IR 05000254/1990025
| ML20029B303 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 02/25/1991 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20029B298 | List: |
| References | |
| TASK-2.F.2, TASK-TM 50-254-90-25, 50-265-90-25, NUDOCS 9103070026 | |
| Download: ML20029B303 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION 111 Reports No. 50-254/90025(DRP); 50-265/90025(DRP)
Docket Nos, 50-254; 50-265 Licenses No. OPR-29; DPR-30 Licensee: Commonwealth Edison Company Opus West III 1400 Opus Place Downers Grove, IL 60515 Facility Name: Quad Cities Nuclear Power Station, Units 1 and 2 Inspection At: Quad Cities Site, Cordova, Illinois Inspection Conducted:
December.16, 1990 through February 2, 1991 Inspectors:
T. E. Taylor J. Shine R Bocanegra T. Ploski D. Jones fy,C
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Approyed By: cMsM' :gm>--
J6/9/
f BTBurgess,Chfef Date'
Reactor Projects Section IB Inspection Summary Inspection from December 16, 1990 through Februaryl 1991 (Reports No. 50-254/90025(DRP); 50-265/9002bT6kV))
Areas Inspected:
Routir.e, unannounced safety inspection by the resident and regional inspectors of licensee action on previously identified items; licensee event report review; regional request; follow-up on TMI action items; operational safety verification; monthly maintenance observation; monthly surveillance observation; training effectiveness; report review; events; and meetings and other activities.
Results: Of the areas inspected, no violations or deviations were identified.
The fU lowing performance was noted:
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. Plant Operation 1)
Quality of plant operations continues to decrease.
The Unit 1 January 24, 1990 event shows an immediate need for additional management involvement to emphasize communications and attention to plant parameters, and adequate control of -operations activities.
2)
On January 24, 1990, due to personnel errors, poor communication, and a lack of attention to plant parameters a loss of vessel inventory occurred.
A loss of 2800 gallons from the vessel and 1400 gallons from the RHR system piping was inadvertently drained to the reactor building sump.
A special NRC team inspector was sent to the site.
Results of that inspection will be detailed in inspection report 254/91006.
3)
A con.ern regarding a failure to properly prepare and verify adequacy of a Unit 1 out-of-service (005) was identified.
Due to the improper 005 an unplanned partial Group Two isolation occurred. This involved errors by the preparer and reviewer.
It predates the loss of reactor vessel inventory event of January 24, 1991 but is similar to that event.
4)
A loss of containment isolation was identified.
Due to two personnel errors, the Unit 2 lower torus sightglass isolation valve was lef t open for about 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />.
An engineering seismic evaluation showed that the sightglass would not withstand a sign'?icant seismic event.
During initial installation the sightglass m hydroed to 62 psig which is the max design basis design pressure.
5)
The Humsn Factors study report for the October-27, 1990 Unit 2 scram is attached to this report.
6)
During the report period six unplanned ESF actuations occurred.
The cause of the actuations were:
Four attributed to equipment failure, and
.two to personnel error.
The personnel errors were related to an improper 005 evolution and the other concerned an electrical maintenance technician's inability to follow the associated work package.
7)
Twenty-two LERs were closed during this report period.
Maintenance and Surveillance 1)
Maintenance and-surycillance area performance' improved slightly.
No violations were issued in-this area.
Maintenance work planning and coordination of activit es are areas of concern.
2)
Unit I refueling activities continue.
The new outage end date is March 1, 1990.
The outage extension is due to a work stoppage associated with a January 24, 1991 loss of vessel coolant event, delays in the 1B RHR system outage activities, and repairs for the 1A RHR' heat exchanger identified in the later stages of the outage.
Securi ty Performance in this area continues-to be very good.
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Radiological Controls Licensee-performance in this area has improved concerning personnel contaminations.
The percentage of plant areas contaminated remains about the same.
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Engineering and-Technical Support
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11)
LAlthough there are still problems with some long standing equipment problems, performance in this area is starting to improve. Areas of
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improvement are tech staff personnel numbers, system engineer program progress, and tech staff involvement for maintenance and operations support.
2)
The completion schedule for TMI action item 2.F.2.4 " Instrumentation for-Detection of Inadequate Core Cooling" for both units has been revised.
The modification will be completed by June 1992 for Unit 1 and by March 1993 for Unit 2.
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Emergency preparedness One open. item was closed concerning licensee response to a simulated onsite medical emergency. On a previous inspection-this item was found to be inadequate with respect to:
medical and contamination assessments of the victim;-contamination control techniques; and onscene' command and control.
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DETAILS 1,
Persons Contacted i
Commonwealth Edison Company 1 CECO)
N. J. Kalivianakis, General Manager, BWR Operations
- R, L, Bax, Station Manager
- R. A. Robey, Technical Superintendent G, F. Spedi, Production Superintendent R. Stols, Nuclear Licensing Administrator
- J. Swales, Assistant Superintendent - Operations G. Tietz, Superintendent of Programs J. Fish, Master Mechanic J. Sirovy, Services Director T. Tamlyn, ENC Site Manager
0. Craddick, Assistant Superintendent - Maintenance B. Tubbs, Operating Engineer - Unit 1
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B, Strub, System Engineer Supervisor J. Kopacz, Operating Engineer - Unit 0 J. Wethington, Assistant Tech Staff Supervisor A. Misak, Regulatory Assurance Supervisor R.- Walsh, Technical Staff Supervisor 0. Bucknell, Assistant Technical Staff Supervisor C. Smith,- Quality Nuclear Program Supervisor K. Leech, Security Administrator B,.McGaffigan, Assistant Superintendent - Work Planning J. Hoeller, Training Supervisor
- D. Kanakares, Regulatory Assurance R, Bajema, Chief Steward 0, Edwards, Chief Steward Nuclear Regulatory Commission
- T Taylor R. Bocanegra J. Shine
- Denotes those attending the exit interview conducted on February 1,1991, and at other times throughout the inspection period, The inspectors also talked with and interviewed several other licensee employees, including members of the technical and engineering staffs,
- reactor and equipment operators, shif t engineers and foremen, and electrical, mechanical and -instrument maintenance personnel,- and contract security personnel.
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2.
Licensee Action on Previously Identified -Items (92701, 92702)
a.
Administrative Closures L
NRC Region III management has reviewed the existing open items for i
the Quad Cities station and have determined that the following open items will be closed administratively due to their safety
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significance relative to emerging priority _ issues and to the. age of the item.
The licensee is reminded that commitments directly relating to these open items are the responsibility of the licensee
.and'should be~ met as committed. NRC Region III will review licensee actions by periodically sampling administratively closed items.
(1)._(Closed) unresolved Item 254/87025-02:
Failure to Implement an
Adequate Procedure for Racking Out 4160 Volt Breakers.
(2) (Closed) Unresolved Item 254/87025-03:
Review Adequacy of EO Training Relative to Breaker Operation.
(3) (Closed) Unresolved Item 265/87025-01:
Failure to Implement an Adequate Procedure for Racking Out 4160 Volt Breakers.
(4) (Closed) Unresolved Item 265/87025-02:
Review Adequacy of EO Training Relative to Breaker Operation.
b.
Open Items (1) (Closed) Open Item'254/89027-03:
Inadequacy of Procedures-00A 5600-4 and QOA 2500-1.
Procedures 00A 5600-4 and Q0A 3500-1 were revised to address inadequacies, and issued on January 11, 1990.
This item is considered closed.
(2) (Closed) _Open Item No. 50-254/90018-01:
During the December 1990 Emergency Preparedness (EP) exercise, the licensee's overall-response to a simulated onsite medical emergency was inadequate with respect to: medical and contamination assessments of the victim; contamination control-techniques; and onscene command and control.
On January 29, 1991, the licensee conducted a remedial medical-response demonstration involving a victim who had supposedly-become injured and contaminated while investigating a leak in the Unit 2 drywell. _ Wespt,nse activities were evaluated by an inspector, the station's EP coordinators,- corporate EP staff,
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the licensee's medical consultant, and by Nuclear Quality _
Programs staff.
The successful demonstration was realistically staged outside a drywell hatch. The victim wore aopropriate protective clothing, His injuries were realistically depicted using makeup. The overall performances of the onscene responders were very-good with respect to the following: -frequent and accurate assessments of the victim's medical condition; contamination
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control =and radiological surveys of-the victim, first aid
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personnel, and-the accident scene;-onscene command and control; and coordination--with Control Room personnel._ Proper priority
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The Radiation Prctection Technicians (RPTs) who initially responded were well equipped.
Additional RPTs and operations personnel _were-summoned as deemed necessary by an RP Supervisor, who-
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effectively functioned as the onscene commander. He was assisted by a communicator.
Contamination control techniques
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at'the scene and along_the route to the simulated ambulance's location were good.
The_ victim was carefully and efficiently placed on a backboard before being transferred from_the simulated contaminated area to an uncontaminated area without spreading contamination.
