-service related problems.
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Observations and Findinas The inspectors and licensee both identified continued out-of-service problems this period, which represented a declining trend in performance in this area. The inspectors documented previous cut-of-service issues in Inspection Report 50-254/98004; 50-265/98004 in April 1998. The licensee wrote trend problem identification form
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I (PIF) Q1998-02365 in May 1998 to track and evaluate recent out-of-service issues. This i
problem identification form described problems concerning general compliance with the
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l out-of-service program, and with the preparation, review, installation, and return to
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l service aspects of the program.
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The inspectors identified that several of the out-of-service problems could have had more serious consequences, and were possible precursors to more significant out-of-service events. One event involved a refuel bridge platform that was operated although an out-
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of-service tag was hanging on the pendant from which the bridge was operated. The out-of-service was used as a control to ensure criticality safety because a modification on the refuel bridge failed to include the proper rod block interlocks specified by the Updated Final Safety Analysis Report (see Section 04.2). A second problem involved an out-of-I service that was designed to protect personnel frorn high radiation dose during traversing
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in-core probe maintenance. This problem, which is described in Section M1.4, showed a
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lack of adherence to the requirements of the out-of-service program. No overexposure j
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occurred during this event, but given different plant conditions, the consequences could have been more severe.
A third event occurred on May 1,1998, when the "D" residual heat removal service water j
pump was started while a diver was in the water near the pump suction. The diver had j
not been notified of the pump start in advance. Further review by the inspectors of the residual heat removal service water pump start revealed that the licensee's root cause j
evaluation of the event was downgraded to an apparent cause evaluation, and the i
quality of the apparent cause evaluation was poor. Although identifying that I
communication was poor and that the special instructions were not followed, the j
evaluation did not address why the instructions were not followed, and did not take l
corrective action to prevent recurrence.
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The inspectors identified that an individual, independent of the out-of-service preparer I
and first and second approvers, removed the requirements to install caution rings on the
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residual heat removal service water pump control switches by fining out and initialing the l
step on the out-of-service form. This action was a violation of interim Procedure
Number 98-0035 " Station Equipment Out-Of-Service." Step 5.2.8 indicated that all
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sequence changes must be reviewed and approved by two qualified individuals.
Step 6.5.1 indicated that if an out-of-service checklist cannot be competed as written, "the i
hard copy of the checklist shall then be marked by pen / ink changes with the required isolation point changes, positions and sequences. These changes shall be reviewed and approved by a second qualified individual and both shall sign the checklist." This was considered a Violation (50-254/98009-01; 50-265/98009-01) of TS 6.8.A.1.
Inspectors' conversations with plant management revealed that this problem was not considered a significant event. Plant management initially concluded that the out-of-service progrem requirements were met and that the need to notify the divers was considered an informational courtesy. The inspectors described to licensee management that the suction of the residual heat removal service water pumps at the intake structure was large (24 inches in diameter) and the combined flow rate of two pumps was significant (two pumps take a suction from each intake line with a possible flow rate of 7000 gallons per minute). These conditions were such that a diver's safety could be jeopardized, and that the in-flow could affect system performance through an entry of foreign material. The inspectors concluded that the significance of this problem in not
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su protecting divers was greater than what was indicated on the problem identification form, and the corrective actions were not commensurate with the significance of the problem.
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Conclusions The inspectors and licensee both identified a neDative trend in out-of-service performance which included problems with the preparation and review stage, the
out-of-service hanging stage, the return-to-service stage, and the general compliance l
with the out-of-service program. Several of the out-of-service problems could have had more serious consequences, and were possible precursors to larger out-of-service events.
The licensee's evaluation of a failure to protect divers during a pump start was not thorough or conservative. The evaluation did not address why the instructions were not followed, and did not describe corrective action to prevent recurrence. Operations management initially did not consider the event significant and did not reset the station event free clock because of the perception that the requirements of the out-of-service program were followed and that the requirement for notifying divers of a pump start was an informational courtesy and not a function of personnel safety.
04.2 Out-of-Service Eauipment Operated _bv Fuel Handlina Personnel a.
Inspection Scope (71707)
The inspectors interviewed personnel and reviewed prob!em identification forms and other assessment reports associated with fuel handling activities on Unit 1.
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Observations and Findinas Technical Specifications required that prior to operating fuel handling equipment over the reactor vessel, the fuel handling bridge position switch interlocks needed to be tested. In Licensee Event Report (LER) 50-254/97012, the licensee determined it was physically possible for both refuel bridge monorail hoists to be over a portion of the reactor vessel without the refuel bridge position interlocks being actuated due to a design error. The licensee administratively controlled the monorail hoist during core alterations by hanging
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an out-of-service tag on the monorail hoist pendant.
However, on April 4,1998, a fuel handler did not see the out-of-service tag, and operated the fuel handling bridge hoist, using the pendant. When the fuel handler operated the pendant, the bridge hoist moved, indicating the power to the pendant was not de-energized. Even though the monorail hoist was not being used for any com alteration activities, the operation of out-of-service equipment was prohibited by Quad Cities Administrative Procedure 230-04, " Equipment Out-of-Service." This was considered a Violation (50-254/98009-02) of TS 6.8.A.1.
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In April 1997, design engineering personnel determined that a 1986 modification to the refuel bridge did not meet design requirements. The modification to correct the problem was scheduled to be completed before the next refuel outage. However, the administrative controls were insufficient to prevent personnel from operating out-of-service equipment and the out-of-service was insufficient to prevent movement of the refuel bridge and monorail hoist. A nuclear tracking system item was assigned to the operations department to review refuel bridge out-of-service tagging, with an assigned completion in late September 1998.
In inspection Report 50-254/97021; 50-265/97021(DRP), the inspectors noted a safety analysis of the fuel handling bridge position switch interlocks stated the procedural controls provided the same protective function as the interlock. However, this event highlighted that the administrative controls would not present the operation of the refuel bridge.
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Conclusions The inspectors concluded an individual failed to adhere to the administrative procedure for out-of-service equipment. The out-of-service on the refuel bridge was insufficient to
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ensure the refuel bridge would not move when operated from the pendant. This event
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showed that procedural controls to prevent operation of the bridge did not provide the j
same protective function as would be provided by functioning interlocks.
J O.7 Quality Assurance in Operations (40500)
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07.1 General Comments
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A special team inspection was conducted to review the performance of the corrective
action process. The inspectors reviewed corrective action documents, audits and audit I
responses and observed some corrective action review meetings. The team also reviewed some of the licensee's self-assessments of plant readiness for restart including some depart,nental reviews.
l 07.2.1 Review of Corrective Action Documents (Problem Identification Forms and Licensee Event Reports)
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Inspection Scope The inspectors reviewed 27 problem identification forms and four licensee event reports dated from summer 1996 through early April 1998. The inspectors reviewed how the licensee screened, evaluated, and dispositioned the issues.
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Observations and Findinos The inspectors determined that most of the problem identification forms and LERs were reasonably screened, evaluated and dispositioned by the licensee. However, the inspectors identified three instances of incomplete corrective actions and four instances where the PIF system did not adequately reflect how issues were dispositioned.
Additionally, some questions remained regarding LER corrective actions as well.
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I Examples of Incomplete Corrective Actions:
e PlF Q1998-01566, Over Torquing %-6601 Emergency Diesel Generator Crankcase Vacuum Connection.. A system engineer inappropriately added a torquing specification to a design drawing without review or concurrence.
Corrective actions included counseling mechanics and work analysts. However, the evaluation was not clear if the correctiva actions were also implemented for the system engineer who caused the error, e
PlF Q1998-01697, Residual Heat Removal Service Water Relief Valve Failed to Lift by 400 pounds per square inch gauge. On March 7,1998, engineering
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determined an operating surveillance test was not in accordance with the j
inservice testing program. A procedure change request was submitted on April 3,
1998, to cancel the procedure. However, operations performed the procedure the j
same day. The licensee attributed the event to inadequate procedure review by i
inservice testing personnel. Corrective actions included informing personnel reviewing operations post-maintenance testing about the event, and deleting the procedure. Corrective actions did not include addressing improvements in procedure reviews by inservice testing personnel or more timely submittal of procedure change requests to cancel deficient procedures.
