IR 05000254/1987027
| ML20237C218 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 12/16/1987 |
| From: | Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20237C208 | List: |
| References | |
| 50-254-87-27, 50-265-87-27, NUDOCS 8712210139 | |
| Download: ML20237C218 (15) | |
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NUCLEAR REGULATORY COMMISSION
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REGION III
Reports No. 50-254/87027(DRP): 50-265/87027(DRP)
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' Docket Nos. 50-254, 50-265 Licenses No. DPR-29; DPR-30 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: QdadCitiesNuclearPowerStation, Units 1and2 Inspection At: Quad C', ties Site, Cordova, IL
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Inspection Ckr,' ducted.1 October 4 through December 5, 1987
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Inspectors:
R. L. Higgins A, D. Morrongiello
/ 7//6 d7 Approved By:
M.
. Ring, Chief
, Projects Section 1C Date
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u Inspelet o'n Summary x
Inspection on October throuch'Decsmber 5, 1987 (Reports No. 254/870027(DRP);
50-265/E7027(DRP))
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Areas f 5 ected:
Routine, unannounced resident inspection of Operations, Maintenance, Surveillance, LER Review, Routine Reports, Administrative Controls Af fect ieg, Quality, Radiation Control, and Outages.
R,e, sui ts; In the-areas inspected, no violations requiring the issuance of a Notice of Vidation we're identified other than those which have already been
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der,tioned in inspection reports 50-265/87025 and 50-265/87031.
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DETAILS l
1.
Personnnel Contacted
- R. Bax, Plant Manager
- T. Tamlyn, Production Superintendent
- R. Robey, Services Superintendent
- M. Kooi, Regulatory Assurance Supervisor
- D. Gibson, Quality Assurance Manager
- Denotes those present at the exit interview on December 7, 1987.
The inspectors also contacted and interviewed other licensee and contractor personnel during the course of this inspection.
2.
Actions on previous Items (Closed) Open Item 254/86013-03; 265/86012-02: Open Item to track establishment of station procedures for fire watch.
The licensee has written procedures for establishing a fire watch fcr both Non-Technical Specification and Technical Specification related items.
This item is considered closed.
3.
Operations (71707, 93702)
The inspectors, through direct observation, discussions with licensee personnel, 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 remcved from service; functional testing and/or calibrations were performed prior to returning components 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 eouipment 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 manner with sufficient and proper corrective actions and reviewed by appropriate management personnel.
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_(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 Coolant Injection Systems, Reactor Core Isolation Cooling Systems, Core Spray Systems, Residual Heat Removal Systems, Standby Liquid Control Systems, Standby Gas Treatment Systems, and Diesel Generators.
(b) Summary of Operations Unit 1 Throughout the inspection period Unit I was in a scheduled refuel outage.
Unit 2 During the inspection period, the unit operated either at full power, on Economic Generation Control (EGC), or at reduced power in order to perform surveillance or to comply with load dispatcher orders, until the reactor scrammed at 1959 on October 19, 1987.
At that time, with Unit 2 on EGC at approximately 90% power, an equipment operator attempted to rack out the breaker for the 2A Circulating Water Pump on the 4160 volt nonessential Bus 23. The procedure which the equipment operator used contained errors, and therefore was determined to be in violation of NRC requirements
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stated in 10 CFR 50 Appendix B.
This violation is contained in
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inspectico report 50-265/87025. After locating the cubicle for the 2A Circulating Water Pump on Bus 23, the equipment operator turned around and put on his protective clothing (rubber gloves, rubber apron and face shield).
He turned around and faced Bus 23 again, l
this time facing the adjacent cubicle which contained the breaker for the 2A Control Rod Drive Hydraulic Pump, which was operating at the time. He racked out the breaker for the 2A Control Rod Drive Hydraulic Pump, which created a fire ball, destroying the breaker for the 2A Control Rod Drive Hydraulic Pump and deenergizing Bus 23
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at 19:59:25. Among the components lost when Bus 23 deenergized were i
the 480 volt nonessential Buses 25 and 26, the 4160 volt essential Bus 23-1, the 480 volt essential Bus 28, and Condensate and Condensate Booster Pumps 2A and 2B. The equipment operator was shaken but unhurt.