The victim was then transported to the Unit I trackway on a gurney.
A' controller portrayed an ambulance crew member at the trackway.
The controller was given a well-detailed and accurate description of the victin's
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medical condition and contamination status by the RP Supervisor.
This item is closed.
No violations or deviations were identified.
3.
Licensee Event Report (LER) Review (92700J _
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Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requiremants were fulfilled, that immediate corrective action was accomplished, and that corrective action to prevent recurrence had been or would be accomplished in accordance with Technical Specifications (TS):
a.
(Closed) LER 254/86023-LL:
Unit 1 RCIC Inoperable Due to Spurious Overspeed Trips.
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(Closed) LER 254/86024-LL:
Residual Heat Removal Service Water
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System Piping Supports Exceed Code Stress Allowables Due to Inadequate Design Control.
c.-
(Closed) LER 254/86031-LL: Unit 1 Diesel Generator Automatically Started Due to Poor Labeling on Electrical Drawings.
d, (Closed) LER 254/87019-L1:
Failure of Unit 1 As'Found Integrated Leak Rate Test.
Le.
(Closed) LER 254/88003-L1: ' Group 1 Isolation in Startup/ Hot Standby Due to Contacts Not Closing on Reactor Mode Switch Caused by Rotational Play.
f.
(Closed LER 254/88010-LL:
Drywell Atmosphere Thermocouples Splices Found Not Qualified Due to Personnel Error.
g.
(Closed) LER 254/90005-LL:
Failure of Valve MO-1-1301-61 to Open
_Due to Contactor at _ Feed Breaker Not Closing Completely.
h.
(Closed) LER-254/90010-LL: Clean-Up Isolation On High Temperature Due to Check Valves leaking.
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(Closed) LER 254/90017-LL:
Excessive Leakage Through HPCI Steam Exhaust Check 1 Valve Due to Deterioration of Seat.
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(Closed) LER 254/90021-LL: Residual Heat Removal Valve 1001-50 Failed to Open Due to Thermal Binding.
L (Closed) LER 254/90022-LL:
Piping System Outside-FSAR Compliance Caused by Computer User Input Error,
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1.
(Closed) LER 254/90024-LL: Missed Technical Specification Surveillance for Continuous Fire Watch Due to Personnel Inattention.
This is example a. of a Technical Specification violation found in report no. 50-254/90022(DRP).
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(Closed) LER 254/90025-LL:
Engineered Safety Feature (ESF) Group II Isolation Due to a Spurious Signal From LT 1-263-58A While Valving Into Service, n.
(Closed) LER 265/88015-LL: Unit 2 Partial Group II Isolation from Blown Fuse Due to Unknown Reason.
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(Closed) LER 265/88016-LL:
Unit 2 Partial Group II Isolation From Blown Fuses Due to Maintenance Activity.
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(Closed) LER 265/88022-Ll:
Loss of Chimney Monitors When Power Supply Deenergized for Maintenance Due to Battery Backup Failure, q.
(Closed) LER 265/89003-LL:
Loss of Secondary Containment During Search for Grounds on 125 VDC.
r, (Closed) LER-265/89005-LL: Unit 2 Scram From Main Stop Valve-Closure Due to Personnel Error.
(Closed) LER 265/90001-LL: HPCI Fire Protection Out of Service
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Greater Than 14 Days Due to Conservative Action.
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(Closed) LER 265/90007-LL:
Partial Loss of RPIS Due to Blown Fuse.
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(Closed) LER 265/90008-LL:
Failure of the Automatic Function of the HPCI. Flow Controller Due to Unknown Causes.
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(Closed) LER 265/90009-LL: Unit 2 HPCI Declared Inoperable Due to Failure of the Giant %al Hotwell Pump Caused by Level Switch Failure, In addit'on to the foregoing, the inspector reviewed the licensee's Deviaticn Reports (DVRs) generated during the inspection period. This was done in-an _ef fort to monitor the conditions related to plant or personnel performance, potential, trends, etc.
DVRs were also reviewed for proper initiation and' disposition as required by the-applicable procedures and the QA_ manual.
No violations or deviations were identified.
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4.
_ Follow-up_on TMI Action items (2515/065-01).
By'1etter dated August 21,-1990 from Rita Stols (Commonwealth Edison) to Dr. Thomas E. Murley (NRR) - the licensee provided a revised schedule for the completion of TM1 Action item II.F.2.4 " Instrumentation For Detection of Inadequate Core Cooling" for both Quad Cities units.
To address TMI Action Item II.F.2.4, the licensee issued a modification
- packasa for each unit (" Reactor Level Reference Leg Modification"),
Each package consists of four partial packages, which are referred to as A, B, C, and D.
Partial = packages A and B include installing condensing chambers and routing instrument lines; C and D include the installation of_ two drywell penetrations.
The following is the revised schedule for the completion of the modifications:
Unit 1 Partial Packages Completion Date A and %
June 1992 C and D-March 1991 Unit 2 Partial Packages ~
pletion-Date Com A and B March 1F9T C and D June 1991 No violations or-deviations were identified.
5.
Operational-Safety Verification (71707)
During the inspection period, with the exception of the circumstances.
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surrounding the' January 24, 1991 vessel-inventory loss event, it was determined that the facility was being operated in conformance with the licenses and regulatory requirements and that the licensee's management control system was effectively carrying out its responsibflities for safe operation. This was done -on a sampling basis through routine. direct observation-of activities and equipment, tours of the facility, Interviews and discussions with_ licensee-personnel, independent verification of safety system status and limiting conditions for operation action requirements-(LC0ARs), corrective action, and review of f acility records.
On a sampling basis the-inspectors daily verified proper control room staf fing-and access, operator behavior, _and coordination-of plant activities with ongoing control room operations; verified operator adherence with the latest re_ visions of procedures for ongoing activities; verified operation as required by Technical Specifications (TS);
including compliance with LC0ARs, with emphasis on engineered safety features (ESF) and ESF electrical alignment and valve positions; monitored instrumentation recorder traces and duplicate channels for abnormalities; verified status of various lit annunciators for-operator
- understanding, of f-norma! condition, and corrective actions being taken; examined nuclear instrumentation (NI) and other protection channels for proper operability; reviewed radiation monitors and stack monitors for-abnormal conditions; verified that onsite and offsite power was available
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as required:-observed the frequency of' plant / control room visits by the
station. manager.' superintendents, assistant operations superintendent, and other. managers; and observed the Safety Parameter Display System (SPOS) for operability, a.
Containment Integrity On December 20, 1990 at approximately 3:30 AM, the licensee discovered that the lower torus sightglass isolation valve on Unit 2 was open.
At 5:00 AM it was determined that this was a potential violation of containment integrity, and the appropriate 50.72 notification was made.
The open isolation valve was identified during troubleshooting
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activities associated with the torus hi/ low level alarm that
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annunicated at 4:12 AM on December 17, 1990.
Based on-the alarm time and a torus level computer point history it was-determined that-the valve was open for-abou: 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />.
The-cause of the event was determined to be personnel errors.
The errors occurred during the weekly torus level verification.
The first error occurred when.the
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Unit 2 equipment attendant (EA) closed the level transmitter Isolation
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instead of the sightglass isolation.
The second error occurred when another EA failed to identify the error during the required independent verification.
Factors that contributed to this event were poor lighting, poorly labeled valves, and a fatigued EA performing second verification. - Although fatigued, the second EA's hours were within-
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NRC overtime guidelines.
The initial installation of the sightglass included a hydro to 62 psig which is the max containment. design pressure for a design basis accident..The evaluation concerning seismic qualifications identified that stresses were exceeded by a factor of 11.4 to 1, therefore, the sightglass would very likely not'
s withstand a significant seismic event. The hydrostatic test of the site glass provides assurance that-containment integrity.was maintained.
The low probability of an accident pressurizing containment in combination with a seismic event makes the safety significance in this case minimal. The licensee has committed to correct the valve. labeling and to investigate additional lighting, b.
Partial Group II Actuation Due To Out-of Service Error An unplanned partial Group II actuation occurred on January 5, 1991,-
-during the performance of out of services (005) 1190 and 1191.for the Unit 1 drywell floor drain sump containment isolation valves 1-2001-3 and 1-2001-4.
The actuation resulted when fuses 7 and 8 were pulled from electrical panel numbers 901-40 and 901-41.
An NRC review identified the cause of the event to be personnel errors by the Communications Center Coordinator (CCC) and the Senior Reactor Operator (SRO).
QAP 300-14, " Equipment Out-0f-Service", requires the CCC to complete the fiaster Out-of-Service Checklist (QAP 300-55).
The CCC failed to perform an adequate review of the electrical drawings which would have identified the improper fuse pulls and the resultant
' unplanned valve closure and partial Group II isolation.
QAP 300-14
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also requires that an SR0 verify that all information on the Master Out-of-Service (005) Checklist is correct and adequate.
