IR 05000254/1988004
| ML20151F836 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 04/12/1988 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20151F823 | List: |
| References | |
| 50-254-88-04, 50-254-88-4, 50-265-88-04, 50-265-88-4, NUDOCS 8804190017 | |
| Download: ML20151F836 (12) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION !!!
Peports No. 50-254/88004(DRP);50-265/88004(DRP)
Docket Nos. 50-254, 50-265 Licenses No. OPR-29; DPR-30 Licensee: Conrnonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: Quad Cities Nuclear Power Static-ts 1 and 2 Inspection At: Quad Cities Site, Cordova, IL Inspection Conducted:
February 7 through April 2, 1988 Inspectors:
R. L. Higgins A. D. Morrongiello Approved By:
M. A. Ring, Chief h[
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Reactor Projects Sec ion ID aire Inspection Summary Inspection on February 7 throuch April 2, 1988 (Reports No. 50-254/88004(DRP);
50-265/88004(DRP))
Areas Inspected: Routine, unannounced resident inspection of Operations, Maintenance, Surveillance, LER Review, Routine Reports, Temporary Instructions.
Administrative Controls Affecting Quelity, Radiation Control, and Outages.
Results:
In the 9 areas inspected, no violctions or deviations were identi-fied in 8 areas; one violation was identified in the remaining area (failure to perform a surveillance within the required time interval - Paragraph 4);
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however, in accordance with 10 CFR 2 Appendix C.Section V.G.1, a Notice of
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Violation was not issued. This violation was of minor safety significance, e00419o017 880412
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P1H ADOCK 05000254 O
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DETAILS 1.
Personnnel Contacted
- R. Bax, Station Manager
- T. Tamlyn, Production Superintendent
- D. Gibson, Regulatory Assurance Supervisor
- R. Hookins, Quality Assurance
- G. Tidz, Assistant Superintendent for Operations
- Denotes those present at the E.
. interview on April 5, 1988.
The inspectors also contacted ai.
interviewed other licensee and contractor personnel during the course of this inspection.
2.
Operations (71707, 93702)
The inspectors, through direct observation, discussions with licensee peisonnel, and review of applicable records and logs, examined plant operations. The inspectors verified that activities were accomplished in a timely manner using approved procedures and drawings and were inspected / reviewed as applicable; procedures, procedure revisions and routine reports were in accordance with Technical Specifications, regulatory guides, and industry codes or standards; approvals were obtained prior to initiating any work; activities were accomplished by qualified personnel; the limiting conditions for operation were met during normal operation and while components or systems were removed from service; functional testing and/or calibrations were performed prior to returning compor.ents or systems to service; independent verification of equipment lineup and review of test results were accomplished; quality control records were properly maintained and reviewed; parts, materials and equipment were properly certified, calibrated, stored, and or maintained as applicable; and adverse plant conditions including equipment malfunctions, potential fire hazards, radiological hazards, fluid leaks, excessive vibrations, and personnel errors were addressed in a timely marner with sufficient and proper co rective actions and reviewed by appropriate management personnel.
(a) Engineered Safety Features System Walkdown (71710)
During plant tours of Units 1 and 2, the inspectors walked down the accessible portions of the High Pressure Coulant Injection Systems, Reactor Core Isolation Cooling Systems, Core Spray Systems, Residual Heat Removal Systems, Standby Liquid Control Systems, Standby Gas Treatment Systems, Diesel Generators, and Station Batteries.
(b) Summary of Operations Unit 1 During the inspection period, the unit operated either at full power, on Economic Generation Control (EGC), or at reduced power in order
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to perform surveillance testing or to comply with load dispatcher
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orders, until 3/2/88, when the IB recirculation pump motor-generator set developed an oil leak. Power was reduced to 60% by reducing recirculation pump speed to minimum, and the IB recirculation pump was removed from service. The oil leak was repaired, the 18 recirculation pump was restarted, and on 3/3/88 power was increased.
The unit then operated either at full power, on EGC, or at reduced power in order to perform surveillance testing or to comply with load dispatcher orders, until 3/26/88, when the 1A recirculation pump motor generator tripped while placing the B oil heat exchanger in service and securing the A oil heat exchanger.
The cause of the trip was determined to be momentary low oil pressure which occurred while placing the B oil heat exchanger in service.
The procedure has been revised to avoid this occurrence in the future. Power was reduced to 47% by reducing the speed of the 18 recirculation pump to minimum as soon as the 1A recirculatior, pump motor generator set tripped.