The loss of the two Condensate and Condensate Booster pumps caused the Reactor Feed Pumps to trip on low suction pressure, resulting in a low reactor vessel level scram at 19:59:33. At 20:00:28 the RCIC and HPCI pumps received start signals because reactor vessel level dropped to the low low level setpoint of -59 inches. At 20:00:37 a Group I isolation occurred also due to the low low level setpoint being reached. At 20:00:54 RCIC reached full flow. At 20:01:00 the low low level signal reset, so the HPCI pump, which had not attained rated speed, also reset. At 20:01:11 the B Reactor Feed Pump was restarted and began to feed water into the reactor vessel. Because
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of the lost electrical buses, the reactor feedwater regulation valves could not be controlled by the operator, resulting in reactor vessel 14/e1 reaching +48 inches at 20:02:42, which in turn caused the RCIC and Reactor Feed Pump B to trip on high level.
RCIC was i
subsequently restarted to' control reactor vessel level.
When Bus 23-1 deenergized, diesel generator 1/2 started automatically and reenergized Bus 23-1 and Bus 28, which receives its power from Bus 23-1.
Cross-tie breakers were manually closed to restore power to all electrical buses except Bus 23.
The NRC Emergency Operations Center was notified at 21:17. An Unusual Event was declared at 21:30, and the Nuclear Accident Reporting System notifications were made at 21:32. The one and one half hour delay between the occurrence of the event and the declaration of an Unusual Event is considered a violation and was so documented in inspection report 50-265/87031.
Shutdown cooling was established at 23:45 and Unit 2 was placed in cold shutdown with all buses energized from normal offsite power except Bus 23-1, which was supplied by diesel generator 1/2, and Bus 23, which was tagged out.
A member of the Division of Reactor Safety assisted the Residents in determining that HPCI functioned properly and in following the licensee's evaluation of the event, repair of the damage, and corrective actions to ensure that similar personnel errors are avoided in the future.
Bus 23 was repaired and Unit 2 was restarted on 11/2/87.
Criticality occurred at 1602 CST on 11/2/87 and Unit 2 was connected to the electrical grid at 0945 CST on 11/3/87.
For the remainder of the report period, the unit was either at full power, on Economic Generation Control (EGC), or at reduced power in order to perform surveillance or to comply with load dispatcher orders. As of the end of the inspection period the unit had operated at power for 33 consecutive days.
(c) Electromatic Relief Valve Setpoint Exceeding Limits On October 17 at 2140 hours0.0248 days <br />0.594 hours <br />0.00354 weeks <br />8.1427e-4 months <br /> while performing a routine surveillance on the electromatic relief valve pressure switches on Unit 2, the instrument mechanics fcund one switch that opened at 1117 psig, exceeding the Technical Specification limit of 1115 psig. The pressure switch was immediately recalibrates and tested i
satisfactorily.
l (d) Standby Gas Treatment System Autostart At 0600 CST on 11/1/87 with Unit 2 in cold shutdown and Unit 1
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defueled, the circuit breaker supplying the 480 VAC essential bus 29 from the 4160 VAC essential bus 24-1 tripped, resulting in the deenergization of bus 29.
Since bus 29 was supplying electrical
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power for'the 480 VAC essential-bus 28, bus 28 also deenergized.
This caused the standby gas treatment system to start and the control room ventilation system to shift to the recirculation mode.
The cause for the circuit breaker supplying bus 29 to trip was unknown at the time, but was later determined to be caused by overcurrent due to the extra load on bus 29 because it was supplying
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bus 28. No apparent damage was found,-so the circuit breaker was reclosed, buses 28 and 29 were reenergized, the standby gas treatment system was secured and placed in standby, and the control room ventilation was returned to normal. At 0820 CST on 11/1/87 the NRC Emergency Operations Center was notified.
The electrical system was subsequently returned to the normal configuration in which the 4160 VAC essential bus 23-1 supplies bus 28.
The cause of the bus trip appears to have been an overloading of the 480 volt circuit breaker.
Prior to the event the load was approximately 1740A. The trip set point for the breaker is 2000A.
When an air compressor automatically 10aded to the bus an additional 175A load was added and the circuit breaker tripped.
'The licensee is revising procedures to impose an 80 percent limit on the 480 volt feed breaker capacity.
The Resident Inspectors will review and follow up on the licensee's corrective actions.