PIF Q1997-03924, Computer Room Humidifier Does Not Work. The licensee j
attributed the cause of this condition to aged and degraded components in the J
computer room ventilation system. The humidifier was listed as part of the i
system in the Updated Final Safety Analysis Report (UFSAR) Section 9.4.1.2. A
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design change to replace the defective component was canceled in May 1995.
l An engineering request,9703011, was written in May 1997 to abandon the l
equipment in place and a nuclear tracking system item was written to revise the UFSAR. The PIF evaluation was deficient because it did not address how equipment identified in the UFSAR was allowed to degrade to a condition which differed from the design described in the UFSAR, the untimely update of the UFSAR, or the need for a 10 CFR 50.59 safety cvaluation.
Title 10 CFR 50.59 authorized the licensee to modify the plant as described in the UFSAR provided a written safety evaluation was performed which provided the basis for a determination that the change did not involve an unreviewed safety question. The inspectors concluded that although this change did not create an
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unreviewed safety question, the licensee did not perform a safety evaluation of
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this UFSAR nonconformance. This was considererl a Violation (50-254/98009-06,50-265/98009-06) of 10 CFR 50.59.
Examples of Weaknesses in Dispositionino PlFs PIF Q1997-03486 Comed Owned Valves Operated by NALCO Service
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e Technician. Documentation was lacking to show that plant on-site review committee (PORC) comments had been addressed as to how this problem represented a limited issue that did not warrant broad corrective actions.
PlF C1998-00465, Adverse Trend in Nuclear Tracking System items. This PIF
was closed to performing a root cause report associated with corrective action
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report (CAR) Numbers 04-98-010 and 04-98-013. However, the inspectors identified the CARS referenced did not perform a root cause report. The root I
cause report was canceled due to breadth and scope of the corrective action program audited by corporate quality assessment. The problem identification form system was later updated to show how this item was dispositioned.
PlF Q1998-01551, Unit 2 Diesel Generator inspection Failure. The inspectors
identified that this problem identification form was screened by the events screening committee as not being a rework issue. However, the inspectors determined the maintenance department screened problem identification forms separately for rework and PIF Q1998-01551 was screened by maintenance staff as being rework. The maintenance staff infrequently piovided a list of problem identification forms screened as rework to the coordinator. However, the coordinator did not frequently update rework status in the problem identification form system. The problem identification form system was updated to reflect rework status of this issue.
Resolutions to Licensee Event Reports e
Licensee Event Report 50-254/96009: 50-265/96009: During a Postulated Loss of Coolant Accident (with offsite power available), Voltage to Selected Safety-related Loads Could Have Been Degraded Due to an inadequate Design Analysis Review.
Engineers noted a discrepancy between the cable length modeled in the degraded voltage calculation and the actuallength of the cable in the field which would have resulted in less than adequate terminal voltages for several components. Design changes were performed on the control circuits for the Unit 1 and Unit 2 low pressure coolant injection system inboard injection valves, the Unit 1 emergency diesel generator ventilation fan and the Unit 1 and Unit 2 emergency diesel generator fuel oil transfer pumps. The licensee performed reviews of all safety-related power circuits using revised cable lengths based on plant walkdowns of cable end lengths. The conclusion of the review was that all Unit 2 480 V loads had sufficient terminal vcltage based on Engineering Evaluation QDC-7800-E-0192, which used a new value for the critical voltage for buses 23-1 and 24-1 of 3845 V. The UFSAR, Section 8.3.1.8," Analysis of Station Voltages," stated, "The results of the voltage drop calculations showed that the minimum running voltage is 3840V when the minimum value of switchyard voltage and the minimum value of switchyard short circuit current are assumed.. " and
"The set point of the second level protection relays is 3840V +/- 2 percent with a time delay of 5 minutes +/-5 percent." Through discussions with engineers, the inspectors determined that the set point change was not conducted under the sci point change program per Quad Cities Administrative Procedure 400-3, " Set point / Scaling Change Request," and no 10 CFR 50.59 evaluation for a change to the UFSAR was performed. The TS at the time were consistent with the UFSAR and required the second level undervoltage setpoint to be 3840 +/- 2 percent.
New TS implemented in September 1996 changed the second level undervoltage setpoint from 3840 +/- 2 percent to greater than or equal to 3833 V. The regulatory assurance department identified the need for a change to the TS set point in January 1998 while researching a similar but unrelated issue. The
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w change, which raised the set point to greater than or equal to 3845 V was submitted to the NRC on May 18,1998.
The inspectors identified a second UFSAR discrepancy. During the licensee's review of the issue in 1996, engineers identified several pieces of equipment which were determined to have less than 90 percent running voltage as
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recommended by NEMA when the revised cable lengths were used. In each case, calculations were done to adjust the required terminal voltage acceptance criteria based on motor brake horse power and a review of thermal overload trip setpoints. Section 8.3.1.8 of the UFSAR states "...Since the typical voltage drop in a motor feeder cable is 0.5 percent, adequate margin exists between the calculated minimum running voltage and the NEMA standard that minimum voltage be limited to 90 percent of equipment rated voltage."
The inspectors did not identify any technical problems with the resolution of the problems identified in this licensee event report. However, in this case, complete corrective actions should have included two UFSAR changes and a revision to the TS set point. These issues are considered to be an Unresolved item (50-254/98009-07; 50-265/98009-07) pending further review of the requirements of 10 CFR 50.59.
- Licensee Event Report 50-254/97015: The Electrical Protection Assembly Failed Due to Aging and Deterioration of the Undervoltage Release Coil Causing a Loss of Power to the Reactor Protection Bus B.
The electrical protection assembly failed and the subsequent loss of power caused a loss of shutdown cooling to Unit 1. Operators responded properly and heat up of the reactor coolant system was minimal while shutdown cooling was restored. In response to this event and General Electric Service Information Letter 496 which addressed spurious electrical protection assembly trips and recommended breaker and circuit board replacement, Quad Cities station committed in the licensee event report to replace the remaining 8 of 12 electrical protection assembly breakers by May 1,1998. On or about that date, the inspectors found that 4 of 8 breakers had not been replaced and were not currently scheduled for replacement. The licensee had failed to take the corrective action as committed in the licensee event report. Upon discovery of the missed commitment, management decided to replace all the breakers prior to reactor startup.
e Licensee Event Report 50-254/97011: 50-265/97011: The Residual Heat Removal Service Water System Was Made Inoperable Due to Uncertainties Related to 4kV Air Magne-Blast Horizontal Gas (AMHG) Circuit Breakers, Which Had Experienced Cracks in the Auxiliary Switch Mounting Channels.
When the cracks in the auxiliary switches were discovered the licensee declared all affected breakers inoperable and shutdown Unit 1. The root causes were l
identified as a design deficiency on the mounting of the auxiliary switch and the torque values applied to the fasteners. Immediate corrective actions were completed to install a ty-wrap strap around the switch and the mounting plate.
This design was seismically tested and qualified to 18 spring discharges and i
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150 breaker cycles. Operations and maintenance departments instituted inspection procedures and tracking of breaker cycles and discharges to monitor the breakers. The LER contained two commitments. The first commitment was to complete the design change for the Unit 2 breakers prior to startup and the second was to evaluate the feasibility of extending the qualification of the breakers for 6 years (up to 750 breaker operations). As a result of the extension, inspection requirements were to be relaxed. The permanent fix was to install a u-bolt. This design was qualified for a 40-year life and was, in fact, the manufacturers fix to the 10 CFR Part 21 deficiency. Newly installed breakers were delivered with the U-bolt design but existing breakers would require a j
modification.
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The licensee planned to install the u-bolt modification for each breaker during the 5-year preventive maintenance activities, with the first breakers to be completed by March 1999. A documented plan for all breakers had not yet been developed but was being tracked in the nuclear tracking system with a due date in late May.
A second nuclear tracking system item was developed with a due date of March 1,2002, to ensure all breaker ty-wraps have been replaced. The inspectors were concemed that past preventive maintenance had been extended past 5 years and questioned the tracking mechanism to ensure that breaker preventive maintenance and ty-wrap replacement were completed on schedule.
The engineer recognized the concem and had documented in the nuclear tracking system that this particular item could not be canceled or extended.
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Conclusions The inspectors concluded the licensee appropriately screened, evaluated and dispositioned a majority of problem identication forms reviewed. However, the
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inspectors identified that in over 25 percent of the issues, some aspect of the corrective actions was incomplete, or the process did not capture how or why problem identification forms were dispositioned the way they were. The inspectors' reviews of LERs also found elements missing in the corrective actions including a missed commitment and one unresolved item on UFSAR and TS revisions that were not made.