The 1A recirculation pump was restarted, power was raised and the unit was placed back on EGC on 3/26/88.
For the remainder of the inspection period Unit 1 operated either at full power, on Economic Generation Control (ECC), or at reduced power in order to perform surveillance testing or to respond to load dispatcher orders. As of the end of the inspection period the unit had operated at power for 89 consecutive days.
Unit 2 During the inspection perioc', the unit operated either at full power, on Economic Generation Control (EGC), or at reduced power in order to perform surveillances or to comply with load dispatcher orders, until power was reduced to 25% on 3/4/88 due to malfunctions of tLe 2A and 2B traveling screens.
The traveling screens were repaired and load was increased to 1065 on 3/7/88.
Unit 2 continued to operate either at full power, on EGC, or at i
reduced power to perform surveillance testing or comply with load
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l dispatcher orders, until low vacuum necessitated a power reduction on 3/10/88. The low vacuum was determined to be caused by a leak from l
the 2C3 feedwater heater.
The heater was isolated, the leak patched, j
and the unit continued to operate, but with a maximum power limit of 95%.
Unit 2 continued to operate either at the reduced power limit of 95%,
on EGC, or at reduced power in order to perform surveillances or to comply with load dispatcher orders, until 10:40 PM on 3/19/88, when a packing leak on the 28 feedwater regulating valve necessitated a rapid power reduction. Water from ae packing leak shorted contacts in the high reactor vessel level relays located in buses 21 and 22, causing the relays to actuate.
This caused a turbine trip, which caused a reactor scram due to control valve fast closure at 1:23 AM on 3/20/88.
For a more detailed narrative of this event refer to paragraph 2.(f).
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The 28 feedwater regulating valve was repaired, the flooded components dried out, and Unit 2 rod withdrawal to criticality began at-1:52 AM on 3/21/88. Criticality occurred at 4:27 AM and Unit 2 was connected to the electrical grid at 3:45 PM on 3/21/C8.
For the remainder of the report period, the unit was either at the reduced power limit of 95%, on EGC, or at reduced power in order to perform surveillan;es or to comply with load dispatcher orders. As of the end of the inspection period the unit had operated at power for 12 consecutive days.
(c) Unit 2 HPCI Inoperable On February 23 at 0945 hours0.0109 days <br />0.263 hours <br />0.00156 weeks <br />3.595725e-4 months <br /> HPCI was declared inoperable when the breaker supplying power to the HPCI room cooler failed.
The licensee began the compensatory testing required by Technical Specifications in parallel with repairing the breaker. The cause of the breaker failure was a failed transformer.
The transformer was replaced and the room cooler was returned to service the iame day at 3:30 P.M.
The control transformer failure appears to be due to end of life.
(d) Unit 2 RCIC Inoperable On March 1, while performing the RCIC monthly operational test, RCIC failed to achieve test pressure. At 11:00 A.M. RCIC was declared inoperable and preparations were made to test HPCI as required by Technical Specifications. HPCI was tested satisfactorily. The reason that RCIC did not achieve test pressure was due to the governor valve. A new governor valve was installed, and RCIC was returned to service on 3/2/88.
(e) Standby Gas Treatment System Inoperable On March 1 at 3:50 P.M. an Equipment Attendant discovered that the intake bell for the Unit 2 Standby Gas Treatment System was blocked l
by plastic sheeting which he immediately removed.
Since an l
initiation signal from Unit 2 would have rendered both trains
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inoperable, the licensee declared the SBGTS inoperable and notified
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the NRC via the ENS.
The sheeting was installed sometime during the l
day shift on March 1st by contract painters.
l (f) Unit 2 Reactor Scram At 10:40 PM on 3/19/88, with Unit 1 on economic generation control (EGC) between 88% and 97% power and Unit 2 on EGC between 85% and 91% power, water was discovered spraying from the packing on the 28 feedwater regulating valve (FWRV) on Unit 2.
The shift foreman attempted to tighten the packing but the packing was already fully tightened and could not be tightened any further.
The Unit 2 nuclear station operator (NS0) adjusted the 2A FWRV and the FWRV bypass valve, and took the unit off EGC at 87% power, in order to reduce
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leakage.
This action redurd the packing leak to a wisp of steam.