(e) Offgas Timer Inoperative At 1030 CST on 11/2/87, with Unit 2 in cold shutdown and Unit I defueled, the off gas timer for Unit'2 was determined to be inoperative.
The off gas timer functions to isolate the condenser off gas from the gaseous waste discharge chimney after a 15 m..ute time delay should the offgas radiation detectors detect a high level of radioactivity in the off gas line upstream of the 15 minute holdup volume. The timer should have actuated on 11/1/87 when buses 28 and 29 were deenergized. Whether it did so and reset when power was restored was unclear because no action would occur due to the unit being in cold shutdown.
Further tests conducted on 11/2/87 at 1030 demonstrated that the off gas timer was inoperative.
The defective off gas timer was subsequently replaced. The NRC Emergency Operations Center was notified at 1325 CST on 11/2/87.
(f) RCIC Inoperable At 0020 CST on 11/3/87 the inboard steam supply valve for the Unit 2 Reactor Core Isolation Cooling (RCIC) turbine could not be closed.
The outboard steam isolation valve was closed and the RCIC turbine was declared inoperable.
In accordance with Technical Specification 4.5.E.2 the High Pressure Coolant Injection (HPCI) pump was demonstrated to be operable by immediately performing a surveillar.ce test. The cause for the inboard steam supply valve not shutting was determined to be sticky contacts.
Repairs were made by replacing
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m the auxilliary contacts like-for-like.
RCIC was tested and declared operable the.same day.
Since similar auxilliary contact problems have' occurred, the licensee initiated an Action Item Record to resolve this. problem.
(g).-. Reactor ' Startup At 1145 CST on 11/2/87-control rods were withdrawn to restart Unit 2 after a two week long outage caused by an operator mistakenly racking out a 4160 V circuit breaker which was closed. Criticality occurred at 1602 CST on 11/2/87 and Unit 2 was connected to the electrical grid at 0954 CST on 11/3/87. 'Two abnormalities occurred during the startup: the RCIC turbine was declared inoperable and rod P-11 continually drifted back into its fully ' inserted position i
after being withdrawn and was consequently electrically deenergized in the' fully' inserted position. Both the RCIC turbine and rod P-11 were subsequently repaired and returned to service.
(h) HPCI Inoperability and Inadvertent Iniection into Vessel At 1850 CST on 11/3/87, with Unit I defueled and Unit 2 at 45%
power, the Unit 2 HPCI system was purposely placed in an inoperable-
condition by blocking closed the HPCI pump discharge valve to the
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reactor vessei. This action was taken in order to perform the HPCI
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Fast' Start Test without.actually injecting into the reactor vesse'.
At 1910 CST on 11/3/87.the HPCI pump discharge valve to the reactor vessel opened, injecting water into the reactor vessel. The reactor operator immediately manually tripped the HPCI turbine; no reactivity insertion was observed, but reactor vessel level did increase. The cause of the HPCI pump discharge valve opening was determined to be valve blocks inadvertently placed on the wrong contacts. The valve blocks were transferred to the proper contacts and the Fast Start Test was repeated.several more times without the HPCI pump discharge valve to the reactor vessel opening inadvertently.
At 1925 CST the Fast Start Test was repeated, but the HPCI turbine tripped when the auxiliary oil pump tripped.
The auxiliary oil pump j
pressure settings had been adjusted in order to comply with new j
manufacturer recommendations; the pressure settings were returned to
their original settings prior to repeating the Fast Start Test. At
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0140 CST on 11/4/87, while prewarming HPCI in preparation for
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another Fast Start Test, HPCI automatically isolated due to high
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room ternperature caused by slight steam weepage around the steam seals on the pump side of the turbine.
HPCI isolated a second time at 0309 CST due to high room temperature. An air mover was placed in the room to disperse the steam which had accumulated in the vicinity of some of the HPCI room's temperature detectors. The HPCI Fast Start Test was successfully conducted at 0600 CST on 11/4/87.
The steam weepage which had caused the high temperature in the HPCI room occurred when steam was applied to the turbine during turbine
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warmup; the steam seals seated properly durir.g the Fast Start Test and are expected to properly seat whenever the HPCI turbine would be called upon to start in an emergency.
The NRC Emergency Operations Center was notified of the removal of HPCI from service at 2205 CST on 11/3/87, of the inadvertent injection of HPCI into the reactor vessel at 2210 CST on 11/3/87, and of the HPCI isolation at 0747 CST on 11/4/87.