07.2.2 Corrective Action Proaram Audits and Process Observations a.
Inspection Scope The inspectors reviewed the licensee's responses to a level I (the highest level of significance) Corrective Action Record (CAR) 04-98-001 which identified ineffective corrective actions. This Quality and Safety Assessment (Q&SA) Department finding was issued in January 1998. The inspectors also reviewed performance trends, follow-up audits and findings, and observed some corrective action review meetings.
b.
Observations and Findinas Q&SA Audits i
in January 1998, the Corporate Assessment group performed broad-based audits of the l
corrective action program to follow-up on CAR 04-98-001. The 13 Level ll CARS
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generated by the audits included ineffective tracking and resolution of corrective actions, excessive number of overdue root cause reports, apparent cause evaluations, and nuclear tracking system items, and other problems associated with corrective action l
program weaknesses. A follow-up audit in April 1998 concluded that the corrective actions taken were effective enough to support plant restart. The inspectors reviewed the trending charts for the total number of open NTS items, past due NTS items and NTS due date extensions and other corrective action trends. The trends for the last three months were favorable. The total number of open NTS items had stopped increasing while both
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over due and extended due dates had greatly decreased. Other follow-up audits in the i
corrective action area continued to identify examples of inadequate corrective action I
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closures, although most activities were adequately performed.
In response to CAR 04-98-001, the licensee committed to a review of past corrective l
actions. When inspectors reviewed the results, it was identified that for the major l
departments of operations, maintenance and engineering, the results of the departmental l
st? lup readiness reviews were submitted as a response. The Q&SA Department had
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accepted this approach. Upon questioning by inspectors, it was determined that the readiness reviewers of closed items had used a criteria that would only identify restart issues fron. past corrective actions. These reviews had not determined if the specified corrective actions had been effective, or whether the cor sctive actions had been adequately completed. The results indicated that no examples of inadequate corrective actions closures were identified. At the same time, Q&SA auditors and NRC inspectors continued to identify examples of corrective action closures that were not adequate.
Event Screenino Committee The inspectors attended several daily event screening committee meetings and noted good participation from all attendees. Event screening committee members generally were prepared (i.e., had read the problem identification forms to be screened). In a couple of cases, problem identification forms were retumed to the initiators because of poor quality or lack of information. In several cases, disposition with respect to nonconformance classification was in question. For these issues, the committee members deferred disposition until the next day in order to research the procedural requirements. The inspectors noted that deferred issues were dispositioned the next day as planned.
The Q&SA department had issued a level 11 corrective action record on event screening committee deficiencies on February 5,1998, with follow-up planned for May 13,1998.
Since the corrective action record was written, the format of the event screening committee meeting had changed. At the time of the inspectors' review, the committee was operating as described by the new process described in the station response to the corrective action record.
c.
Conclusions The inspectors noted the identification of corrective action program issues by the Q&SA department was aggressive and a positive contributor to improving the performance of the corrective action program. In some cases, the corrective actions implemented to address the Q&SA findings were effective as indicated by improved performance i
indicators. The inspectors also noted better management involvement in certain aspects
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I of the corrective action program such as greater management presence in the event screening committee. Recent changes to the event screening committee procedures were implemented and improved the overall process. However, there continued to be examples of weaknesses in corrective action implementation and the Q&SA staff erred in accepting restart readiness review results in response to Level I CAR 04-98-001
" ineffective Corrective Actions."
07.2.3 Review of Corrective Actions on a Significant Condition Adverse to Quality Report a.
Inspection Scope The inspectors reviewed the licensee's process of problem identification, screening and resolution of PIF Q1997-03147," Adverse Trend in TS Non Compliances." The inspectors spoke to personnel and attended meetings on possible solutions to non-compliances with TS requirements. The inspectors reviewed the root cause report generated by the team and reviewed the nuclear tracking system items generated as corrective actions to these events. The inspectors attended a corrective action review board which performed an effectiveness review of this problem identification form. The inspectors reviewed additional non-compliances with TS after implementation of corrective actions to determine the thoroughness of the corrective actions.
b.
Observations and Findinas The inspectors determined actions taken to resolve PIF Q1997-03147 were appropriate but identified some deficiencies as described below.
Problem Identification
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From June 23,1997, through August 8,1997, the licensee identified ten significant conditions adverse to quality involving non-compliance with TS requirements. On August 11,1997, the licensee documented this adverse trend on PIF Q1997-03147.
The inspectors concluded the event screening committee appropriately assigned a high significance level to the PlF and appropriately required a root cause report to investigate the possible causes of the non-compliances. The root cause investigation team later identified nine similar events dating back to January 1996.
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Root Cause Report
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On September 25,1997, a management approved charter was developed to form a multi-
disciplined team to determine root causes and recommend corrective actions to prevent
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recurrence of the identified TS non-compliances. The team reviewed all 1996 PlFs and PlFs through October 1997 for TS non-compliances, and identified programmatic d
weaknesses in the electronic work control system (EWCS) used to implement, update and maintain TS requirements. Some humen errors were also identified but were of j
i lower frequency than the process issues. The root cause report was completed November 7,1997. The report was reviewed and approved by management through the
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plant onsite review committee (PORC) 3 days later.
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The inspectors periodically attended team meetir qs during the fall of 1997 and reviewed the root cause report. The inspectors determined de repori to be thorough and proposed corrective actions focused on ensuring TS requirements were identified in site procedures, ensuring the procedures were performed within the required frequencies, and ensuring the electronic data base properly implemented the requirements. The root cause report generated 19 corrective actions to prevent recurrence.
Effectiveness Reviews The licensee performed effectiveness reviews after corrective actions were implemented to determine if corrective actions were effective to prevent recurrence of problems. The licensee implemented a corrective action review board (CARB) to perform these effectiveness reviews. The inspectors attended a CARB in which an effectiveness review was performed for corrective actions for PlF 1997-QO3147.
The corrective actions for PIF 1997-Q03147 were only recently implemented and most had not been challenged. The CARB concluded that of the 19 corrective actions evaluated, three actions were effective and the 16 remainder actions were indeterminate.
The CARB approved the need to perform additional effectiveness reviews later. The CARB also identified one NTS item was closed out to a " promise" and the " promise" had not been implemented. This deficient condition was documented on PIF Q1998-02232.
The inspectors determined the effectiveness review appropriately reviewed the corrective actions associated with PlF Q1998-03147. The CARB properly concluded the effectiveness of corrective actions was indeterminate and scheduled effectiveness reviews for later dates. The CARB also identified an NTS item was improperly closed out.
Repeat Missed TS Surveillance Since December 1997, the licensee identified nine additional non-compliances with TS.
Five of these non-compliances were identified as a direct result of corrective actions from previous non-compliances. The CARB considered four of these identified non-compliances as evidence of at least one effective corrective action. Three non-compliances were related to programmatic failures of the inservice inspection and inservice testing programs and would not have been prevented by the implementation of corrective actions associated with PlF Q1997-03147.
One corrective action to PlF Q1997-03147 required a step-by-step review of TS. The remaining non-compliance was not identified as deficient during this review. The
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reviewer failed to ensure there was an adequate margin between the TS required temperature limit and the limit required by an implementing station procedure. This non-l compliance was later identified during a quality assurance review.
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Conclusions
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I The inspectors concluded the licensee appropriately assigned a high significance level to j
the TS non-compliances. The root cause report was thorough and corrective actions
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assigned to this issue were appropriate. The CARB documented on a problem identification form an instance where an NTS item was inappropriately closed. In
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addition, one corrective action was inadequate because a step-by-step review of TS failed to identify an additionalinadequate surveillance. Enforcement for the issue of inadequate TS surveillance performance was addressed in Inspection Report 50-254/97014; 50-265/97014.
07.3 Restart Self-Assessments a.
Inspection Scope The inspectors reviewed Q&SA restart assessments, licensee focus area assessments, and department restait readiness assessments for the following departments of Operations, Maintenance, Engineering, Regulatory Affairs, and Quality and Safety Assessment. The inspectors spoke to personnel associated with assembling and evaluating department assessments. The inspectors also attended senior startup review boards which evaluated the quality of department self-assessments.