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At 12:55 AM on 3/20/88 the shift foreman reported that the packing leak had increased appreciably. The Unit 2 NS0 reduced recirculation pump speed to minimum to reduce power in order to isolate the leaking 2B FWRV. At 1:10 AM spurious annunciator alarms began to be
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received, and at 1:16 AM a shutdown of Unit 2 was begun. At 1:23 AM the Unit 2 main turbine tripped, causing Unit 2 to scram from 44%
power. A group I isolation occurred, which caused all main steam isolation valves to shut.
It is suspected that vibration from the turbine trip affected the instrument rack containing the low main steam line pressure switch, resulting in a spurious group I isolation. Other than the spurious group I isolation, no abnormalities were noticed during the scram. At 2:15 AM the NRC Emergency Operations Center was notified.
The packing for the 28 FWRV is believed to have failed because the valve operated for an extended period of time with the packing fully compressed. The licensee admits that the packing should have been replaced prior to the time that the packing was fully tightened. The licensee has stroked the valve, polished the stem with emery paper, and replaced the packing. The 2B FWRV was placed back in service when Unit 2 was restarted. A maintenance outage for Unit 2 will begin on 4/10/88, and the 28 FWRV is scheduled to be overhauled during that outage.
Extensive surveys revealed no contamination problem.
Steam caused several spurious fire alarms; the licensee verified all fire alarms working properly prior to restarting Unit 2.
Rod withdrawal for criticality began at 1:52 AM on 3/21/88, criticality was attained at 4:27 AM, and Unit 2 was reconnected to the electrical grid at 3:45 PM on 3/21/88.
The turbine trip was caused by the actuation of the high reactor vessel level relays located in 4160 volt non-essential buses 21 and 22.
These buses are located on the floor below the 28 FWRV and were drenched with water.
The relays actuated because of water shorting electrical contacts; reactor vessel water level never approached the trip setting of +48 inches.
The licensee removed the water from the buses and did not restart Unit 2 until the water had been removed and all electrical components were shown to be undamaged.
No violations or deviations were identified in the review of this area.
3.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety related and non-safety related systems and components listed below were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specifications.
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The following items were considered during this review:
the limiting conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; acti<tities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention procedures were followed. Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance.
Portions of the following activities were observed / reviewed:
(1) Maintenance of the 8 fire diesel.
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(2) Repair on secondary containment doors.
(3) Vibration test of the service air compressor bladet (4) Maintenance of the 28 feedwater regulating valve.
(5) Maintenance on the 1C reactor feed pump.
(6) Mechanical Maintenance installing the 1A CRD pump rotor.
(7)
Instrument Maintenance repairing the Unit 1 Traveling Incore Probe instrumentation.
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(8) Mechanical Maintenance repairing traveling screens.
(9) Electromatic Relief valve testing.
(10) Maintenance on the Unit 2 condensate booster pump.
(11) Repair and reconstruction of the instrument air compressor.
l (12) Repair and reconstruction of the feedwater check valve.
(13) Testing of the rebuilt Versa valves.
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No violations or deviations were identified in the review of this area.
4.
Monthly Surveillance Observation (61726)
The inspectors observed Technical Specifications-required surveillance testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that
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limiting conditions for operation were met, that removal and restoration of the affect J components were accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed
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by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
Portions of the following activities were observed / reviewed:
(1) Nuclear Engineer's daily surveillance on Unit 1.
(2) Unit 1 HPCI monthly and quarterly surveillances from the control room.
(3) Unit 1 HPCI valve operability test from the control room.
(4) RCIC monthly and quarterly surveillances from the RCIC room.
(5) Adjustment of the rod worth minimizer on Unit 2.
(6) LPRM calibration on Unit 1.
(7) Main steam line high flow surveillance on Unit 2.
(8) Main steam line low pressure calibration on Unit 2.
(9) Vibration data collection on c Unit 1 Motor-Generator Set.
(10) Control room portion of the HPCI flow test.
One violation concerning surveillances which were perfonned late was identified by the licensee.
The surveillances were weekly APRM high flux surveillances and main steam line high radiation surveillances (QIS 60-1)
for Unit 1 and Unit 2 which were due to be performed on 3/21/88 but which were not performed until 3/25/88.
i The oversight was discovered at 4:00 P.M. on 3/25/88 by personnel in the Instrument Maintenance Department.