The notification at 0747 of the HPCI isolation which had occurred at 0140 was twe hours and seven minutes in excess of the time limit prescribed in 10 CFR 50 72 and is considered a violation.
Because this violation satisfies the five criteria spe ified in 10 CFR 2 Appendix C Section V.A, no Notice of Violation will be issued.
(i) Piping Supports Fail to Meet FSAR Requirements At 1645 CST on 11/16/87 the Commonwealth Edison BWR engineering group informed Quad Cities that two RHR piping supports and one HPCI piping support on Unit I did not meet FSAR requirements but did meet operability requirements. The problems were discovered during the course of an on going piping verification program being performed by Nutech. To bring these piping supports into cumpliance with FSAR requirements requires that cam springs be reset on the RHR lines and a new piping support be installed on the HPCI relief line to the torus suction line from the oil ' cooler supply line. The piping verification program is continuing.
At 1740 CST on 11/16/87 the NRC Emergency Operations Center was informed.
The appropriate Regional Inspectors were informed of the problems with the RHR and HPCI piping supports. The licensee has modified these piping supports to bring them into compliance with FSAR requirements.
The piping verification program is still in progress and will be closely scrutinized by the Resident Inspectors and the appropriate Regional Inspectors.
(j) Control Room Habitability Concern Control Room habitability studies assumed that the charcoal banks in the Standby Gas Treatment System were 99% efficient. Technical Specification 3.7.B.2.a.3 requires that these charcoal banks be at least 90% efficient. Several times during the past several years surveillance tests of these charcoal banks demonstrated their efficiency to be greatnr than 90% but less than 99%, calling into question the habitability of the control room should an accident occur.
The NRC Emergency Operations Center was notified at 1530 CST on 11/25/87.
l The resident inspectors will follow up to ensure the disparity l
between the requirements of Technical Specifications and the control room habitability studies is resolved.
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No violations or deviations other than those in paragraphs 3(b) and (h)
were identified.
I 4.
Monthly Maintenance Observation'(62703)
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Station resintenance activities of safety related and non safety related l
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.
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 l
inspected as applicable; functional testing and/or calibration $ were
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performed prior to returning components or systems to service; quality control records were maintained; activities 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 j
related equipment maintenance which may affect system performance.
The following activities were observed / reviewed:
(1) Po' ions of work on various valves associated with the Unit 1 o
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(2) Portions of refuel cycle overhaul of 4KV breakers-.
r (3) Portions of heat trace installation-on Unit 1 SBLC System.
i (4) Portions of Unit 2 0xygen Analyzer pump repair.
(5) Portions of the repair of bus 23.
(6) Portions of the weld overlay repair work.
No violations or deviations were identified.
5.
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 affected components were accomplished; that test results conformed with Technical Specifications and procedure requirements and were reviewed 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.
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The following activities were observed / reviewed:
.(1)_ Portions of logic testing of EHC controls on Unit 1.
(2) Portions of Control Room HVAC 00P testing.
(3) Portions of Unit I drywell vent valve LLRT.-
(4) Portions of construction test for.new trackway fire suppression system.
_(5) HPCI. Fast Start Test and the RCIC Fast Start Test on Unh 2.
(6) Portions of resistance measurements on the main venerator.
(7,) Portions of the primary containment ILRT.
(8) Portions of'the test of the electromatic relief valves on Unit 2.
(9) Portions of the control rod friction testing on Unit 1.
(10) Portions of the control rod timing test on Unit 1.
(11) Portions of the weld ultrasonic testing.
(12) Portions of the hydrostatic test on Unit 1.
No violations or deviations were identified.
6.
LER Review (92700)
.(1) Unit 1 (a) ('Open) LER 87018, Revision 00:
IB Recirculation Motor Generator Field Breaker Failure to Trip - Apparent Component Failure.
On September 13, 1987,, Quad Cities Unit One was in the shutdown mode at 0 percent thermal power. At 0228 hours0.00264 days <br />0.0633 hours <br />3.769841e-4 weeks <br />8.6754e-5 months <br />, while attempting to shutdown the IB Recirculation Motor Generator Set
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for inspection, it was found that the associated field breaker
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failed to trip. The trip coil was found burned out. The i
armature in the closing linkage was found to be binding and had
to be freed by operating personnel.