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Observations and Findinas l
i Departmental Self-assessments A memorandum from the site vice president to each department head required a i
departmental self-assessment be performed. The assessment was to ensure all
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identified issues were appropriately addressed prior to unit startup. The self-l assessments required a review of all previously identified open issues, a sampling of closed issues and unidentified issues as gathered from employee surveys. Each issue
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was entered into the corrective action process, if needed, and assessed to determine if
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the issue needed completion prior to startup.
The inspectors reviewed the reports and determined the department efforts to identify
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issues were good. Similarly, the employee surveys captured some issues not previously identified. The inspectors noted the identification and review of corrective actions for l
closed issues was a sample, targeted to identify restart issues. Although the engineering department and smaller departments reviewed all the actions taken in 1997, the sampling i
of past issues resulted in finding no additional concerns. However, the inspectors were l
concemed with the licensee's implementation and effectiveness of corrective actions from past events. This concern was based on previously identified performance weaknesses in this area. The inspectors also questioned the licensee's criteria for review of the past issues and the small sampling size.
The senior startup review board evaluated each department's readiness for startup. The inspectors determined the review board keenly identified weaknesses in each department's readiness assessments.
Q&SA Assessments The inspectors reviewed a " Station SALP Area Assessment" and a "Two-year j
Retrospective Evaluation of Quad Cities Station issues" dated March 31,1998. Both of these were performed by the Q&SA department in preparation for plant restart. These assessments looked for trends or significant open issues by reviewing past findings by
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various inspections, audits and overviews.
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Station Blackout Diesel Generator Preventive Maintenance
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The licensee committed to the NRC that all station blackout diesel generator preventive maintenance tasks would be current prior to Unit 2 startup. The inspectors reviewed data supplied by each of the maintenance departments that indicated all Unit 2 items were current. The Unit 1 items were mostly current with the exception of some instruments which were being tracked by the maintenance department as prior to startup items.
The preventive maintenance program for the station blackout diesel generator had not yet been fully developed and entered into the electronic work control system. Therefore, each maintenance department identified required tasks, and performed the work under I
corrective work requests rather then predefined work requests normally used for l
preventive maintenance. The licensee intended to have the entire preventive maintenance program developed by December 1998.
c.
Conclusions The inspectors concluded the licensee's identification of issues through self-assessments was Good. However, the departmental reviews of past corrective actions did not include
corrective action implementation and effectiveness; areas previously determined to be I
weak. The senior startup review board identified other weaknesses by asking probing l
questions. The Q&SA assessments were good efforts to identify additional problems l
revealed in past trends or issues. Licensee commitments pertaining to the station j
blackout diesel generator preventive maintenance program appeared to have been met.
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Miscellaneous Operations issues (92700)
08.1 (Closed) Violation 50-254/97006-01: 50-265/97006-01: Failure to Maintain Procedures.
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The licensee demonstrated weaknesses in maintaining the current revision in a controlled i
copy of an operating procedure. The inspectors reviewed the licensee's corrective actions as stated in the response to the violation. The inspectors had noted improvement in this area. This item is closed.
08.2 (Closed) Violation 50 254/97026-02: 50-265/97026-02: Valves Reassembled Improperly.
The inspectors verified that corrective actions were completed. This violation is closed.
j 08.3 (Closed) Licensee Event Report 60-254/96009: 50-265/96009: Voltage to Selected j
Safety Related Loads Could Have Been Degraded. Corrective actions were reviewed as
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discussed in Section 07.2.1. An unresolved item was opened to further review the failure
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to review the changes to the updated final safety analysis report against the requirements j
of 10 CFR 50.59. This LER is closed.
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08.4 (Closed) Licensee Event Report 50-254/97015: Unit 1 Electrical Protection Assembly Failed. Corrective actions were incomplete at the time of review and the LER commitment date was missed. Licensee management rescheduled the maintenance
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activities to be conducted prior to reactor startup. This LER is closed.
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08.5 (Closed) Licensee Event Report 50-254/97011: 50-265/97011: Unit 1 Residual Heat Removal Service Water System inoperable Due to 4kV Breaker Uncertainties. All corrective actions described in the LER were completed. Longer term modifications were in the planning stage and were being tracked by the licensee. This LER is closed.
08.6 (Closed) Licensee Event Report 50-265/97008: Five Control Rods Did Not Receive Scram Time Testing. The inspectors verified that all corrective actions were completed.
This LER is closed.
II. Maintenance M1 Conduct of Maintenance M1.1 Loss of Electrical Power to Unit 1 Main Power Transformer a.
Inspection Scope (71707)
The inspectors observed operators recover from an unanticipated loss of electrical power to the Unit 1 main power transformer. The inspectors reviewed the licensee's promp'
j investigation report, other troubleshooting documentation and Problem Identification Form Q1998-01806.
b.
Observations and Findinas On April 15,1998, the station was aligned to receive two sources of offsite power to Unit 1. One source was from the main power transformer which was operated in a backfeed mode. The second source of offsite power was to Unit 1 Transformer T12. All Unit 2 electrical loads were powered by two cross-connects from Unit 1.
Unexpectedly, the electrical breaker from the switchyard to the main power transformer opened due to a ground fault. With this fault, the station had lost one of only two sources
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of offsite power. This resulted in only one source of offsite power being available with all j
Unit 2 loads being fed from Unit i via the cross-connects. This condition was allowed by
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TS with both units shut down, but was considered undesirable since there was a potential for the cross ties to exceed a 600 ampere limit. Operators ensured the limit was net
exceeded on the cross ties and later energized a second offsite power source (Transformer 22).
Upon receipt of the ground fault, control room operators responded appropriately. All
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plant equipment performed as expected. Operator actions were in accordance with
operating and abnormal procedures and were accomplished using both self-check and peer-check techniques. Operator response to the event and subsequent energization of Transformer T22, were discussed and briefed prior to initiating the tasks.
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The licensee initiated a promot investigation team to review the event. The investigation included review of protect ' relay operations, inspection and test results of the affected area, probable cause of the event and proposed corrective actions. The investigation determined the source of the ground fault to be a grounding cable that was in close proximity to an energized bus. This event was attributed to electrical maintenance l
personnel who improperly routed the grounding cable.
This event highlighted where poor quality maintenance resulted in loss of one of two sources of offsite power, and caused operators to enter into abnormal operating p ocedures. Recovery from the event took several days of outage time. The inspectors identified that this event was not initially screened as being a rework issue until prompted by the inspectors. Problem Identification Form Q1998-01886, which documented the main power transformer trip, was initially screened as not being rework. There were no additional problem identification forms generated as a result of this event and no other method captured the rewcrk aspects of this event.
c.
Conclusions Poor quality of maintenance resulted in the loss of one of two sources of offsi+e power.
The inspectors concluded equipment responded properly to the event and control room operators' actions were in accordance with procedures and were accomplished using both self-check and peer-check techniques. The investigation was both timely and thorough. The inspectors identified that the rework aspects of this event had not been captured.
M1.2 Surveillance Test Performance
a.
Inspection Scope (71707)
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The inspectors observed performance of Quad Cities Surveillance Test 0300-01,
" Automatic Blowdown Logic Test," which was intended to meet TS Requirements 4.6.F.1.b,4.2.B.2 and Table 4.2.B-1.
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Observations and Findinas The inspectors found most of the preparations for the surveillance to be extensive, and the pre-job brief to be thorough. Steps which required second verification of the proper component were carefully checked. Communication between the work site and the l
I control room was good. The inspectors found that proper operation of test equipment for checking the timing of certain relays was not verified prior to the test. The use of this equipment during the test yielded unsatisfactory results and resulted in a several week delay in completing the surveillance test.
Test results indicated satisfactory equipment operation with the exception of 4 relay timers which were found outside of the timing tolerance range of 14 to 15 seconds by about 3 seconds or less. Instrument drift was the suspected cause, however, these timers had not been previously tested with accurate electronic timers. The timers were reset within the required range.
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Conclusions The inspectors observed good coordination and self checking during performance of the surveillance. The surveillance test was delayed by several weeks due to problems with test equipment that had not been resolved before the surveillance started.
M1.3 Failure to initiate Procedure Chanae Reauest a.
Inspection Scope (62707)
The inspectors observed electrical maintenance workers perform Quad Cities Electrical Preventive Maintenance Procedure 0200-16, Revision 15, " Inspection and Maintenance
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I of 480 V AK-25 Breakers." The inspectors reviewed the circumstances surrounding the decision to not perform one of the steps in this procedure. The inspectors reviewed the licensee's procedure adherence requirements and interviewed procedure writers and maintenance personnel.
b.