The surveillances were immediately begun, and were completed at 4:30 P.M. on 3/25/88. The Plant Manager declared this to be a Potentially Significant Event (PSE), and a PSE report was prepared on 3/29/88. The Plant Manager has assigned a task force to review the existing Surveillance program to identify the root cause and ensure that corrective actions are instituted throughout the station to ensure no required surveillances are missed in the future. An LER is being prepared (LER 88-006) and will be issued within the 30 day i
time limit for issueing LERs.
The missed surveillances are considered a violation of Technical t
l Specification 4.1.A, but because this violation met the five (5)
l criteria of 10 CFR 2 Appendix C Section V.G.1 (the violation was licensee I
identified; it was a severity level IV or V; it is expected to be l
reported within the required time frame; prompt corrective action was taken to correct the problem and prevent recurrence; and it was not a i
l violation that could reasonably be expected to have been corrected by the licensee's corrective action for a previous violation), no Notice I
of Violation will be issued.
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One violation was identified in this area, however, in accordance with 10 CFR 2 Appendix C, Section V.G.1, no Notice of Violation will be issued.
5.
LER Review (92700)
(1) Unit 1 (a) (0 pen) LER 880'11, Revision 00: Two Contractor Personnel Overexposures in the Fourth Quarter of 1980 Due to Dosimeter Inaccuracy.
This item is being investigated by regional based inspectors.
(b) (0 pen)LER88004, Revision 00: Reactor Head Vent Line Outside Safety Analysis Criteria for Allowable Stress Due to Design Error.
This item is beir.g investigated by regional based inspectors.
(c) (Closed) LER 88005, Revision 00: Control Room Ventilation Isolations Due to Personnel Error and Cause Not Determined.
This item was discussed in Inspection Report 254/87033 (DRP) and resulted in a Notice of Violation being issued.
(d) (Closed) LER 87003, Revision 01: Unit 1 RCIC Inoperable Due to Flow Controller Failure Caused by Loose Solder Joint.
This supplement reports the root cause for RCIC failure was a loose cold solder joint in the setpoint tape chassis section of the electronic controller. All other flow controllers associated with either HPCI or RCIC will be inspected and repaired if necessary at the next opportunity.
(e)
(Closed)LER87032, Revision 00: RCIC Inoperable due to check valve 1-1301-50 stuck closed because of worn parts.
This item was discussed in Inspection Report 254/87033(DRP).
(2) Unit 2 (a)
(Closed)LER87021, Revision 00: Standby Coolant Supply System Outside Safety Analysis Report Due to Position Indication Short Circuit.
On December 30, 1987, Quad Cities Unit 2 was in the run mode at 89 percent of rated core thermal power. At 12:25 A.M., the Nuclear Station Operator (NS0) received a "Service Water Valve to Condenser open" alann and lost light position indication for the motor operated (MO) condenser service water supply (Standby Coolant Supply) valve 28, M02-3902. At the same time, a report
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a of smoke in the Turbine Building was received. The Unit 2 Equipment Attendant (EA) traced the smoke to Motor Control Center (MCC) 27-1, cubicle L-4, which contains the control circuitry for M02-3902.
The cubicle was deenergized and the Electrical Maintenance Department was notified to investigate the problem.
The root cause that led to the event was that the "closed" indicating light socket for M02-3902 shorted out.
This short circuit created an overcurrent to the control transfonner. The control transformer was eventually destroyed. Thus, remote manual control of the valve by the NS0 from the control room was lost.
The valve was designed to be manually operated (opened) from the control room, and therefore was declared as not meeting the design basis of the Quad Cities final safety analysis report (FSAR) at the time of the event. However, since the valve is located in an accessible area and since it can be hand cranked open, if needed, the valve was considered operable. This system is only used when all other Emergency Core Cooling Systems have been exhausted or become unavailable.
A work request was written to investigate and repair the indicating light socket and equipment contained in the cubicle.
The shorted light socket was replaced. The cubicle was replaced with a spare cubicle, the cubicle wiring was verified and the breaker and overload heater assemblies were trip checked.
One violation was identified in Inspection Report 245/87033 in this area. No additional violations or deviations were identified in the review of this area.
6.
Review of Routine and Special Reports (90713)
The inspectors reviewed the Monthly Performance Reports for the months of January and February,1988.-
No violations or deviations were identified.
7.
Temporary Instruction Followup (25598)
A Temporary Instruction was issued which provided guidance in assessing BWR licensees' activities to ensure scram discharge volume capability in accordance with their long term commitments concerning Multiplant Action
Item B-58.