The SR0
failed to identify the fuse pull error in the 00S.
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Although procedure QAP 300-14 governs the preparation and review of master 005 checklists, employees failed to produce an adequate checklist,-i.e. isolation, for the intended work.
The inadequate 005 checkiist is similar to a problem found as part of a.
January 24, 1991 event at Quad Cities. That event resulted from an improper 00S valve lineup which inadvertently drained water from the shutdown cooling system, c.
Engineered Safety Features (ESF) Systems
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Accessible portions of ESF systems and components were inspected to veri fy.
valve position for proper flow path; proper alignment of power supply breakers or fuses (if visible) for proper actuation on an initiating signal; proper removal of power from components if required by TS or FSAR; and the operability of support systems essential to system-actuation or performance through observation of instrumentation and/or proper valve alignment.
The inspectors also visually inspected components for leakage, proper lubrication,
' cooling water supply, etc.
d.
Radiation Protection-Controls The inspectors verified that workers were following health physics procedures for dosimetry, protective clothing, frisking, posting, etc., and randomly examined radiation protection instrumentation for use, operability, and calibration, e.
Se_curity The'. inspectors, by sampling, verified that persons in the protected area (PA) displayed proper badges and had escorts if required; vital areas were kept locked and alarmed, or guards posted if~ required; and personnel and packages entering the PA received proper search and/or monitoring.
f.
Housekeeping and Plant Cleanliness The inspectors monitored the statuc of housekeeping and plant cleanliness for fire protection, protection of safety-related equipment from intrusion of foreign matter and general protection.
The in.spectors also monitored various records, such as tagouts,-
. jumpers, shiftly logs and surveillances, daily orders, maintenance items,L various chemistry and radiological sampling u..d analysis,
. third party review results, overtime records, QA and/or QC audit results and postings required per 10 CFR 19.11.
No violations or. deviations were identified.
Engineered Safety Feature (ESF) Actuations (93702)
The licensee reported six Unit 1 Engineered Safety Feature (ESF) actuations-since December 20, 1990.
Event investigations by the licensee has not been
. completed, although two of the ESFs appear to be. personnel error.
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Control-Room HVAC ESF actuations on December 20,1990(LER90-026)and December 23,1990 (LER 90-034) resulted from the chlorine analyzer probe
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The licensee is working with_ the vendor to resolve the chlorine analyzer problem.
Group 11 isolations on January 5,1991 (LER 91-001) and January 8,1991 (LER 51-002) have been tentatively attributed to personnel error. An
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out-of-service (005) request not properly researched resulted in the January 5,1991 ESF actuation.
The other ESF actuation occurred when an
electrical maintenance worker failed to complete a portion of work package instructions.
I Two additional Group 11 isolations were reported on December 23, 1990 (LER 90-033)'and January 10,1991 (LER 91-004).
Both actuations were caused by blown fuses in unrelated incidents.
One blown fuse appears to have been caused by workers performing cable verification while the cause i
of the other blown fuse has not been determined.
In response to the recent ESF actuations, the licensee conducted a l
station meetir,
'o review the incidents and to form a strategy for preventing fur-r occurrence.
The station's Regulatory Assurance department is c.
- tinuing its investigation and will brief the resident inspe'etors of the results and any corrective actions.
7.
Monthly Maintenance Observation (62703)
Station maintenance activities affecting the 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 t
Specifications.
.The following items were considered during this review:
the limiting conditions for cperation were met while components or systems were removed from-and restored to service; approvals were-obtained pricr 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 ser_vice; quality control records were maintained;- activities were accomplished by qualified personnel; parts and materials used were i
properly certified; radiological controls were implemented; and fire prevention controls were implemented. Work _ requests were reviewed to determine the status of outstanding jobs and to assure that priority is assigned to safety-rel.ated equi _pment maintenance which may affect system performance, The following maintenance activities were observed and reviewed:
q
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Temporary Procedure 6473, "Decnergize Bus 14-1 for Bus and Cubicie
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Maintenance" Electrical Maintenance CR120 Relay Replacement
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Unit 1 Diesel Generator Fuel 011 Transfer Pump Replacement Unit 1 Diesel Generator Prelube Modification DCRDR.Annurciator Modification (Panel 901-54)
Unit 2 HPCI Exhaust (2301-45) Check Valve Replacement The inspectors monitored the licensee's work in progress and verified that it was being performed in accordanec with proper procedures, and approved work packan s, that 10 CFR 50,59 and otht.'appitcatie drawing updates were made and/or planneo, and that operator training was conducted.in a reasonable period of time.
No violations or deviations were identified.
8.
Monthly -Surveillance Observation (617261 The inspectors observed surveillance testing required by Technical Specifications-during the inspection period and verified that testing was performed-in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for operation were met, that removal and restoration of the affected components were accomplished, that results ' conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the
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individual directing the test, and that any deficiencies identified:
during the testing were properly reviewed and resolved by appropriate management personnel.
The inspectors also witnessed portions of the following test a:tivities:
Unit 1 QTS 130-1 Rev. 11, Control Rod Timing and Position Indication Check QIS 59-1 Rev. 11, Standby Diesel Generator Cardox Fire Protection
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Test Procedure Unit 2 QCOS 1300-1,-Monthly RCIC-Pump Operability Test QCOS 1300-5, Quarterly RCIC Pump Operability Test
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005 6600-6, Diesel Generator Cooling Water Pump Flow Rate Test QOS 2300-1, HPCI System Preparation for Operation QOS 250-8 -.MSIV Testing at Cold Shutdown QTS 130-1, Control Rod Timing and Position Indication Check
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005 1000-2, RHR System Pump Operability No violations or deviations were identified.
9.-
Refueling Activities (60730)
The inspection objective was to ascertain whether refueling activities
- are being controlled and conducted as required by the Technical Specifications and applicable approved procedures, The inspection period began with Unit 1 in day 33 of a planned 70 day refueling outage.
The inspection period ended at day 83 of the outage, with unit startup tentatively scheduled to commence on March 1, 1991.
The extension of the outage is attributed to deliberate performance of outage activities.to minimize errors, unscheduled leave given to workers during the holiday period, and the necessity to repair a tube leak on the A RHR heat exchanger, which surfaced late in the outage, The startup delay was further increased approximately two weeks due to the unplanned
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loss of RCS inventory event that occurred on' January 24, 1991.
During the report period _the inspectors observed and reviewed portions of the following: refueling activities:
a.
Maintenance of secondary containment integrity, housekeeping, loose object control, adherence to radiation protection guidelines _ and
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adherence to_ overtime guidelines.
b.
Activities concerning containment penetration leak rate testing (Appendix J) and condensate pump. room flood protection
maintenance / surveillance were reviewed, c.
The inspectors routinely monitored management coordination efforts concerning interdepartmental communication and overall_ outage control.
Additionally, the inspectors regularly witnessed operations personnel performing shif t turnovers and shif t briefings, with heavy emphasis on verifying that control room and shif t supervisory personnel were aware-of plant status and upcoming evolutions attributed tv. refueling activities.
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The inspectors verified the adequacy of available core cooli-ng
- systems anfavai_ lability of electrical power to components required
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- for operation as mandated by the Technical Specifications for outage-related plant co'nfigurations.
The inspectors verified that any applicable limiting conditions-of operation were properly entered, documented, and complied with.
The following outage related events occurred:
- a.
On January 5,-1991 a partial group Il containment isolation was-received due to an improperly prepared out-of-service (LER 91-001),
b.
On January 8,1991, a partial group 11 containment -isolation was received due to personnel error.
A jumper was removed out-of-sequence with the work package instructions.
(LER 91-002).
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On-January 16, 1991, a partial group II containment isolation was received due to a. blown fuse occurring while a wiring verification was being conducted by Substation Construction (LER 91-004).
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No violations or deviations were identified.
10. - Training Ef fectiveness (41400, 4170l}
The effectiveness of training programs for licensed and non-licensed personnel was reviewed by the inspectors during the witnessing of the licensee's performance of routine surveillance, maintenance, and operational activities and during the review of the licensee's response to events which occurred during the inspection period.
Personnel appeared to be knowledgeable of the tasks being perfccmed, and nothing was observed which indicated any ineffectiveness of training.
No violations or deviations were identified.
11.
Report Review During the inspection period, the inspector reviewed the licensee's Monthly Performance Report for December 1990 and January 1991.
The inspector confirmed that the information provided met the requirements of Technical Specification 6.9.1.8 and Regulatory Guide 1.16.
-The inspector also reviewed the licensee's Monthly Trending and Analysis Report for December 1990.
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No violations or deviations were identified.
12.
Events (93702)
Loss of Coolant Inventory On January 24, 1991, a loss of vessel inventory occurred.
The vessel inve-tory -loss occurred between 1:18 PM and 1:39 PM. Approximately.