Observations and Findinas On April 16,1998, the inspectors observed electrical maintenance technicians perform port 5ns of Quad Cities Electrical Preventive Maintenance Procedure 0200-16. The inspectors noted that the workers exhibited a good understanding of the procedure.
However, when the workers reached Step I.7.b which required application of a light film of Mobil 28 grease to the primary breaker contacts, they contacted their foreman to ensure that the step needed to be performed. The foreman, after discussing the step with his supervisor, instructed the workers to not perform the step. The step was annotated with a "not applicable" symbol, and the workers continued to perform the surveillance.
The inspectors were concemed that the workers were not following the requirements of the approved procedure for maintenance of safety equipment. Through discussions with station management, the inspectors determined that the immediate supervisors assumed that procedure steps could be skipped as long as a supervisor approved the change.
This understanding was different from the description of procedure compliance in station documents. The inspectors noted that Quad Cities Administrative Procedure 1100-12,
" Procedure Use and Adherence," provided instructions for when situations may arise where a procedure may be perceived as inadequate to perform a given task or evolution.
The procedure stated that "in such situations, the supervisor shall resolve the discrepancy in the procedure by submitting a procedure change, either Procedure Field Change, Interim Prccedure or permanent, depending on the actual situation. No further procedural steps shall be accomplished until the procedure change is approved." Ori April 16,1998, the supervisor did not submit a procedure field change, and work continued with the procedure.
Licensee senior management disagreed with the maintenance supervisor's decision to skip a step without performing the necessary reviews. The breaker inspection procedure provided confusing guidance on the ability la skip a step by stating that workers could
" place N/A in all steps which are not required." The licensee initiated a problem identification form, and resolved to review all electrical maintenance procedures to determine if this unclear guidance was also included in other procedures. The inspectors noted that the scope of these corrective actions was narrow, and the licensee
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subsequently expanded tha aview to all maintenance procedures. The unclear guidance was similar in all maintenana procedures.
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The licensce's review of this event determined that several corrective actions were necessary. In addition to reviewing all maintenance procedures, the licensee also resolved changing the unclear guidance 'n skipping steps. Additionally, guidance in the procedure adherence procedure was expanded to describe when it was acceptable to annotate steps with a "not applicable."
The failure to comply with the Quad Cities Administrative Procedure 1100-12 was a Violation (50-254/98009-03; 50-265/98009-03) of TS 6.8.A.1.
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Conclusions The inspectors found that maintenance workers failed to perform steps in an approved procedure and fnited to change the procedure prior to continuing the maintenance actions. Maintenance supervision guidance contributed to the conclusion th.at this violation of TS requirements was acceptable.
M1.4 Traversina incore Probe Activities Not Corirolled By Out-of-Service Proaram a.
Inspection Secpe (62707)
The inspectors reviewed the circumstances surrounding work on the Unit 2 traversing incore probe system. This included a review of applicable procedures, ra'fiological survey maps and work permits, and licensee investigations. The inspectors also interviewed cognizant licensee personnel.
b.
Observations and Findinas The licensee performed work on the Unit 2 traversing incore probe system in April 1998, which involved the removal of traversing incore probe tubing, reinstallation of the tubing, and hand tests of the tubing. Mechanical work on the traversing incore probe system was conducted from April 8 through April 25,1998. Instrument maintenance workers began their work, and after steps were ccmpleted, requested an out-of-service be cleared on April 25,1998. Although operations staff cleared the out-of-service, another out-of-service card remained on the system. However, on April 27,1998, the instrument maintenance workers requested a temporary lift for this out-of-service in order to perform additional work on the traversing incore probe system. Operations personnel granted this temporary lift, and instrument maintenance staff completed the task requiring the Oft.
However, after the work was completed, the temporary lift remained in place, and tne equipmant was not retumed to an out-of-service status.
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Instrument maintenance proceeded with the next sequence of activities which involved
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hand cranking the traversing incore probes at the local machines. This evolution lasted for six shifts from April 27 through April 29,1998. However, during this evolution, no supervisors or workers verified whether an out-of-service was in place. Associated i
equ:pment was supposed to be tagged out-of service to ensure that operations personnel would not manipulate the equipment while personnel were present in the general area of the traversing in-core detector equipment. This type of operational activity could adversci affect workers' radiological safety. The workers failed to hang, or to verify hung, personal protection cards, contrary to the requirements in Quad Cities Administrative Procedure 0230-04, " Equipment Out-of-Service."
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The failure to follow this procedure was noted on April 29,1998, when an instrument maintenance system expert began work and proceeded to verify that the out-of-service was in place, immediate corrective actions included retuming the system to an out-of-service status, investigating the event, and counseling involved personnel on the appropriate methods for working on equipment which is, or should be, out-of-service.
The inspectors noted that several barriers failed in this event. The failure to ensure personal safety during the evolution reflected a lack of understanding of problems which could be encountered while working on the traversing incore probe system. Under certain plant conditions, the manipulation of traversing in-core probes can create high radiation areas in the vicinity of the machines. In this case, the reactor had been shut down for an extended period of time, the traversing incore probe detectors were less radioactive than at initial shutdown, and were sufficiently deca, cd such that a sutastantial potential for an overexposure was unlikely. The NRC had documented problems associated with work on the traversing incore probe system through numerous information noticer Barriers which remained in place were provided by the radiation protection program and included technician coverage during traversing incore probe activities, alarming dosin,eters and area radiation monitors, and specific abort instructions if elevated radiation dose rates were observed. Additionally, operations personnel were procedurally required to notify health physics personnel prior to remotely manipulating traverring incore probe detectors.
The barriers provided by radiation protection ensured the radiological safety of the maintenance workers.
Quad Cities Administrative Procedure 0230-04, " Equipment Out-of-Service," required supervisors to ensure that an out-of-service card had been placed and an inspection had been conducted, required a worker from the work crew to ensure that out-of-service cards had been correctly placed, and required verifications of personnel protectien cards to be hung and to be in place on the master out-of-service card. The failure to comply with the requirements of this required procedure was a Violation (50-265/98009-04) of TS 6.8.A.1.
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Conclusions During work on traversing incore probe components in April 1998, Instrument Maintenance personnel did not comply with the out-of-service program and personnel protection controls. While the failure to conduct work on this system in a safe and
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protection program requirements and the low dose rate of the detoctor at the time of the
evolution resuiicd in an event where there was no substantial potential for an overexposure.
i M2 Maintenance and Material C,ondition of Facilities and Equipment M2.1 Electrical Breaker Maintenance a.
Inspection Scene (61726. 62707)
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The inspectors reviewod the results of preventive maintenance and testing performed on
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numerous safety and nonsafety-related electrical breakers. In particular the inspectors l
reviewed numerous material condition problems identified on the Merlin-Gerin breakers.
l The inspectors interviewed knowledgeable licensee staff, and observed portions of the l
maintenance activities.
b.
Observations and Findinas The licensee began installation of Merlin-Gerin Lreakers in 1994 to replace the General Electric breakers located throughout the station. The NRC has documented in inspection reports problems the licensee had identified with the Merlin-Gerin breakr, since the initial installation, however, during recent breaker mair,ter.ance activities, the licensee identified numerous other deficiencies. A Commonwealth Edison root cause investigation team was assembled to conduct a review of details associated with these deficiencies.
The team determined that while thera were numerous problems, no clear trend was apparent which would combine these problems together into a generic issue.
Seeral instances of loose wiring were discovered during the breaker inspections. During the initial inspections, four breakers were discovered to have wires which were considered loose by the electrical maintenance personnel, and two other breakers were found to have unsecured wires. All wires were believed te have sufficient tightness to maintain the electrical connection, hence, allowing the breakers to perform the intended safety functions. The licensee tightened allloose wires, and began a root cause investigation. The licensee subsequently repaired loose wiring in 72 of 101 breakers in l
April and May of 1998. While loose wiring was discovered in numerous breakers, there
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were no repor1ed incidents of breakers failing to onerate due to the loose wiring. The l
licensee planned to revise Quad Cities Electrical Preventive Maintenance 0200-21, I
" Periodic Inspection and Maintenance of Meriin-Gerin SF6 4kV Circuit Breakers l
Procedure." The revision was to insert a caution statement to include a 100 percent wire tightness inspection. All deficiencies identified were to be recorded by a problem
! identification form and the data to be provided to the component engineer. The licensee planned to have the component engineer evaluate the results of the loose wire inspections from June 1,1998, through June 30,2000. This review was to include a review of the problem identification form database and nuclear work requests. If the data
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would warrant, a procedure change would be initiated to remove the 100 percent wire inspection from the procedure.
