ML20080M438
| ML20080M438 | |
| Person / Time | |
|---|---|
| Issue date: | 01/31/1984 |
| From: | Massaro S, Trenery S NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| References | |
| NUREG-BR-0051, NUREG-BR-0051-V05-N4, NUREG-BR-51, NUREG-BR-51-V5-N4, NUDOCS 8402170513 | |
| Download: ML20080M438 (24) | |
Text
NUREG/BR-0051 Vol. 5, No. 4 gmeg&POWER REACTOR EVENTS tw%.. /
United States Nuclear Regulatory Commission (h(l Date Published: J anuary 1984 Power Reactor Events is a bi-monthly newsletter that compiles operating experience information about commercial nuclear power plants. This includes summaries of noteworthy events and listings and/or abstracts of USNRC and other documents that discuss safety related or possible generic issues. It is intended to feed back some of the lessons learned from operational experience to the various plant personnel, i.e., managers, licensed reactor operators, training coor-dinators, and support personnel. Referenced documents are available from the USNRC Public Document Room at 1717 H Str:et, Washington, DC 20555 for a copying fee. Subscriptions and additional or back issues of Power Reactor Events may be requested from the NRC/CPO Sales Program,(301) 492-9530, or at Mail Stop 016, Washington, DC 20555.
Table of Contents Page 1.0 SUMNIARIES OF EVENTS 1.1 Improper Control Rod Manipulations..
1 1.2 Uncontrolled Leakage of Reactor Coolant Outside Primary Containment (Update from Vof. 5, No.1)....................
5 1.3 Slow MSIV Closure Times Due to inadequate QA on Replacement Parts..
10 1.4 Inadvertent Reactor Vessel Drainage During Shutdown..
11 1.5 Damage to Reactor Coolant System Components.............
13 1.6 Reactor Trip Resulting from Sealinjection System Leak..
14 1.7 Unexpected Loss of Offsite Power to Safety-Related Buses.......
16 1.8 Reactor Trip with Indicated Slow Feedwater Flow Reduction Times..
18 1.9 References................
20 2.0.ABSTRA CTS OF OTHER OPERA TING EXPERIENCE DOCUMENT 2.1 Abnormal Occurrence Reports (NUREG-0090)........
23 2.2 Bulletins and information Notices.......
24 2.3 Engineering Evaluations andCase Studies...
34 2.4 Generic Letters..........................
38 2.5 Operating Reactor Event Memoranda........
41 2.6 Regulatory and Technical Reports (NUREG-0304).............
42 Editor: Sheryl A. Massaro Associate Editor: Steven E. Trenery Office for Analysis and Evaluation of Operational Data U.S. Nuclear Regulatory Commission Period Covered: J uly-August 1983 Washington, D.C. 20555 8402170513 840131 PDR NUREC BR-OO51 R PDR
- 1. 0 SUMARIES OF EVENTS 1.1 Improper Control Rod Manipulations 1The following events involving improper control rod insertions and other.
violations at-Quad Cities Unit 1* and Hatch Unit 2** demonstrated breakdowns in plant management control systems designed to control operations activities and
' ensure safe _ operation of the facilities.
Quad Cities Unit 1 On March 10 and 11, 1983, the plant'was.being shut down for.a scheduled main-tenance outage.
During the day shift on March 10, the nucir c engineer requested to have the rod worth minimizer.(RWM) bypassed so he that could load a new shutdown control rod sequence _into the RWM computer.
The RWM serves as a backup to procedural controls to limit control rod reactivity worth during startup and low power operation; this helps limit the reactivity addition rate in the event of a control rod drop accident.
The system blocks (prevents) rod movements if the existing control rod pattern deviates from a specific sequence which has been developed by the plant nuclear engineers and loaded into the RWM computer memory.
Due to lower rod worths at higher power levels, the plant's procedures do not require the RWM to be operable above 20% reactor power.
After the nuclear engineer loaded the new rod insertion sequence into the RWM computer, he gave the unit operator the new shutdown rod insertion sequence procedure (designated QTP 1600-S3, dated March 9, 1983) and an RWM control rod sequence computer printout (which was a rod withdrawal sequence intended to be reversed for the pending rod insertion sequence).