The recirculation MG Set field breakers are involved in the
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Anticipated Transient Without a Scram (ATWS) system and are designed to trip upon either a low low reactor water level or l
high reactor pressure. The cause and appropriate corrective l
action for this failure will be determined following General Electric Company testing, and a supplemental report will be issued.
This issue is being followed by a Region based inspector.
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(b) '(Closed) LER 87020, Revision 00:
Safety Features Actuation Caused by.Possible Relay Coil Installation Error.
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On October 6, 1987, Quad Cities Unit I was in the shutdown mode with the reactor defueled. At 1303 hours0.0151 days <br />0.362 hours <br />0.00215 weeks <br />4.957915e-4 months <br />, an Engineered ~ Safety Feature (ESF) actuation occurred from the Refuel Floor Radiation. Monitor System; the control room ventilation switched-to 100 percent recirculation, Unit 1 and 2 Reactor Building Ventilation automatically-isolated, and a Standby Gas Treatment train automatically started.
The coil in relay 1-1705-106 (IA Refuel Floor Radiation Monitor Downscale Relay) had been replaced on October 1, 1987, and it appears that the relay was damaged (bent coil. tab) during the coil: replacement.
Post maintenance testing only covered coil testing and not s
contact functioning which would have prevented this occurrence.
' Future coil replacement will involve contact functional testing.
(c) (0 pen) LER 87019, Revision 00:
Failure of Unit 1 As Found Integrated Leak Rate Test.
This item is being followed by a region based inspector.
(it) (Open) LER 87016, Revision 00:
Leak Rate from all valves and penetrations on Unit 1 in excess of Technical Specification Limit.
This item is being followed by a region based inspector.
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(e) (0 pen) LER 86001, Revision 00:
Leak Rate From All Valves and Penetrations in Excess of Technical Specification Limit.
This item is being followed by a region based inspector.
(f) (Closed) LER 87022, Revision 00:
Reactor Scram While Shutdown
- Neutron Monitor Spiked High High.
This item is discussed in paragraph 11.c.
(2) Unit 2 (a) (Closed) LER 87018, Revision 00: HPCI Auto Isolation due to High Temperature in the HPCI Room.
This item is discussed in paragraph 3.(h).
(b) (Closed) LER 87017, Revision 00: High Pressue Coolant Injection During Auto Initiation Test due to Personnel Error.
This item is discussed in paragraph 3.(h).
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E-(c) (Closed) LER 87015, Revision 00:'
Failure of the Offgas
' Isolation Timer due to Motor Fatigue did not Allow the'Offgas y
System'to Isolate.-
On November 2, 1987, Quad Cities Unit Two was 1n the shutdown
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mode at 0 percent reactor thermal power. At 1030 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.91915e-4 months <br /> the offgas timer was declared ir. operable following testing performed by I.nstrument Maintenance because the offgas isolation did not occur when the timer timed out.
This problem had been identified on November 1,1987 during a loss of buses 28 and 29 (described in LER 265/87014, Revision.00). At 1145 hours0.0133 days <br />0.318 hours <br />0.00189 weeks <br />4.356725e-4 months <br />, the Steam Jet Air Ejectors (SJAE) were isolated and taken out of service to prevent pcssible radioactive releases to the atmosphere.
The cause of this event is equipment failure due to motor end-of-life. The timer motor runs continuously and therefore has been in operation for approximately fifteen years..The Unit 2 offgas timer was replaced with the Unit 1 (currently in a refuel outage) timer and functionally tested satisfactorily.
Due to this occurrence, Action Item Record (AIR) 4-87-19 has been initiated to rcmedy the problem of timer motor failure with no method of failure. identification.
Efforts will be directed at a possible alarm circuit to indicate when the timer motor.has failed or a possible modification to replace the timer with one that does not require the motor to run continually.
This item is also discussed in paragraph 3.(e).
(d) (Closed) LER 87013, Revision 00:
Reactor Scram and Emergency System Initiation caused by Operator Error on Wrong Equipment.
This item is discussed in paragraph 3.(b).
(e) (Closed) LER 87016, Revision 00:
Reactor Core Isolation Cooling Inoperable Steam Supply Valve Auxilliary contact Binding.
This item is discussed in paragraph 3.(f).