During the loose wire inspections, the licensee also identified the following problems on numerous breakers:. unacceptable clearances between the breaker frame and the q
indicator support plate; springs not discharging; damaged or broken parts; cracked trip l
coils; and cracked or misaligned auxiliary switches. These breakers had not been inspected since installation. The licensee felt that the above problems did not appear to be associated with maintenance activities, but may have been maintenance preventable.
Workmanship, vibrations, and materials were potential causes for the identified problems of springs not charging, loose wires, and parts damaged, cracked or broken. The licensee's investigation team was unable to identify a trend in these incidents.
The licensee's Part 21 Committee concluded that the recently documented problems were not applicable under 10 CFR Part 21. Since the licensee did not perform any.
receipt inspections of the breakers, and the loose wires were found on breakers that had been in service at least a year, the licensee could not conclusively attribute the loose wires to the vendor as a defect. The loose wires could have been caused by vibration or conditions from normal operation. Additionally, since no breakers failed as a result of the loose wires, there was little actial safety consequence to this condition, c.
Conclusions The ingectors noted that the licensee was experiencing numerous problems with 4kV circuit breakers, but was effectively tracking the problems encountered with the breakers, and repairing these problems in a timely manner.
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Licensee Event Report 50-254/95003-00: Motor Operated V.ve Breaker Trip.
On June 29,1995, the B loop of the residual heat removal system was unavailable, and
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during the attempt to place the A loop of the residual heat removal system in service for
the unit, the circuit breaker for Motor Operated Valve 2-1001-29A tripped. The trip was
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due.to a constant close signal being applied to the valve from a previous surveillance which had not been cleared. The starting current for the motor operated valve was greater than the normal starting current, and was sufficient to trip the circuit breaker.
The cause of the event was attributed to inadequate procedures being used to reset the previous isolation signals. The inspectors reviewed the applicable procedures and noted j.
that revisions ensured that the isolation signals on various valves would be reset prior to l
finishing the procedures. The inspectors also verified that the licensee completed commitments made in the LER.
. The licensee changed circuit breaker settings for motor operated valves subject to i
L sudden reversalin direction. The inspectors reviewed vendor evaluations, and noted that the licensee appropriately changed Quad Cities Electrical Maintenance Surveillance Procedure 250-11, " General Electric Model 7700 Motor Control Center Environmental Qualification Maintenance and Surveillance," to include the vendor's recommendation ~ s. Additionally, all motor operated valves subject to the reversal either n
had the associated circuit breaker settings changed or scheduled for change.
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The inspectors note that these actions were sufficient to address concems in the LER, and no violations were identified. This item is closed.
M8.2 (Closed) Unresolved item 50-254/95005-04: 50-265/95005-04: Loss of Residual Heat Removal Capabilities. See Section M8.1. This item is closed.
M8.3 (Closed) Inspection Follow-up llem 50-254/96004-03: 50-265/96004-03: Electrical Breaker Database. The licensee experienced a failure of an electrical breaker but #1 not have a reliable method to locate installed contactors similar to the one that faiied he licensee determinea there were other methods that could be used to determine the location of similar contactors in lieu of a breaker database. This included plant walkdowns, review of equipment qualification binders and stsff memory. The inspectors reviewed the licensee's response to this item. This item is closed.
M8.4 (Closed) Inspection Follow-up Item 50-254/96012-08: 50-265/96012-08: Hydraulic Lock of Motor Operated Valve Spring Pack. The A feedwater regulating valve isolation valve in Unit 1 and both Unit 2 feedwater regulating valve isolation valves had spring packs susceptible to hydraulic lock conditions. The licensee reviewed other "important to plant operation" valves to determine which valves were susceptible to hydraulic lock of the spring pack. The licensee also reviewed the grease relief for all the motor operated valves, and concluded that all Limitorque valves addressed in Generic Letter 89-10 were acceptable as is with respect to grease relief capabilities. The licensee additionally generated action requests for valves similar to the one that failed. Action requests were not generated for any portion of the rest of the motor operated valve population.
However, Quad Cities Mechanical Preventive Maintenance 1500-01, " Mechanical Preventive Maintenance of Limitorque Operators," was revised to require an action request be written if the motor operated valve being inspected was grease relief deficient.
The applicable overhaul procedures have the provisions for replacing all non-slotted spring packs with the slotted style. The inspectors determined inat these corrective actions were acceptable. This item is closed.
111. Enaineerinn E1 Conduct of Engineering E1.1 General Comments (71707)
The licensee identified that from 1991 to 1998 some design information was nM transferred to procedures for the reector protective system setpoints. Corrective action for several setpoint related issues was poor Emergency Diesel Generator reliability problems continued, with one failure to stcrt on demand for the Unit 1 Emergency Diesel Generator.
E1.2 Poor Corrective Action for Reactor Protective System Setpoint Deficiencies (37551)
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Inspection Scope (37551)
The inspectors reviewed operator logs, and found that reactci protective system setpoints had been set in a non-conservative direction for the scram discharge volume reactor trip
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setpoint and other engineered safety feature instrument setpoints. The circumstances l
surrounding the setpoint errors, including corrective action from previous discoveries, l
were reviewed by the inspectors.
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Observations and Findinas l
On August 27,1991, Calculation Number NED-I-EIC-0038, Revision 0 was performed to I
evaluate reactor protective system instrument loop errors during normal operating conditions "to ensure Technical Specification compliance." The evaluation stated, "This
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calculation indicates that the combination of errors could result in the potential for l
exceeding TS Limiting Condition for Operation (LCO) with the current Quad Cities I
instrument Surveillance (QIS) setpoint." The licensee determined that the reactor protection system scram setpoint could be set up to about 3.8 gallons non-conservatively (as compared to the 40 gallon setpoint for the scram discharge instrument volume). No apparent action was taken to resolve this issue f,om 1991 until 1998 when the licensee was reviewing calculations for a reactor building high temperature concem. Corrective action Problem Identification Form Q1998-01424 documented this March 20,1998, licensee discovery.
Engineers completed a new setpoint calculation for the scram discharge volumes in March 1998. This work, along with a historical search of calibration data, revealed five instances of scram discharge volume setpoints exceeding the 40 gallon TS limit for a reactor protective system trip. This information was documented in LER 50-254/98015-00. The setpoints were set non-conservatively high (above 40 gallons) by as much as 3.5 gallons or about nine percent of the TS limit. Technical Specification Table 2.2.A-1 (upgraded TS) and Table 3.1-2 (TS in effect until September 23,1996) required the scram discharge volume setpoint for a reactor protective system trip to be set at less than or equal to 40 gallons level in the scram discharge instrument volumes. This setpoint was intended to provide an anticipatory reactor trip signal before the instrument volumes filled to a point where control rod insertion times or functions may be adversely affected.
Technical Specification Table 2.2.A-1, required scram discharge volume water level-high trip setpoints to be set at less than or equal to 40 gallons. Quad Cities Instrument Surveillance 0300-02, " Scram Discharge Volume Rochester Instruments Calibration and Functional Test," implemented calibration instructions for instruments used to provide the scram discharge volume 40 gallon trip setpoint. This procedure was not modified to account for the deficiencies identified in 1991. Failure to take corrective action for the deficiencies in the scram dischargo volume trip setpc;nts in 1991 led to at least five occasions where the trip setpoint was greater than that required by TS. The safety significance for not meeting the TS required setpoints was lessened by the fact that the scram discharge instrument volume was required by design to have a diverse backup instrumentation system to provide a reactor trip, and this instrumentation was operable.