280' ' gallons (14 inches vessel level) from the vessel was drained to u
the reactor buildiag floor drain sump. A special NRC inspection was conducted.
The circumstances surrounding the event and NRC findings will be discussed in Inspection Report 50-254/91006.
13.
Human Factors Study Report As part of the AE00 program to study the human factors aspects of operational events, a team was sent to the Quad Cities plant on
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Octobar 31, 1990 to evaluate the Unit 2 scram which1 occurred on October 27, 1990.
The team was on site for two days and gathered data from discussions, plant -logs, strip chart recordings and interviews of. plant operators.
Enclosure 3 is a copy of the Human Factors Study _
Report - Quad Cities 2 (10/27/90).
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Exit Interview (30703)
The inspectors met with the licensee representatives denoted in Paragraph I during the inspection period and at the conclusion of_ the inspection on February 1, 1991, The inspectors summarized the scope and results of the inspection and discussed the likely content of this inspection report.
The_llcensee acknowledged the information and did not indicate that-any of the information disclosed during the inspection could be considered proprietary in nature.
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DEC 2 81990
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h1Eh!ORAND'Jh! FOR:
Thomas hi, Novak, Director Division of Safety Programs Office for Analysis and Evaluation of Operational Data FROht:
Jack E. Rosenthal, Chief Reactor Operations Analysis Branch
' Division of Safety Prograais Office for Analysis and Evaluation of Operational Data SUBJECT:
.HUhtAN FACTORS STUDY REPORT - QUAD CITIES 2
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(10/27/90)
On October 27,1990, at 3:59 p.m., Quad Cities Unit 2 scrammed on a hi hi intermediate range scram signal, because the operator withdrew control rods to increase reactor pressure without
. recognizing the need to follow the normal procedures for re establishing reactor criticality Quad Cities 2 was preparing to restore the plant following an aborted special turbine torsional test and returr to pcw operations, At about 1 % power, an operator was inserting control rods to reduce reactor pressure so that the turbine _ bypass valves would close and test equipment could be removed from the EHC system,-when the reactor went suberitical. When the. system pressure continued to decrease below the desired-level, the operator withdrew rods to increase pressure,
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but the reactor scrammed on a hi hi intermediate range scram signal. This event occurred because the operator was monitoring reactor pressure rather than reactivity.
As_ part of the AEOD program to study the human factors aspects of operational events, a team was sent to the site October 31. The team leader was Gene Trager of AEODt other team
- members were Barry Kaufer of AEOD, and Orville hieyer and hfark Parrish of Idaho' National:
Engineering Laboratory., The team lwas c.i the site for-two days and gathered data from-discussionsf plarit togs,- strip chart recordings, and interviews of plant operators.
' Enclosed if the report prepared by INEL of the results_ of the team's human factors study.
Specific human performance aspects of this event are addressed in this memorandum.
Task' AwjggDin There was a low level of awareness that the operations required to support the special test might require special attention. : Operations personnel were not sufficiently aware that careful reactivity -
management would be necessary during installation and removal of the special test equipment to l
- avoid either suberiticality or short startup periods.'
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Thomas M. Novak-2-i l
Shift Organization qqd Command and Control The shift organization consisted of a shift engineer (SE; SRO), who had overall responsibility for operations, a shift control room engineer (SCRE; degreed SRO/STA) who directs control room operators and activities for both units, nuclear station operators who are the licensed control room i
operators, and shift foremen (SF; SROs) who report to the SE and who direct equipment
operators for inplant activities. The shift organization was not effective in preventing this event.
A contributor to this event was the dif6culty experienced by the SE and SCRE in managing operations in support of the special test. During shift change there were many people in the cor.:rol room in the vicinity of the SCRE's desk monitoring the test, and the SCRE Onally asked them to leave the control room. When the decision was made to return the unit to power operation, the SE and SCRE were both surprised, as they had expected to go to cold shutdown to repair intermediate range monitoring equipment. They were both involved in reinerting the drywell (to meet a technical specification time limit) and returning the EHC system to service.
The combination of these factors may have been distracting. The SE realized that the SCRE was busy, but he did not return to the control room until the time the scram occurred.
The SCRE did not monitor and direct the activities of the unit NSO in controlling reactor power, because he was busy with other things, Unfortunately, the NSO thought be was being watched, as he reduced power unnecessarily until the reactor was suberitical, and then quickly pulled control rods to increase pressure.
Procedures The procedure governing operations from power operation to hot standby did not have cautions regarding the possibility of high rod and notch worths and the need for special reactivity management. In addition, when the procedure was first performed on Shift I the operators were unwilling to sign off a step regarding suberiticality, because it was unclear. However, they accepted the step as completed when it was signed off by an operating engineer. Furthermore, the Shift 3 unit NSO did not use a new copy of the procedure, but referred to the copy that had been signed off by Shift 1.
Communications There was a low level of communicadons among station operators prior to the event. The SCRE directed the unit NSO to take certain etion, but he did not verify that his instructions were understood nor that the actions were taker,
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Thomas M. Novak-3-
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Training While operating the plant in a hot standby condition is rare at this site, no special training was requested for performing this special test and there was no simulator drill, classroom instruction, or " read only" instructions for the control room operators. Furthermore, maintaining the reactor in a hot standby condition was part of initial licensW cperator training, but was not part of the requalification program.
Use of Ooerating Experience Information Operating experience information was not fed back prior to and during this event. An SRO had been assigned to review a previous reactivity management event that occurred at 12Salle in 1990, but no information on the significance of the event relative to Quad Cities was given to the operators. Similarly, high notch worth was experienced and understood by Shift 1, but this information was not recorded nor passed on to Shift 3.
This event emphasizes the need for careful planning, increased awareness, training, proper review and use of procedures, and good communications, when a plant is placed in a non typ; cal mode of operation due to special testing or other unusual conditions.
This report is being sent to Region III for appropriate distribution withir 'he region, l
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Odaheldgned ty Jack E. Rosenthal, Chief i
Reactor Operatiens Analysis Branch Division of Safety Programs Office for Analysis and Evaluation l
of Operational Data
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Enclosure: As stated ec:
Richard L. Bax, Station Manager l
Quad Cities Nuclear Power Station
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22712 206th Avenue North Cordova, IL 61242
Distribution: See attached 4(
ROAB:DSP:AEOD RO SP:AEOD O'
A3:DSP:AEOD ETrager:mmk G-f losenthal 12@90$
1g90 127f/90
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Distribution:
PDR Central File ROAB R/F DSP R/F ETrager BKaufer i
GLanik JRosenthal FJordan Dross TNovak VBenaroya l
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EGG HFRU 9427 TRIP REPORT:
ON SITE ANALYSIS OF
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THE HUMAN FACTORS OF AN EVENT I
AT QUAD CITIES 2 ON OCTOBER 27,1990 (HI HI IRM SCRAM FROM HOT STANDBY)
l Orville Meyer i
On Site Analysis Team:
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- Eugene Trager, NRC/AEOD Barry Kaufer, NRC/AEOD Orville Meyer, INEUEG&G Idaho Mark Parrish, !NEUEG&G Idaho l
' Team Leader Published December 1990 i
Idaho National Engineering Laboratory l
l EG&G Idaho, Inc.
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P.O. Box 1625 L
l Prepared for the Office for Analysis and Evaluation of Operational Data
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U.S. Nuclear Regulatory Commission -
Washington, D.C. 20555 Under DOE Contract No. DE AC07 761D01570
l ll0 !01431*
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l EXECUTIVE SUMM ARY
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At 3:30 p.m., 0:tober 27,1990, the Quad Cities Unit 2 reactor scrammed on a Hi-Hi trip fro the intermediate range monitors (IRMs). The scram occurred when the Unit 2 Nuclear Station Operator (NSO) was operating in the Hot Standby mode and attempting to control reactor pressr means of control rod positioning. TLe scram occurred when the NSO withdrew rods to incret cssure. A team led by Eugene Trager, of Nuclear Regulatory Commission, Office for Analysis and Evaluation of Operational Data (NRC/AEOD), visited the site on October 31 and November 1 to conduct an analysis of the human factors involved in this event as a part of an on going AEOD program to study the human factors of operating events. Other team members were Barry Kaufer, of NRC/AEOD, and Orville Meyer and Mark Parrish, of Idaho National Engineering l2boratory. This report provides a reconstruction and review of the details of the event and an analysis of the human factors embedded within the event.
The Quad Cities Nuclear Generating Station is located near Cordova, Illinois, and is owned and operated by the Commonwealth Edison Co. of Chicago, Illinois. The station consists of two General Electric BWR 3 reactors with Mark I containment and each plant rated at 789 MWe, Both units are operated from a common control room, and an NSO, who is a licensed reactor operator (RO), is dedicated to the controls of each reactor. There is an NSO serving as the Center Desk Operator and an additional NSO at the panels.- The NIOs for both units are L,. der the supervision of a Shift Control Room Engineer (SCRE), who is a licensed Senior Reactor Operator (SRO). Two Shift Foremen (SF), who also hold SRO licenses, are assigned principally to supervise local operations outside the control room. All operations during the shift are supervised by a Shift Engineer (SE), who is a licensed SRO.