(f) (Closed) LER 87014, Revision 00:
480 Volt Bus 29 Circuit Breaker Trip due to an Apparent Overload Cause Safety Feature Actuation.
This item is discussed in paragraph 3.(d).
(g) (0 pen) LER 86015, Revision 00:
Failure of Unit 2 Integrated Leak Rate Test due to Leakage Through the Drywell Head Gasket.
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This item is being followed by region based inspectors.
7.
Review of Routine'and Special Reports (90713)
The inspectors reviewed the Monthly Performance Reports for the months of September and October.
No violations or deviations were identified.
8.
Generic Letters (92703)
(1) Generic Letter 8706: Testing of Pressure Isolation Valves.
In a letter dated June.11, 1987 the licensee provided the information requested by this letter.
(2) Generic Letter 8607: Transmittal of NUREG - 1190 regarding the San Onofre Unit 1 Loss of Power and Water Hammer event.
The licensee placed this document in the operating department's required reading file The licensee's Regulatory Assurance group has a system in place that tracks Generic Letters as well as other NRC information.
9.
Administrative Controls Affecting Quality (42700)
l 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.
10. Radiation Control (71709)
Periodic inspections of plant radiological control conditions were made during the inspection period.
Isolated instances of minor deficiencies were found and promptly corrected by plant personnel.
No violations or deviations were identified.
11. Outages (60710,86700)
(a) ESF Actuation On October 6 instrument mechanics had bypassed the IB Refuel Floor Radiation Monitor to replace a power supply. When they removed the power supply, Standby Gas Treatment System actuated at 1305 hours0.0151 days <br />0.363 hours <br />0.00216 weeks <br />4.965525e-4 months <br /> tripping normal reactor building ventilation and placing control room ventilation into full recirculation mode. The cause of the actuation was discovered to be a faulty relay in the 1A Refuel Floor Radiation Monitor which gave a spurious downscale trip coincident with the downscale trip on IB when the power supply was removed.
The faulty relay was replaced and functional tests were performed on both monitors with satisfactory results and control ventilation was returned to normal.
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I (b) ' Detached Wire Disables LPCI Loop Select At 1505 CST on 11/1/87 with Unit 1Ldefueled and Unit 2 in cold shutdown, electricians found a wire disconnected on a~ relay for the Unit 1 Low Pressure Coolant Injection (LPCI) Loop Select Logic. Had this wire been disconnected during a loss of coolant accident with
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only one recirculation pump running, the pump would not have been deenergized as required. This could have resulted in LPCI injecting into the failed loop. _The disconnected wire will_be reattached to the troper relay and a functional test performed prior to reactor startup. The cause of the wire becoming detached or the date at l
which it became detached _is unknown, but the relay was successfully l
functionally-tested prior to the startup from the last refueling outage.
No work had been performed in the panel prior.to the time at which the detached wire was discovered. A plausible cause for the detached wire is a worker in another panel through which the wire ran accidently moving the wire, thereby pulling the wire from.
the relay. There is no evidence of intentional tampering. The NRC Emergency Operations Center was notified at 1625 CST on 11/1/87.
(c) Reactor Scram On 11/09/87 Quad Cities Unit I was in cold shutdown returning fuel elements into the reactor vessel and Quad Cities Unit 2 was near full power.
Source Range Monitor 21 on Unit I was not functioning properly,' interfering with the fuel load. At 1627 CST a scram signal was placed on the channel B reactor protection system of Unit 1 in order to perform response checks and signal-to-noise ratio checks on source range monitor 21 in an effort to return it to service. At'1941 CST intermediate range channel 14 spiked above the high-high scram setpoint, which provided a scram signal to the channel A reactor protection system,_and since a scram signal was already present on channel B, a reactor scram resulted. There was no rod movement since all rods were inserted at the time. The cause of the spikeion intermediate range channel 14 is unknown; there was no fuel movement at the time. At 2000 CST the NRC Emergency Operations Center was notified.
After the scram signal from channel A cleared the scram was reset.
Source range monitor 21 was returned to service and the core reload subsequently successfully completed.