The inspectors reviewed other TS setpoints that were suspected of bein0 non-conservative. Recent uncertainty calculations pe formed by the licensee identified l
neDative (non-conservative) margins in the setpoints for Main Steam Tunnel Temperature l
High (NED-I-EIC-0039, Revision 0), and Torus-Reactor Building Vacuum Breaker (NED-I EIC-0044, Revision 3). Refueling Floor Radiation High (NED-I-E!C-0316) and Main Steam Line High Radiation (NED-I-EIC-0313) setp@h were non-conservative using
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I existing calculations and assumptions, but were expected to be satisfactory using appropriate revised assumptions. The licensee determined that the Reactor Vessel Water Level Low calculation (NED-I-EIC-022, Revision 2) was in need of a setpoint change because the effects of the reactor vessel level modification had not been
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incorporated into the calculation. Engineers re-evaluated the calculations for these setpoints and found the following negative margin: Main Steam Tunnel Temperature High Setpoint - 16.5 degrees compared to a 185 degree setpoint; Torus-Reactor Building Vacuum Breaker- 0.33 milliamps compared to a setpoint of 7.05 milliamps; Main Steam
- Line High Radiation - 75 millirem per hour compared to a setpoint of 1500 millirem; Refueling Floor Radiation High - 198 millirem per hour cornpared to a setpoint of 100 millirem per hour.
The inspectors reviewed historical documentation of the setpoint concems dating back to I.
1991. A September 18,1991, corporate Nuclear Engineering Design letter to the l
Quad Cities station entitled, " Quad Cities Setpoint Error Analysis Operability Concems"
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(CHRON Number 173165) detailed a number of setpoint concems stemming from a TS
setpoint review. A July 24,1992, Comed corporate Nuclear Engineering Design letter to Quad Cities Station Manager (CHRON Number 189521) recommended approximately 27
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accuracy. Eighteen of these actions were 'Jentified as necessary to correct a negative (or non-conservative) margin condition. T he 1992 letter also indicated that Scram
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I Discharge Volume and Steam Tunnel High Temperature Isolation instrument loops were l
still under evaluation. Although many of these items had been addressed through other design modifications such as reactor vessel water level instrumentation, several had not been addressed prior to 1998.
l The inspectors found that this issue and the recommended corrective actions for negative instrument margin were identified and tracked in the 1992 Vulnerability Assessment Team management report. Upon inspector questioning, the licensee indicated this
- Vulnerability Assessment Team item was considered " closed." At the end of the report period, the licensee could not determine how these Vulnerability Assessment Team engineering issues were dispositioned as " closed." A 1996 record of closure of the issue was found which did not have an adequate justification for closure, and was essentially a j
restatement of the original Vulnerability Assessment Team item.
Criterion XVI," Corrective Action," of 10 CFR Part 50, Appendix B, required conditions adverse to quality to be promptly identified and corrected. Failure to ensure identified instrumentation setpoint errors for TS related setpoints were corrected, which comprised a condition adverse to quality, is a Violation (50-254/98009-05; 50-265/98009-05) of 10 CFR Part 50, Appendix B.
Updated Final _ Safety Analysis Report, Section 7.1.2.1, " Instrumentation Setpoints" specified: "In the selection of the appropriate safety system setpoints, instrument error
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and accuracy are considered, Setpoints listed in Chapter 7 are understood to be nominal
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values; the actual setpoints may vary within prescribed limits to account for particular
instrument accuracies." The inspectors identified that the licensee did not consider
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instrument accuracy for many of the reactor protective system and engineered safeguards features system instruments or could not locate calculations whicn indicated
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that instrument uncertainty had been factored into the setpoint calculation. By the end of the period, the licensee had reviewed calculations for existing reactor protective system r
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f negative margin associated with the setpoint. However, the licensee indicated that calcuhtions were not available for about 40 percent of these instruments. The inspectors
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questioned whether the setpoint recommendations of the 1991 ano 1992 letters were l
addressed. At the end of the inspection period, the licensee stated that these issues had i
been addressed as a result of the March 1998 setpoint effort, but had not provided the results to the inspectors. The licensee was planning to perform some additional l
calculations in 1998, including setpoint calculations for nuclear instrumentation, but a l
schedule was not available at the end of the inspection period.
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Conclusions i
Issues involving the need to review instrument calculations identified in 1991 and 1992 l
were not resolved prior to 1998. Some TS related setpoints were determined to have
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non-conservative or negative margin. The Vulnerability Assessment Team report tracking item for this issue was closed without apparent justification. Five instances of exceeding i
TS required setpoints for the scram discharge volume instrumentation were identified by
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the licensee.
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E1.3 Diesel Generator Reliability Problems I
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inspection Scope (37551)
The inspectors reviewed events and corrective actions for emergency diesel generator
deficiencies.
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Observations and Findinas i,
Several discrepant material condition items were identified and repaired on the
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emergency diesel generators this period. These included cracked exhaust sleeving, a leaking jackat cooling heat exchanger, and continued problems with time delay relays, all on the Unit % emergency diesel generator. A Unit 1 emergency diesel generator failure to start on demand was identified during diesel testing, and was due to a faulty relay in the start logic.
The cracked exhaust sleeve was replaced on the Unit % emergency diesel generator, and j
the other emergency diesel generators were examined and found to be free of sleeve l
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cracks. A root cause for the cracking was not available. The ler> king heat exchanger was replaced on the % emergency diesel generator. The cause of the tube failure on the heat exchanger was not known at the end of the inspection.
Problems continued with time delay relays on the emergency diesel generators similar to problems documented in Inspection Report 50-254/98004; 50-265/98004. Problems this period were due mainly to the Time Delay 1 relay which 'vas intended to stop the emergency diesel generator 90 seconds after start if sdficient oil pressure was not achieved. The 90 second setpoint was not maintained by the relay. The licensee was continuing to pursue a design change to install other time delay relays for the emergency diesel generators, but had not completed this effort at the end of the inspection, l
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On May 15,1998, the Unit i emergency diesel generator fi#ed to start on a simulated undervoltage signal during surveillance testing. The licensee traced the problem to contacts in the ASR-1 autostart logic relay which did not make up as expected. The relay was replaced and sent off site for further analysis. Results were expected ba,ck by June 5,1998.
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Conclusions Equipment problems with emergency diesel generators continued this period. The Unit 1 l
emergency diesel generator failed to start on demand during surveillance testing. The I
cause of the failure was a malfunctioning autostarilogic relay. Other problems were
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identified by the licensee and corrected prior to affecting diesel operability. The causes of these failures were still under review by the licensee.
E8 Miscellaneous Engineering issues (92902)
E8,1 (Closed) Unresolved item 50-254/96011-01: 50-265/96011-01: Criticality Monitors. The licensee had determined that the station was in compliance with 10 CFR 70.24, which required installed criticality monitors in areas where special nuclear material was used or stored. Requirements included evacuation procedures and practice drills. The new fuel storage vault at Quad Cities was an area required to meet the rule. However, on October 27,1997, the licensee issued a letter requesting an exemption to the requirements of 10 CFR 70.24 regarding the criticality requirements. On March 31,1998, the staff issued an exemption from the requirements of 10 CFR 70.24. This exemption closes the unresolved item.
E8.2 (Closed) Unresolved item 50-254/96017-01: 50-265/96017-01: Ultimate Heat Sink. The licensee pedormed rough calculations showing sufficient volumes of water inside the ultimate heat sink boundaries. Potential flow path blocking concems were still not answered, but were not expected to result in a violation. The licensee was continuing to review the potential blocking issue. This item is closed.
E8.3 (CJosed) Violation 50-254/97008-05: 50-265/97008-05: Zebra Mussel Fouling Of Intake Structure. The inspectors reviewed the licensee's corrective actions to the above mentioned violation which addressed inadequate monitoring of zebra mussel growth and its affects on fire pump operability. The cause of the violation was due, in part, to inadequate inspection frequencies of the circulating water intake bay and fire pump suction strainers. In response to the violation, the licensee cleaned and restored the fire pump suction strainers and established a zebra mussel team. The team was chartered in December 1996 and consisted of representatives from maintenance, operations, chemistry, engineering, and environmental services. The team was chartered to evaluate past, present, and needed future actions to mitigate the adverse impacts that zebra mussels could create on plant performance and safety, propose additional corrective actions, and implement those conective actions. The team recommended, and the licensee approved, the coating of the fire pump suction strainers with a copper based marine anti-fouling paint that has been proven at other facilities to be successful in retarding zebra mussel growth and accumulation. The licensee received approval from the Illinois Environmental Protection Agency to perform this modification, and installed the coated strainers in September 1997. The licensee also increased surveillance of the strainers during zebra mussel spawning seasons, and have noted that the copper coating
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l has been effective. The inspectors noted that these actions appeared sufficient to address the concems mentioned in the violation. This item is closed.