The objective of unit 2 operations during this event was to support the conduct of Special Test 2 95 Partbl B, " Turbine Generator Torsional Response Test." The purpose of Special Test 2-95 was to precisely determine the torsional resonant frequencies of the turbine generator rotors.
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The test method was to operate the turbine at 45 to 105% of rated r, peed with the generator connectd to a phase A line to neutral short circuit. Th( eteet 'al load on the generator wcold be sery small. The reactor power required would be approumately 6 to 7L The turbine speed wvuld be controlled by a test potentiometer in the turbine control salve EHC circuit. Reactor power would be under the control of the Unit : NSO.
Temporary Change 6303 w as issued on 10/24/oO to normal operating Quad Cities General Prceedure (QGP) 2-4, ' Shutdown from Power Op: ration to a Standby llot Pressurized Condition,' 5 order to allow the use of re< irculation pumps and/or control rods to reduce pow er and thereby provide greater flexibility during power reduction to Hot Standby. Temporary Change 6303 did not add any specialinstructions or cautions. QGP 2-4 with Temporary Change 6303 was the controlling procedure in use by the Unit 2 NSO during the event.
The Special Test was attempted on 9/28/90 but was not performed due to electrical problems with the EHC circuitry. An extra RO and an SRO were assigned to the control room to perform the test during the 9/28/90 attempt.
The test was attempted again on 10/27/90 beginning with shift 1 (11:00 p. n. to 7:00 a.m.). The Unit 2 NSO inserted control rods to reduce reactor pressure to shut th TBVs and permit connection of Special Test circuitry to the EHC controls.
Dunng this maneuver the NSO experienced high controlim notch worths. The reactor had been in power operation the previous day and high xenon concentrations existed. The tips of the control rods in use were near the top of the core in a region of lower xenon concentration.
Information on the high rod notch worth was passed on orally from shift I to 2 (7:00 a.m. to 3:00 p.in.) but not from shift 2 to 3 (3:00 to 11 p.m.). No log entry was made of the high control rod notch worths.
The shift 2 operators increhsed reactor power until I to 2 TBVs were open ard warmed up the main turbine. However, the Special Test circuitrv would not permit increasii.g t!.e turbine iii
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i speed above 571 rpm so the turbine was tripped. Unit 2 conditions during shift turnover wre
~ 7% p3wer,1 1/2 TBVs open,920 psig reactor pressure, and moje switch in Hot Standby.
When shift 3 began their orientation, a meeting was being conducted near the SCRE's desk with u.w of the SCRE's phone among test engineers, the SE, and other station staff concerning the Special Tes, The SCRE directed that the meeting leave the control room, and it reconvened in the SE's office. Shift 3 began operations at 3:00 p.m.
In addition to the Special Test, there were other conditions that were of concern to the SE and the SCRE: two IR.',1 channels were in " bypass," one IRhi had a spurious trip, and one
IRhi remote detector drive was inoperable with the detector in:.crted, and the drywell had been deinerted with a LCO (limiting condition for operation) that requires reinerting within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or being in Hot Shutdown.
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At 3.10 p.m., the above conferencees decidtd to abort the Special Test and return to power. The SE phoned the SCRE and directed him to take f.he EHC off-line to permit removing the Special Test circuits. The SCRE directed the Unit 2 NSO to insert control rods to reduce reactor pressure to less than 800 psig.
The NSO inserted control rods a total of 84 steps while observing the reactor pressure
- 'ase. The reactor pressure decreased to 770 psig, but at the same time the reactor power had decreased to Range 1 of the IRM (the lowest range of the IRhis; the reactor was significantly sub-critical). At 3:58 p.m., the NSO began rod withdrawal to increase pressure and withdrew
one group of four rods one notch. He then withdrew one rod one notch. The reactor scrammed from an IRht Hi Hi trip on a 25 second period at 3:59 p.m..
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Task Awattncu The dominant human factor in this esent was a low lesel of awareness by the plant staff that the reactor conditions required by the torsional test were difficult to maintain. Reactivity management requires special attention when attempting to control reac - pressurt with the j
control rcds while the TBVs are shut because the reactor is at low power (2 to 5 %). In addition, high rcd notch worths may be experienced if xenon peaking levels are present. This low level i
of task awareness began with the planning and preparation of the Special Test and carried on through all activities to culminate in the reactor scram.
Pro:ednu The procedures redected the low level of task awareness, as there were no special instructions for reactivity management and no cautions for possible high rod notch worths. In addition, procedures were not followed. A test engineer, rather than the Shift 1 Unit 2 NSO, annotated and initialled a step in procedure QGP 24 as complete when a controlled change to the procedure would have been more appropriate, particularly since the step involved reactivity management in Hot Standby.
Training Requalification training had not included a lesson plan for reactor operation in Hot Standby and the operators had no special training nor briefing for the Special Test. The station developed and implemented an appropriate lesson plan within three days after the event.
Dinemination of Ooerating Exocrience Information Information on similar events at other stations had not been disseminated to the reactor operators. The high rod notch worth experienced during shift I had not been passed on to the shift 3 operators.
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I Communsations The Unit 2 NSO did not report back any information to the SCRE while executing the j
SCRE's command to insert control rcds to reduce pressure to less than 800 psig. The changes in rod positions and reactor power lesel were signi6 cant enough to justify supervisory overview by the SCRE.
Command atid Control The commands from the SE to the SCRE and from the SCRE to the NSO were mimmal and did not contain cautions or directions to report information back. The lack of reporting from the NSO to the SCRE contributing to the SCRE's failure to direct and os ersee the NSO's actions.
Knowledge Based Venus Rule BasedSMaliOD The Unit 2 NSO seemed to have been in a rule based mcdc of operation, as he was following the pro:cdural rule to " insert control rcds until reactor pressure is less than..." No signal seemed to have been effective to remind the operator to use his knowledge of reactivity management and also monitor reactor power, vi
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ACKNOWLEDGEMENTS
Appreciation is expressed for the cooperation of the Quad Cities station staff and es;>xially for the control room operators who were on duty during shift 3 on Octoter 27, w ho
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freely provided information concerning their observations, thinking, and actions during the event.
Appreciation is also expressa! for the valuable insights and cont 6butions of Hironori Peterson, of NRC Region 111, during on site analysis.
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TABLE OF CONTENTS
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Eh EC UTl V E S U hi hi A R Y....................................................... ii i
A C KN O WL E DG E hi ENTS...................................................... v ii ACRONYhtS.....................................................................,is 1.
I NT R O D U CT I O N............................................................ I 1. 1 P u rpo se................................................................... I 1. 2 S c o pe...................................................................... I 1. 3 On site Analy si s Team.................................................. I 2.
DESCRIPTION OF THE EVENT ANALYSIS......................... 2 2. I Ba c k g rou n d............................................................. 2 2. 2 E v e n t Ti m e Li n e........................................................ 4 2. 3 A nal y si s.................................................................
1 5 2. 3.1 Task A ware n e s s.................................................
2. 3. 2 P roced u r e s.......................................................
2. 3. 3 T rai n i n g........................................................... I 8 2.3.4 Dissemination of Operating Experience Information......
2. 3.5 Com munications................................................
2. 3. 6 Com mand and Control......................................
2.3.7 Knowledge based Versus Rule based Operation........... 20 3. S U bi hi A RY OF FINDING S............................................. 21 TABLES 1.
Reactor operating cycle for performance of Special Test 2 95 Partial B, " Unit 2 Turbine Generator Torsional Resynse Test'...... 5 2. S tation pe rsonnel interviewed.............................................. 7
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ACRONYMS APRM average power range monitor EHC electro-hydraulic control IRM intermediate range monitor NRC/AEOD Nuclear Regulatory Commission, Office for Analysis and Evaluation of Operational Data NSO Nuclear Station Operator QGP Quad Cities General Procedure RO Reactor Operator SCRE Shift Control Room Engineer SE Shift Engineer SF Shift Foreman SRM source range monitor SRO Senior Reactor Operator TBV turbine bypass valve ix
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1. INTRODUCTION l.I hupex The purpose of the visit to the Quad Cities Nuclear Generating Station on October 31 and November 1 and of the subsequent analysis was to examine the human factors involved in the automatic reactor scram from Hot Standby that o: curred on Unit 2 at 3:59 p.m., October 27, 1990. The scram originated from a Hi Hi trip on intermediate range monitors (lRMs) 13 and 16 while the Unit 2 Nuclear Station Operator (NSO) was attempting to control reactor pressure by means of control rod positioning. The reactor scrammed on a 25 second period when the NSO withdrew control rods to increase pressure. This site visit was the sixth si'c visit to be conducted by the NRC staff with the assistance of INEL, for the purpose of acquiring and
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analyzing data on the related human factors issues of operating events.