The RWM was left in the bypass condition with reactor power still above 20%.
Following shift change, th_e nuclear engineer prepared a handwritten explanatory l
note to_the sequence procedure and gave it to the day and evening shift unit operator _and shift engineer.
Reactor shutdown was to begin during the evening shift.
An extra operator, scheduled for the night shift, was called in early to assist with control. rod insertion because the evening shift unit operator was performing numerous-surveillance tests. - The extra operator reviewed the handwritten note and the computer printout, and mistakenly concluded that the rods should be inserted in the sequence listed on the RWM computer printout.
(The evening shift unit operator also agreed with the extra operator's
! interpretation.) As discussed previously, the sequence was a rod withdrawal sequence that was the reverse of-the proper sequence given in QTP 1600-S3.
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- Quad Cities Unit 2:is a_769 MWe (net) BWR located 20 miles northeast of Moline, Illinois, and is operated by Commonwealth Edison.
- Hatch Unit 2 is a 771 MWe (net) BWR located 11 miles north of Baxley,
' Georgia, and is operated by Georgia Power.
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At about 8:00 p.m., the extra optrator began insarting control rods.
By 10:15 p.m., the extra operator had ir.serted 33 control rods improperly; at the time, reactor power was about 30%.
In addition, contrary to procedures, recirculation pump speed was not manually reduced at set intervals during control rod insertions. The pumps automatically ran back to minimum speed, reducing reactor power to about 20%.
At 11:00 p.m., the night shift came on duty.
At about 11:10 p.m., the oncoming unit operator returned the RWM to service.
The RWM automatically prevented additior.al rod movements because of the out of sequence control rods, but did not display any error messages because there were so many insertion errors.
After failing to clear the rod block, the unit operator (after discussion with the shift engineer) declared the RWM inoperable, and it was again bypassed at 11:18 p.m.
The unit operator requested the extra operator to continue rod insertions.
Ten more control rods were improperly inserted, reducing power i
from about 20% to 9%; at thic point, the reactor was manually scrammed as part of normal shutdewn procedures. On the following morning (March 11), plant management discovered that the control rods had been inserted in reverse order using the RWM computer printout.
Had the plant reached very low power levels, the improper insertion of the control rods and the bypassing of the RWM could have affected the plant's ability to withstand a rod drop accident (in which a control rod suddenly drops from the reactor core, resulting in a rapid, localized increase in power and possible damage to the surrounding fuel rods).
In this case, no fuel damage occurred and General Electric, the reactor vendor, determined that safety margins were not seriously degraded.
The unit was manually scrammed at 9%
power, a level well above the point where safety margins would have been significantly reduced.
The event, together with numerous other violations identified by the licensee's and NRC's investigations, however, raised concerns regarding plant management control systems designed to control operating activities and to ensure safe, controlled shutdown of the reactor.
Hatch Unit 2 On July 14, 1983, during normal startup activities from a refueling outage, the plant was operating at about 25% power.
Problems with main condenser vacuum had occurred and air ejector troubleshooting was in progress.
Condenser vacuum began to decrease and the turbine was unloaded and tripped.
Control rods were inserted in an attempt to reduce reactor power to within the limit of the mechanical vacuum pump so that it could be placed in service to maintain vacuum above the trip setpoint of the reactor feed pumps.
A reactor feed pump low vacuum trip would cause a loss of feedwater flow to the reactor vessel.
To reduce power more quickly, the licensee bypassed the rod worth minimizer (RWM) and assigned a second licensed operator to verify control rod movement, as permitted by the technical specifications.
At one point, the emergency rod-in position switch was used to achieve the greatest possible insertion rate.
When the operator reached groups of low worth peripheral rods in the sequence, a collective discussion among the licensed operators an1 their supervisors in 2
the centrol rcom result:d in a d: cision to scran individual rods by using the individual scram switches at the scram timing panel.
There was no approved procedure for this method of shutdown.
This action resulted in the insertion of rods in an out of sequence manner.
Vacuum at the time vas about 1/2 inch above the trip setpoint.