E8.4 (Closed) Inspection Follow-up Item 50-254/93015-02: 50-265/93015-02: Unit Shutdown to Repair 2A Feedwater Pump. The problems with the pump were caused by a crack in the socket weld tap connection of the pump flow sensing line. The licensee's investigation determined that the problem was due to an isolated event which had
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occurred during the plant construction. The licensee's corrective action included the repair of the connection and an inspection of other connections in the system. No similar problems were identified. The inspectors noted that these corrective actions appeared adequate. This item is closed.
E8.5 (Closed) Licensee Event Report 50-265/95004-00: Condenser Vacuum Scram Switches Found Out-Of-Tolerance. In July 1995 all four low condenser vacuum scram switches, (PS) 2-503-A/B/C/D, were found to be " low" out-of-tolerance. This was discussed in NRC Inspection Reports 50-254/95006; 50-265/95006. The licensee immediately calibrated the switches into the allowable tolerance. The switches were later replaced with like-for-like switches which were placed on an accelerated calibration frequency. The licensee performed a review of the data obtained from the accelerated calibration frequency, the sample analysis of the old switches, and a review of the historical data, and determined that the original switches were prone to setpoint drift in elevated temperature and humidity environments. Subsequently, the licensee's replaced these switches with a more reliable model switch. There were no further occurrences of as-found "out-of-tolerance" surveillance since the installation of the new model switches. This item is closed.
E8.6 (Closed) Inspection Follow-up item 50-254/96006-06: 50-265/96006-06: Degraded Control Room Humidifier. The Section 9.4.1.2 of the Updated Final Safety Analysis Report stated a steam humidifier was to control the old computer room relative tv nidity.
However, the humidifier had not worked in years. In 1996 the licensee canceled a design change to replace the humidifier but still had not evaluated the condition in accordance with 10 CFR 50.59. This was a violation cited in Section 07.2.1. This item is closed.
IV. Plant Support R4 Staff Knowledge and Performance in Radiation Protection and Chemistry R4.1 Unintentional Release of Xenon-133 (71750)
The inspectors reviewed the circumstances surroundir,g the unintentional release of xenon-133 in the chemistry lab, This included a review of radiological surveys, inspection of the chemistry laboratory, and interviews with cognizant station personnel. The licensee documented this event in Problem identification Form Q1998-02104. On April 24,1998, while pieparing a marinelli beaker for calibration of the off gas filter monitors, a glass sphere containing xenon-133 gas was dropped and broken on the chemistry " hot" laboratory floor. The sphere contained a calculated quantity of 3.87 microcurie of gas in 37 cubic centimeters of volume. The individual who had dropped the glass immediately evacuated the hot lab, closed the door, and contacted radiation protection. The individuals in the hot lab successfully passed through the whole
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body radiation monitors. Radiation protection personnel obtained an air sample and performed radiological surveys. No airbome contamination peaks or residual contamination was found in the area of the spill, and no associated exposure was assigned to individuals in the vicinity. The exhaust from the lab area passed through the chimney and vas monitored. The individual who dropped the source was counseled and assisted in the clean up of the material. The inspectors interviewed the individual, and
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l inspected the area of the spill, and determined that the cause was primarily due to l
personal error. The inspectors noted that the licensee's immediate actions and corrective l
actions were appropriate, and indicated a clear understanding of the appropriate response to an unintentional release of gaseous radioactive materialin the presence of
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personnel.
R8 Miscellaneous Radiation Protection and Chemistry issues (92904)
R8.1 (Closed) Inspection Follow-up Item 50-254/95002-03: 50-265/95002-03: Spent Fuel Pool l
Filter. On February 22,1995, workers cutting local power range monitor strings inside the j
l fuel transfer canal accidentally contacted an underwater vacuum filter, causing the filter media to disintegrate and disperse into the Unit 1 and Unit 2 fuel pools. The licensee (
was not aware that according to the vendor, the filters would degrade after a cumulative i
radiological exposure. Corrective actions included a review of administrative and fuel i
handling procedures addressing fuel pool storage to ensure that necessary chemical,
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radiological, and physical requirements were addressed. The inspectors reviewed j
l licensee procedure Quad Cities Fuel Handling Procedure 0500-01, " Refueling Pool Inventory Control," Revision 1, and determined that it included steps which described
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objects subject to radiation damage and disintegration. The inspectors also reviewed the Fuel Hand'er's initial and continuing training program and noted that the degradation of filters due to excessive radiation exposure was described. The inspectors interviewed numerous personnel from fuel handling, radiation protection, and nuclear engineering j
disciplines, and noted that these individuals had a sufficient understanding of objects subject to radiation damage, and how to appropriately control these objects. The
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licensee's actions adequately addressed the previous weaknesses identified, and this item is closed.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on May 29,1998. The licensee acknowledged the findings presented. The inspectors asked if any proprietary information was reviewed during the inspection period. No proprietary information was used which resulted in inspection conclusions.
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PARTIAL LIST OF PERSONS CONTACTED Licensee J. Dimmette Site Vice President L. Pearce Plant Manager B. Holbrook Site Engineering Manager T. Huizenga Shift Operations Manager G. Powell Radiological Protection and Chemistry Manager (Acting)
j J. Walker Quality and Safety Assessment Manager M. Wayland Maintenance Manager
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INSPECTION PROCEDURES USED IP 37551:
Offsite Engineering l
lP 40500 Effectiveness in identifying, Resolving, and Preventing Problems IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92700:
. Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Follow-up - Engineering
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IP 92904:
Follow-up - Plant Support i
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l ITEMS OPENED, CLOSED, AND DISCUSSED
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Opened 50-254/98009-01; 50-265/98009-01 VIO negative out-of service performance trend 50-254/98009-02 VIO out-of-service equipment operated by fuel handling personnel 50-254/08009-03; 50-265/98009-03 VIO failure to initiate procedure change request 50-265/98009-04 VIO traversing incore probe activities not controlled by out-of-service program 50-254/98009-05; 50-265/98009-05 VIO poor corrective action for setpoints q
discrepancies
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50-254/98009-06; 50-265/98009-06 VIO failure to perform 50.59 evaluation i
50-254/98009-07; 50-265/98009-07 URI failure to update the UFSAR and TS Closed 50-254/97006-01; 50-265/97006-01 VIO failure to maintain procedures 50-254/97026-02; 50-265/97026-02 VIO valves reassembled improperly 50-254/96009-00; 50-265/96009-00 LER Voltage to Selected Safety-Related Loads Could Have Been Degraded 50-254/97015-00 LER Unit 1 Electrical Protection Assembly Failed l
50-254/97011-00; 50-265/97011-00 LER Unit 1 Residual Heat Removcl Service Water System Inoperable Due to 4kV l
Breaker Uncertainties 50-265/97008-00 LER Five Control Rods Did Not Receive Scram
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Time Testing
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50-254/95003-00 LER MOV breaker trip
50-254/95005-04; 50-265/95005-04 URI loss of residual heat removal capabilities l
50-254/96004-03; 50-265/96004-03 IFl electrical breaker database l
50-254/96012-08; 50-235/96012-08 IFl hydraulic lock of MOV spring pack j
50-254/96011-01; 50-265/96011-01 URI criticality monitors
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50-254/96017-01; 50-265/96017-01 URI ultimate heat sink 50-254/97008-05; 50-265/97008-05 VIO zebra mussel fouling of intake structure 50-254/93015-02; 50-265/93015-02 IFl unit shutdown to repair 2A feedwater pump 50-265/95004-00 LER condenser vacuum scram switches found out-of-tolerance 50-254/96006-06; 50-265/96006-06 IFl degraded control room humidifier 50-254/95002-03; 50-265/95002 03 IFl spent fuel pool filter I
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LIST OF ACRONYMS AND INITIALISMS USED ASME American Society of Mechanical Engineers CFR Code of Federal Regulations Comed Commonwealth Edison Company DRP Division of Reactor Projects IFl Inspection Follow-up Item
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l LER Licensee Event Report l
URI Unresolved Item VIO Violation NTS Nuclear Tracking System PORC Plant On-Site Review Committee UFSAR Updated Final Safety Analysis Report PlF Problem identification Form ESC Event Screening Committee EWCS Electronic Work Control System CARB Corrective Action Review Board Q&SA Quality and Safety Assessment TS Technical Specifications l
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