1.2 kes The on site data acquisitiot, and analysis focused on the factors that contributed to the reactor trip: operator tasks, control room activities, and control room crew composition immediately preceding the scram, ne human factors related to the preparation for the test were also analyzed: planning of the operation, preparation and review of the controlling procedures, specific training for the operation, and on shift and shift to shift operator communications.
1.3 On site Analysis Team The on site analysis team was led by Eugene Trager, of NRC/AEOD, and included Barry Kaufer, of NRC/AEOD, and Orville Meyer and Mark Parrish of Idaho National Engineering Laboratory.
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2.- DESCRIPTION OF THE EVENT ANALYSIS 2.1 N i): ground The Quad Cities Nuclear Generating Station is located near Cordova, Illinois, on the Mississippi River appruimately 20 miles north of Moline, and is owned and operated by the Commonwealth Edison Co. of Chicago, Illinois. The station consi;ts of two General Elo:tric BWR 3 reactors with Mark I containment and each plant rated at 18? MWe.
. nit I entered commercial operation on February 18,1973; Unit 2, on March 10, 1973.
Both units are operated from a common control room, and an NSO, who is a licensed reactor operator (RO), is dedicated to the controls of each reactor. There is an NSO scning as the Center Desk Operator and an additional NSO at the panels. The NSOs for both units are under the supenision of a Shift Control Room Engineer (SCRE), who is a licensed Senior Reactor Operator (SRO). Two Shift Foremen (SF), who also hold SRO licenses, are assigned principally to supervise local operations outside the control:oom. All operations during the shift are under the supervision of a Shift Engineer (SE), who is a licensed SRO.
The objective of Unit 2 operations during this event was to tupport the conduct of Special Test 2 95 Partial B, ' Turbine Generator Torsional Response Test." (Unit I was in commercial power generation at 90 to 100% power.) The purpose of Special Test 2 95 was to precisely determine the torsional resonant frequencies of the turbine generator rotors. The test method was to excite the resonant frequencies by operating the turbine at 45 to 105% of rated speed with the generator disconnected from the grid and instead connected to a phase A line to-neutral short circuit. The phase A fault current would te limited to low values by the use of a low power de source in place of the normal field excitation, ne electrical load on the generator would be very small and the turbine load would be slightly above the no load value. The reactor power required would be that necessary to support the turbine and the auxiliary steam loads which would total approximately 6 to 7% of full reactor power.
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During the actual measurement of the resonant frequencies, the turbine speed would t<
controlled by a test potentiometer speed reference setting in the turbine control vahe electric-hydraulic control (EHC) circuit. The potentiometer setting would be under the direction of the test dircetor. Reactor power would be under the control of the Unit 2 NSO with the automatic pressure control adjusting the opening of the turbine bypass valves (TBVs) to maintain reactor pressure near the setpoint.
The Special Test 2 95 Partial B procedure does not specify the reactor power lesel for the performance of the measurement of the resonant frequencies. It does state that the hioJe Switch must be in Startup/ Hot Standby and the reactor power must be less than 12 % to prevent a reactor scram due to an average power range monitor (APRht) Hi Hi trip. The ' Limitations and Actions * section of the Special Test procedure states that the Test Director shall order the reactor to be scrammed if any of the following conditions exist and are "not part of a controlled evolutio.i:"
Reactor pressure increasing above 960 psig
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Reactor pressure decreasing below 893 psig
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APRMs increasing above 11% of rated power
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APRhis decreasing below 2% of rated power.
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Temporary Change 6303 was issued on 10/24/90 to normal operating procedure QGP 2-
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4, " Shutdown from Power Operation to a Standby Hot Pressurized Condition," in order to allow i
the use of recirculation pumps and/or control rods to reduce pawer and thereby provide greater l
flexibility during power reduction to Hot Standby, Temporary Change 6303 deleted certain l
sections of QGP 2-4 as not applicable to the Special test evolution and did not add any Special i
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instrictions or cautions. QGP 2 4 with sections deleted by Temporary Change 6303 was the controlling procedure in use by the Unit 2 NSO during the event on 10/27/90. The combination
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of Special Test Prxedurc 2 95 Partial B and Temporary Change 6303 constituted the procedures for the Special test esolution.
The on site analysis of this event disclosed that there were fhe phases to this Special test evolution, as defined in Table 1.
The Special Test 2 95 Partial B prc(edure gave explicit instructions for reactor operation only for the fourth item in Phase 3, that is, the procedure gave no instructions for reactor operation during installation and removal of test circuits. The only applicable prxedure for reactor operation for the remainder of the evolution was QGP 2-4 as modified by Temporary Change 6303. The reactor scram during the event occurred during the performance of Phase 4.
There was no special tra.ining for Special Test evolutions.
2.2 Event Time Line The following event time line sequence was constructed based upon interviews with the station parsonnel listed in Table 2 and upon reviews of the control room logs and recordings and control room copies of Special Test 2 95 Partial B and Temporary Change 6303. The IRM recorders were operating on slow speed during the event and the station was attempting to decipher the recordings during the site visit (some entries in control room logs required interpretation):
2C6/90 Safety evaluation for Special Test 2 95 Partial B approved by the Quad Cities On-site Safety Review Board. The conclusion of the safety evaluation was that the Final Safety Analysis Report and the Technical Specifications were not affected and did not need to be changed.
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Table 1. Reactor operating cycle for performance of Special Test 2 95 Partial B. ' Unit 2 Turbine Generator Torsional Response Test'
Phase 1. Initial conditions Low power operation (- 10%).
Automatic reactor pressure control at -900 psi with 1 1/2 TBVs open.
Reactor power level is high enough for the void coefficient of reactivity to provide reactor power stability, infrequent notching of individual control rods used to adjust power les el.
Xenon at greater than equilibriurn due to power history, Phase 2, Installation of Special Test circuits on EHC controls Requires the EHC to be taken out-of service with main turbine secured and all TBVs shut.
Operating method scleeted is to reduce reactor power by inserting control rods until the automatic pressure control has shut all TBVs and then to continue reactor power reduction until the auxiliary steam loads have reduced pressure to less than 900 psig, Reactor power reduction by rod insertion will have little effect upon pressure reduction after reactor power is reduced below the dxay heat level
[below the Point of Adding Heat (POA10, Range 7 on IRMs). Pressure reduction will be determined by the auxiliary steam loads and ambient losses, which may not total much in excess of the decay heat levels.
Continued rod insertion may be required to compensate for the temperature affect on reactivity during cooldown and for possible decay of xenon.
Continued rod insertion may drive the reactor suberitical since power les el is too low for the void coefficient of reactivity to have much effect, Reactor criticality may be sensitive to rod motion on rods high in or on the periphery of the core due to xenon peaking in the central regions of the core.
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Table 1. (continued)
Phase 3. Operate Turbine generator per Special Test 2 95 Partial B.
Restore EHC.
Increase reactor power by notching out control rods until the increasing reactor pressure causes the automatic pressure centrol to begin to open a TBV.
Continue until in low power operation with one to two TBVs open.
Turbine generator will be operated at very low load with speed adjusted as requested by the Test Director.
Phase 4. Remove Special test circuits on EHC controls.
Reactor operation is the same as in Phase 2.
Phase 5. Return to normal commercial operation.
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e Table 2. Station personnelinterviewed
~
10/27 Shift 1: Unit 2 Nuclear Station Operator *
Shift Control Room Enginect'
i 10/27 Shift 3: Unit 2 Nuclear Station Operator Shift Control Room Engineer Shift Engineer
Shift Technical Advisor Nuclear Engineer Trai ig Manager Simulator Training Manager a. These operators were also on duty during the 9/28/90 attempt to perform Special Test 2 95 l
Partial B.
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9127!o0 Validation of Special Test 2 95 Partial 11 was signed off as completed.
The validation sign off form offers four validation methods:
Simulator p:rformance Plant walk through Bench check Tabletop check, which was selected.
Rev 0 of Special Test 2 95 Partial B received on site reuew and approval signatures.
?!.23L*Q Phase 2 of Special Test 2 95 Partial B (see Table 1) was attempted but not completed due to electrical problems with the EllC circuit.
An extra RO and SRO were assigned to the shift to perform the Special Test (the extra RO and SRO were the unit 2 NSO and SCRE on duty on shift I on 10/27/90 later in this sequence.)
10/24 E Temporary Change 6303 was issued against QGP 2-4, ' Shutdown from Power Operation to a Standby Hot Pressurized Condition,' to " allow the use of recircs (reactor coolant recirculation pumps) and/or control rods to reduce power to provide greater flexibility during power reduction to hot standby."
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10/27/oQ. Shift 1 (l1:00paJ0!/26 to 7:00 a.m.10/27)
Shift turnover.
11:00 p.m.