(d) Drywell Steel Connections Fail to Meet FSAR Requirements On 11/20/87 at 1400 CST, with Unit 1 in a refueling outage and Unit 2 over 90% power, Quad Cities was informed by the Commonwealth i
Edison Station Nuclear Engineering Department that the results of an
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analysis conducted by Sargent and Lundy showed that some drywell
steel connections on Unit I did not meet FSAR requirements but did meet operability requirements. At 1455 CST on 11/20/87 the NRC Emergency Operations Center was notified.
i The drywell steel connection analysis and inspection was undertaken as part of a followup of discrepancies discovered at Dresden. A
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100% inspection of Unit 1 drywell steel connections has been completed, during which 10 connections and 3 beams failed to meet FSAR requi cments but did meet operability limits.
These discrepam o will be repaired prior to the Unit I startup.
Fourteen h discrepancies were discovered which comply with FSAR wqv ments but which violate good engineering practice.
.These are also planned to be repaired prior to the Unit I startup.
Analysis results will continue to be developed by the licensee's contractors and any discrepancies will be repaired as necessary. A 100% inspection of Unit 2 has been made.
No discrepancies which violate operability requirements have been discovered.
Components which do not meet FSAR requirements will be repaired during the next Unit 2 refuel outage.
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(e) Fire Penetrations During a walkdown by Sargent and Lundy to revise fire drawings, one
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fire penetration was found that was not completely sealed.
Station personnel conducted further inspections and found a total of six fire penetrations that were not correctly sealed. A continuous fire;
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watch was established. Some examples of what was found are:
holes-from removed anchor bolts not grouted, a penetration where the grouting did not match the thickness of the penetration, a cover-plate held with two screws instead of ten, and 1/4"'tygon tubing in a penetration. These incorrect fire penetrations do not represent a I
significant safety concern. They did, however, point out weaknesses in the licensee's program that are being investigated by the licensee. The defective fire penetration seals have been repeired and the fire watch has been discontinued. A detailed inspection cf fire penetration seals by the licensee and the licensee's
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contractors is continuing.
(f) Control Room Ventilation Isolation At 2200 on 12/1/87 a control room ventilation isolation occurred when the sample point for the toxic gas analyzer was switched from channel C (the control room ventilation system's exhaust) to channel A (the suction of the in-service train of control room ventilation).
This action caused a momentary spike in the toxic gas analyzer. The spike cleared immediately and the control room ventilation shifted I
back to normal. The'NRC Emergency Operations Center was notified at 0022 CST on 12/2/87.
The toxic gas analyzer's sample point was positioned to channel C at 1340 on 11/28/87 when an instrument technician discovered the toxic gas analyzer to be inoperative during a surveillance test,
necessitating that control room ventilation be manually isolated.
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Part of the procedure for isolating the control room ventilation system is to place the toxic gas analyzer in channel C.
At 1125 on 11/30/87 the toxic gas analyzer was repaired and the control room ventilation system returned to normal, however the sample point for l
the toxic gas analyzer was erroneously lef t in the channel C l
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position. The Resident Inspectors are monitoring licensee q
corrective actions to ensure similar errors are avoided in the
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(g) Control Room Ventilation Isolation As a result of the ' control room ventilation isolation that occured on 12/01/87 (refer to paragraph (f) of this section), a training i
sessionion the Control Room HVAC System was being conducted at'the I
toxic gas analyzer station. During the session an equipment attendant, believing that the S02 range switch was in the wrong position, moved this. switch-from the 0-5 ppm range to the 0-1 ppm range resulting in an isolation of the control room ventilation system.
The switch was moved back to,the 0-5' ppm range and control room ventilation was returned to the normal mode. The isolation signal occurs when the S02 reading is 20%.of scale or greater. 'At-the time the switch was moved the 0-5 ppm range was reading 0.5 ppm-which.is greater than 20% of the scale on the 0-1 ppm scale.
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(h) ' Refuel Activities l
The refuel activities conducted during this outage showed the same
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I consistently good performance that has been demonstrated in past refuel' outages
.The Resident. Inspectors observed portions of core unloading and loading, new fuel inspection, and other refuel j
l activities. -No violations or deviations were noted, j
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(i) Outage Planning
This department assumed a larger role during this outage than in the past' refuel outage. The increased use of work planning programs
.during this outage is expected to provide a data base for future outage planning. Additionally, plans are in' place to increase the staffing'in this department, which' currently has four members, to a staff of eight personnel.
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Exit Interview (30703)
The inspectors met with licens u representatives (denoted in Paragraph 1)
throughout the inspection period and at the conclusion of the inspection on December 7,1987, 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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