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(a) The scram discharge headers shall be sized in accordance with GE
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OER-54 and shall be hydraulically coupled to the instrumented l
volume (s) in a manner to permit operability of the scram level instrumentation before loss of system function.
This item was covered under Appendix 8 to the Generic SER.
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(b) Level instrumentation shall be provided for automatic scram initiation while sufficient volume exists in the SDV.
This automatic scram does axist for high instrument volume water level.
(c)
Instrumentation taps shall be provided on the vertical Instrument Volume (IV) and not on the connected piping.
It was verified that safety-related IV level instrument taps are on the IV only and not on connected piping above or below the IV.
(d) The scram instrumentation shall be capable of detecting water accumulation in the IVs assuming a single active failure in the instrumentation system or the plugging of an instrument line.
It was verified that the system configuration precludes a single line plugging or other single failure causing failure of the instruments to detect water in the IV.
(e) Vent ar.d drain functions shall not be adversely affected by other system hterfcces. The objective of this requirement is to preclude water backup in the suam IV, which could cause a spurious scram.
Tne licensee's analysis was reviewed and vent and drains are not adversely affected by other system interfaces.
(f) The power-operated vent and drain valves shall close under loss of air and/or electric power. Valve position indication shall be provided in the control room.
A review of current drawings and visual inspection confirmed that the IV vent and drain valves close on loss of air and that valve position is indicated in the control room.
(g)
Instrumentation shall be provided to aid the operator in the detection of water accumulation in the IVs before scram initiation.
A visual faspection confirmed that an alarm exists in the control room for the presence of water in the IV and that procedures exist i
for operator action in the event water is detected in the IVs.
(h) Vent and drain line valves shall be provided to contain the scram discharge ' ':r with a single active failure and to minimize operationat uposure, i
Redundant vent and drain valves exist and a single active failure will not defeat isolation of the vent and drain valves.
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(1) Vent and drain valves shall be periodically tested.
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Procedures exist that test the operability of the IV vent and drain valves and that they close in less than 30 seconds.
(j) Level detection instrumentation and verifying level detection instrumentation shall be periodically tested in place.
These procedures are in existance.
(k) The operability of the entire system as an integrated whole shall be demonstrated periodically and during each operating cycle by demonstrating scram instrument response and valve function at pressure and temperature at approximately 50% control rod density.
The operability of the entire system as a whole is demonstrated during each operating cycle by virtue of a manual scram at about 10% power while shutting down. However, there are no Technical Specification requirements for this scram.
No violations or deviations were identified in the review of this area.
8.
Administrative Controls Affecting Quality (42700)
Several drawings and procedures were checked for adequacy and accuracy.
Errors found were brought to the attention of the licensee and are in the
process of being corrected. No violations or deviations were identified.
9.
Radiation Control (71709)
Periodic inspections of plant radiological control conditions were made during the inspection period.
Isolated instances of minor deficiencies l
were found and promptly corrected by plant personnel. No violations or deviations were identified.
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10. Outages (60710, 86700)
The Outage Planning department has made extensive use of work planning programs and meetings with the various work groups in order to efficiently coordinate work activities during the upcoming Unit 2 refueling outage
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scheduled to begin on 4/10/88.
The outage is scheduled to be ten weeks, which is shorter than the planned duration of previous outages. A shortened outage will increase the importance of planning done by the
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11. Violations For Which A "Notice of Violation" Will Not Be Issued l
The NRC uses the Notice of Violation as a standard method for formalizing
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the existence of a violation of a legally binding requirement. However, because the NRC wants to encourage and support licensee's initiatives for self-identification and correction of problems, the NRC will not
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generally issue a Notice of Violation for a violation that meets the tests of 10 CFR 2, Appendix C, Section V.G.I.
These tests are:
(1) the violation was identified by the licensee; (2) the violation would be
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categorized as Severity Level IV or V; (3) the violation was reported to the NRC, if required; (4) the violation will be corrected, including measures to prevent recurrence, within a reasonable time period; and (5)
it was not a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation.
A violation of regulatory requirements identified during the inspection for which a Notice of Violation will not be issued is discussed in Paragraph 4.
11. ExitInterview(30703)
The inspectors met with licensee representatives (denoted in Paragraph.1)
throughout the inspection period and at the conclusion of the inspection
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on April 5,1988, and summarized the scope and findings of the inspection activities.
The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any such documents / processes as proprietary.
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