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Unit I at 95 to 100%
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Unit 2 at 141 htWe and preparing for turbine torsional test.
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hiade entry into Unit 2 drywell to disconnect drive from 11:45 p.m.
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IRhi 16 detector and manually insert detector, since remote drive was inoperable (drywell had been deinerted previously).
Reduced Unit 2 power to 1.30 hlWe and took turbine off 00:52 a.m.
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line.
Began inserting rods to come to Hot Standby.
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Unit 2 hiode Switch to Startup/Ilot Standby.
2:40 a.m.
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Began inserting rods to reduce reactor pressure to target
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value of 850-900 psi to close the TBVs and turn off EHC pumps.
Test Director for Special Test 2 95 Partial B was present
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(also the individual who planned the Special Test, is a licensed SRO, and has had experience as a nuclear engineer.)
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3:40 a.m.
Received Channel A half scram while ranging IRM 14 from
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range 7 to 6.
This appeared to be a spurious electrical problem. A 'near miss" memo was written to inform the on coming shift.
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(time approx)
The SCRE and the Unit 2 NSO could not understand step
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D.38.b and would not sign it as completed. The Test Director then annotated and initialled step D.38.b of operating procedure QGP 2 4 as complete.
"llot rod' condition experiersed (* hot rod' is terminology
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used by station operators for unusually high rod worth).
Significant IRM increase of 1 to 2 ranges resulted from one notch rod withdrawal. The auxiliary NSO assigned to the control room was directed to help observe IRM responses.
4:20 a.m.
Unit 2 reactor pressure steady at -830 psig. The EliC
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pumps were turned off.
Technicians began to connect test circuitry to EliC controls
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for Special Test 2 95 Partial 13 10/27/90-Shift 2 (7:00-3:00 p.m.)
7:00 a.m.
Shift tumover.
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Unit I operating at 710 to 780 MWe.
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At ilot Standby; reactor pressure -860 psig; drywell
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deinened twause of entry required during Shift 1; limiting condition for operation (LCO) action statement to reinert the drywell or in shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />;IRM 17 inoperable; 1RM 16 remote drive for detector inoperable.
Shift 1 o,wrators orally addse on-coming shi't 2 Unit 2
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operators of the ' hot rod' condition experienced. However, no written information was provided.
Turned on Unit 2 EHC pumps and began notching rods out 10:10 a.m.
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to increase power until I to 2 TIWs are open.
Began turbine warmup.
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Closed generator field circuit breaker for turbine torsional 12:20 p.m.
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test.
Adjusted Unit 2 ApRM gains to 7% power.
12:24 p.m.
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Began turbine acceleration.
12:26 p.m.
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Turbine speed seems to plateau out at 571 rpm, which is less 1:23 p.m.
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than minimum speed required for the turbine torsional test, i
Conference begins among the Special Test Director, other
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utility personnel, and vendor personnel concerning the turbine speed problem.
Opened generator field breaker and tripped the turbine,
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Shift 3 operators arrive on site and begin preparations for 2:30 p.m.
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assuming control at 3:00 p.m.
SCRE directed Special Test conferees to leave j
2:50 p.m.
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(approx)
the control room.
10/27/90 Shift 3 (3:00 to 11:00 p.m.)
Unit I at 710 to 780 MWe.
3:00 p.m.
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Unit 2 on * hold" for Special Test 2 95 partial B, -7%
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power,1 1/2 TBVs open,920 psig.
Four out of eight IRMs had problems [the A channels have
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one in * bypass' and one with caution tag because of 1/2 scram on Shift 1, and B channels have one on " bypass' and one (#16) with detector inserted but with inoperable remete detector drive.]
Unit 2 was in LCO action statement to reinert drywell with
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approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> remaining or be in shutdown.
Withdrawal of IRM #16 would require entry into drywell.
Reinerting drywell would require 10 to 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> elapsed time.
No information conceming the " hot rod' experience during
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shift I was passed on to the on coming shift 3 Unit 2 operators.
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Conference was still on going concerning the problem with
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the Special Test 2 95 and was taking place near SCRE's dest with use of SCRE's phone.
Conference resumed in SE's of6ce.
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Decision made by conferees in SE's office to abort Special 3:10 p.m.
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Test 2 95 Partial B and return Unit 2 to commercial power generation. The IRM 16 detector with the inoperable drive was left inserted, w hich would destroy (bum-out) the detector during power operation.
SE directed the SCRE by telephone to insert control rods to
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take the EHC off line and began directions to other personnel for reinerting the drywell and other preparations for disconnecting the Special Test equipment and returning Unit 2 to power operations.
Nuclear engineer 'on call," who had been called to be
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present for the Special Test, left site since the test was aborted.
SCRE directed Unit 2 NSO to insert control rods to reduce
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(
reactor pressure to less than 800 psig. (During similar l
maneuver on shift I the pressure was not reduced below
~ 860 psig. The purpose of the pressure reduction was to prevent an increasing pressure reaching 920 psig and signal j
l the TBVs to open. The SCRE on shift 3 was opting for a larger pressure margin to prevent this. However, this would
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require more rod insenion.) Unit 2 NSO began insening control rods per step D.38.b of QGP 2 4.
3:30 p.m.
Unit 2 NSO continued rcd insertion.
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Founeen rod groups were insened, a total of 84 steps.
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Unit 2 NSO was observing pretsure decrease with objective
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of decreasing pressure to less than 800 psig.
Unit 2 NSO stopped rod inwnion at -850 psig
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IRM indications decreased from Range 6 to I (reactor was
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signincantly suberitical, however, Unit 2 NSO was still focusing attention on reactor pressure).
At 805 psig the TBVs were completely closed by the
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automatic pressure control and the EHC pumps were turned off. Reactor pressure was decreasing. Unit 2 NSO attempkd rod withdrawal to increase pressure.
3:43 p.m.
Rod block annunciator indicated that rod withdrawal was
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blocked due to source range monitor (SRM) indication being less than 100 cps and SRMs not fully inserted. Unit 2 NSO began inserting SRMs to increase their indicated level, t
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3:57:45 p.m.
Rod block cleared as SRMs were being inserted. Reactor
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pressure was 770 psig.
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Unit 2 NSO tegan rod withdrawal to increase reactor
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3:58 p.m.
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pressure; withdrew one Group (G 7, G 9, J 9, J 7) from
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posit on 04 to 06; then withdrew rod G 7 from position 06 j
to 08, i
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Unit 2 reactor scram from IRM Hi Hi trip.
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3:59 p.m.
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(Note: No signi6 cant changes in reactor feedwater now or
reactor water level occurred during the 3:30 3:59 time
interval relative to reactivity.)-
Entered procedure QGP 2 3 for Hot Shutdown.
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c 2 3 Amtlysis
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2.3.1 Task Awarene13
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A dominant factor underlying all other factors of this event was a low level of awareness that the reactor operation tasks required by the Special Test 2 95 on the Unit 2 turbine generator y
might require special attention. Table I was prepared during this event analysis to identify Ove
different phases of reactor'operstlo that were required to perform the Special Test. This tabulation indicates that Phase 2 and 4, the installation and removal of Special Test circuits on the EHC controls, may require special attention to reactivity management to avoid either
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- subcriticality or short reactor startup periods. However, the event analysis indicated that a low
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level of task awareness for reactivity management persisted through the preparation and conduct -
intervals for the Special Test.
The reactor was to be maintained in Hot Standby with the TBVs shut lduring Phase 2 and 4.
Maintainlog the reactor critical in Hot Standby with the TBVs shut is an infrequently performed-15-f
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operation of limited durations since the normal operating plans would usually call for continuing on either to Hot Shutdown or to Power Operation.
Safety Evaluation 90 601,9/24/90, which was prepared for Special Test 2 95, Partial B, does not address reactivity management during the Special Test. Temporary Change 6303 to QGP 2 4, ' Shutdown from Power Operation to a Standby Hot Pressurized Condition,' was prepared by deleting those parts of QGP 2-4 that were not needed to support the Special Test 2-95 to provide greater flexibility during power reduction to hot standby. Temporary change 6303 did not add any notes or cautions to QGP 2 4 As summarized below QGP 2 4 is not explicit for reactivity management of the Phase 2 and 4 condition (Table 1) and contains no cautions for possible high rod or notch worth.
2.3.2 Pro:cdures The controlling procedure for reactor operations for the SpecirJ Test was Temporary Change 6303 to QGP 2 4, ' Shutdown from Power Operation to a Standby Hot Pressurized Condition." As noted above, QGP 2 4 has no cautions for reactivity management. The possible need for a caution is demonstrated by the fact that QGP l 2, " Unit Startup to Hot Standby,' has a caution concerning the possibility of high rod and notch worths existing after a shutdown from power operations. QGP l 3, ' Hot Standby to Power Operation,' has a similar caution that is more generally worded and is not restricted to specific, limited rod positions.
The control room copy of the controlling procedure, Temporary Change 6303 to QGP 2-4, had been initialled as complete through Step D.38.b by the Shift 1 operators. The Shift 3 Unit 2 NSO was using the marked up copy of the procedure for guidance, but was not formally following the procedure. There was no procedure covering the complete sequence of reactor operations outlined in Table 1.
At the time of the event, the Unit 2 NSO had Temporary Change 6303 on his desk and was attempting to carry out the SCRE's command to reduce possure to less than 800 psig in
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accordance with Step 38 b of Temporary Change 6303. The 'less than 800 psig' is a variation l
from the '920 psig' in step 3.8.b.:
'
b.
Insert control rods until reactor pressure equals 920 psig and the reactor
is suberitical by at least 'bree rods.
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The Unit 2 NSO copy of Temporary Change 6303 contained an added handwritten note:
'
' Impossible to tell exact number of rods suberit., took pressure to 825 psig,' adjacent to step 38 b and the step had been initialled off by the operating engineer on shift 1 of 10/27/90. -The insertion of the control rods until the reactor power was below the range of the IRMs was
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consistent with the controlling procedures.
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p j
To sumtnarize, the controlling procedure for the Special Test had no special instructions for reactor power or reactivity control or cautions for high rod or notch worth and relied instead
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upon the QGps for Hot Standby. The adequacy of these QGPs in this respect is questionable and
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is under review by the Quad Cities Station staff.
,
A signal occurred on shift 1 of 10/23/90 that could have alerted the control room crew to the possibility of a problem in the use of the controlling procedure for the Special Test. That signal was the request by the SCRE and Unit 2 NSO for help in interpreting Step D.38.b of
- Temporary Changes 6303. The request was resolved by the e crating engineer on shift I who
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discussed Step D 38.b with the SCRE and the Unit 2 NSO, a.motated and initialled the step on
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the control room copy of Temporary Change 6303 as complete. This resolution was apparently
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adequate for shift 1, as no reactivity management anomaly occurred on shift 1. ' A preferred resolution would have been to put the test on hold and initiate a change request for the controlling procedure. The change control process may have uncovered the fact that QGP
<
- 2 4 was missing the caution with respect.to high rod notch worths that existed in QGp 12 and -
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. QGp 13 However, it may not have uncovered the knowledge that central rods may have a high notch worth when these tips are near the top of the core, since that knowledge was not widely available. A full resolution to the interpretation and usage of Step D.38.b would have required p
.
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a higher lese; of task awareness, specincally, a greater knowledge of the possit>1e sensitivity of the reactivity management task during the test planning and pro:cdure preparation stages.
2.3.3 Itaining No special training was requested for this Special Test and there was no simulator dnll, classroom instruction, or " read only' instructions for the control room operators. Further, there was no lesson plan that specincally covers reactivity management in llot Standby conditions.
110t Standby may be transitioned during some simulator exercises but the high rod notch worths experienced on 10/27/90 would not have been simulated. Maintaining criticality in liot Standby was not included in previous Requalification training.
On the job training or experience in reactivity management in llot Standby is limited since this is an infrequent condition. The Unit 2 NSO operator who had experienced the scram could not recall any time since 1982 that he had been involved in 110t Standby operations.
The Requal/Remediation lesson Plan that was issued on 10/31/90 and the 110t Sta, dby Operations lesson plan for SRO/RO licensee training that was issued on 10/T0/90 define training that would have been appropriate for supporting operations during the 10/27/90 event.
2.3.4 Dinemination of Oncrating Expejiensc_lafetalall2D An SRO was assigned to review the reactivity management event that occurred at 12 Salle on 6/23/1990, liowever, no written information on the significance of this event relative to Quad Cities was prepared for the reactor operators.
Special Test 2 95 had been attempted on 9/28/90 and Phase 2 and 4, installation and removal of the test circuits on the EHC controls, was performed. An extra SCRE and NSO were present at the Unit 2 controls for this trial. No written information on the reactor control
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experience during this 9/28/90 test run was prepared for the benefit of other reactor operators or other station staff.
phase 2 of Special Test 2 95 was performed by the 11:00 p.m. to 7:00 a.m. shift on the morning of 10/27/90 High notch worth had been experienced and understc=xt by the NSO and the SCRE (who incidentally were the same NSO and SCRE at the controls on 9/28/90). No wntten information on this experience was prepared; there was no entry in the logs. Oral information was passed on during the turnover to the 7:00 a.m. to 3:00 p.m. shift, howeser this shift did not pass this information on to the 3:00 to 11:00 p.m. shift who ultimately ey=enenced the scram at 3:59 p.m.
2.3.5 C2mmunicalicas The low lesel of awee.ess of the teactor operatior.s task demands that existed during the
,
planning of Special Test 2 95 was followed by a low level of communications that existed among the station operators as demonstrated by the following information from the on site anal) sis.
The command communication from the SE to the SCRE by telephone was to reduce l
pressure, turn off the EHC pumps, remove the Special Test circuits, and restore the EHC to service. The command communication from the SCRE to the Unit 2 NSO was to reduce the
pressure to less than 800 psig to permit tuming off the EHC pumps.
There was no communication from the Unit 2 NSO to the SCRE to acknowledge understanding of the l
.
command or to report progress in execution of the pressure reduction. Immediately before the l
l teram, the SCRE realized that the Unit 2 NSO was pulling rods and that the SRMs wcre fully inserted, but there was no communication between the SCRE and the Unit 2 NSO.
l l
2.3.6 Command and control The low level of communication among the SE, the SCRE, and the Unit 2 NSO implies a diminished level of command and control of the Unit 2 reacte ss does the absence of a brief
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review by the shift 3 operators of the planned operations for the shift prior to initiating a significant change in the operating mode of the reactor.
There were several factors that contnbuted to the diminished status of command and control: (a) the continuously low lesel of task awareness, which perhaps was compounded by a shift turnover during which there many people in the control room; (b) the conference in the control room among the SE and other station staff concerning a decision as to whether to return to power or to shutdown; (c) the need to resolve the question concerning the time hmit on at LCO which required reinerting the drywell versus the inoperable IRM detector drive which would require entry into the drywell to repair; (d) concern about the reliability of other IRM channels; and (c) when the Unit 2 NSO began to lower reactor power to reduce pressure, the SE and the SCRE were involved in reinerting the drywell and other activities pursuant to returning to power.
A command to hold the existing reactor operating mode until the situation was reuewed among the SE, the SCRE, and the Unit ? NSO would have been appropriate, liowever. gnen the low levels of task awareness and communications and the absence of detailed operating instructions, precautions, and training for phase 2 and 4 of the Special Test, it cannot be determined if a ' hold and review' command would have prevented the reactor scram.
2.3.7 Knowledge based Versus Rule based Omatis The expected range of knowledge of an NSO includes the fact that Range 6 of the IRMs is below the POAH as is the heat balance principle that resul's in little effect on pressure reduction if the reactor power is reduced below the pOAli, llowever, it appears that the Unit 2 NSO was in a rule-based mode of operation, as he was fixated on following step 38 b of Temporary Change 6303, ' Insert control rods until reactor pressure is less than 920 psig and the reactor is suberitics),' as modified by the SCRE's direction to reduce pressure to less than 800 psig. His knowledge base would have told him that it was unnecessary to reduce power below Range 6, however, a rule based manner of operation is self reinforcing. Once an operator is engaged in executing a set of specific rules, the operator will tend to continue until some signal alerts him to reconsider, such as an annunciator alarm, a procedural caution, a cautionary
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principle retained from training, or a communication from another control room team member.
In this event no such signal was present and the Unit 2 NSO had con 6dence stemming from a use of the procedure by a presious shift as attested by the initials of ra eywrienced operating engineer.
Once the reactor power was down to the bottom of the range of the IRMs, the stage was l
set for obtaining a short reactor period and Hi Hi IRM scram due to the combined effiret of reactor cooldown, xenon decay, and high notch worth of the center control rods.
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3. SUMMARY OF FINDINGS There were several human factors ' hat were evident contributors to the reactivity transient and Hi Hi IRM scram on October 27,1990. Mc, wever, our analysis indicates that the factor that underlay all the other factors was a low level of task cwareness concerning the management of reactivity by the reactor operator when operating in a post shutdown, Hot Standby mode.
Several conditions combine to present a urique challenge to the reactor operator who is executing this task: increased control rod notch worth due to post shut 6own xenon conditions, variable levels of decay heat, low level of control of heat removal, and low level of negative reactivity feedback from temperature changes or void formation. In addition planning for the turbine torsion.' response test apparently did not consider the possibility that operations during preparation for and restoration from the test would be mcre challenging than operation during the test itself.
Given this low level of task awareness at the test planning stage, there would not hue been
"
a strong signal to review the written procedural instructions and cautions, the task specific training, ar.d the command and control structure and staffing for the entire Special Test evolution. These were the human factors that ultimately led directly to the unanticipated, automatic scram.
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