While the plant operator continued inserting rods at the front panel, two other operators began to insert rods at the scram timing panel.
When the front panel operator observed those rods going in, he stopped inserting rods and verified further insertions from the scram panel. A process computer output indicated several rods were not fully inserted (i.e., the scram toggle switches were not held down sufficiently long).
These rods were subsequently rescrammed.
One rod that had not been manipulated was also found mispositioned. Because of this one mispositioned rod, the reactor was scrammed as required by procedures.
The consequence of this event was operation of the reactor outside of the acci-dent analyses contained in the plant's Final Safety Analysis Report.
In addi-tion, the RWM, which is used to minimize the effects of a rod drop accident, was bypassed, and a control rod configuration resulted that had not been analyzed.
The use of a second operator to verify control rod movements was apparently ineffective in preventing mismanipulations, as evidenced by the mispositioned rod position.
In addition, the rod sequence control system (RSCS) was also effectively bypassed.
The RSCS is a backup system to the RWM and independently imposes restrictions on control rod movements to mitigate the effects of a control rod drop accident.
The plant's technical specifications require the RSCS to be operable when the reactor power is below 20%.
However, the use of the emer-gency rod-in position switch and the scram switches on the scram timing panel circumvented the RSCS.
Although no apparent fuel damage occurred, the event and related violations identified by the NRC's investigation raised concerns regarding the application of management resources to the overvie i of facility operations.
Causes and Corrective Actions For both events, there was a weakness in the plant management control systems, as evidenced by the number of procedural violations, the number and types of personnel involved, the poor judgment exercised by control room staffs, and the insufficient guidance provided by management.
j Quad Cities Unit 1.
The following corrective actions were taken pertaining to the control rod insertion error event.
(1) The station superintendent met with each person involved in the incident to discuss his or her understanding of the event, and personally emphasized the importance of accountabiity for actions taken.
In addition, the sta-tion superintendent conducted accountability meetings with all plant personnel.
(2) A committee was forned to implement a special program to monitor all the work activities of control room personnel involved in the event.
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(3) A n:w system for control rod cov:ments and sequ nces was establish:d, providing clearer instructions and a better means of documenting rod movements.
To implement this system, station procedures were revised to direct responsibilities and provide instructions.
(4) The RWM procedures were revised to provide better instructions for opera-tion, sequence loading, initializing, and determining operability.
(5) Training was accomplished on the above procedures for control room employees.
In addition, in terms of general control room conduct, procedures and practices were reviewed and rewritten to improve the quality of interpretation, to foster adherence to all procedures, and to enhance communication among control room personnel during shift turnovers.
The NRC performed a special safety inspection during March 1983 of the cir-cumstances associated with the Quad Cities event.
Violations were identified involving failure to follow shutdown procedures, failure to accurately document actions completed, failure to record operating conditions and equipment status, failure to perform proper shift turnover, and failure to maintain proper overall perspective of faulty operations.
On June 21, 1983, the NRC issued a notice of violation and proposed imposition of civil penalties in the amount of $150,000.
In addition, the NRC expressed concern over the performance of certain operating personnel during the event.
A special enforcement conference was held on October 20, 1983, between those individuals and senior NRC management to discuss the Quad Cities performance.
A separate enforcement conference had been held previously with the licensee's management on March 29, 1983.
On August 12, 1983, the licensee paid the civil penalty and described the corrective actions taken.
These actions will be examined during-future NRC inspections.
Hatch Unit 2.
Upon being notified by the NRC Resident Inspector of individual rods being scrammed from the scram timing panel without authorized procedures, senior onsite plant management immediately relieved all involved operators and shift technical advisors of control room duties.
Senior licensee management counselled the individuals on their improper actions.
Appropriate procedures, simulator and other training techniques, and other orders to control room personnel either have been or will be modified to clarify corrective actions and to prohibit those actions which resulted in the event.
The licensee also conducted a " lessons learned" program for operators during the week of August 4, 1983.
Further actions may be necessary in response to pending NRC enforcement actions.
The NRC performed a special inspection on July 14 and 15,1983, of the circum-stances associated with the Hatch event.
Three violations were identified involving failures to follow procedures for reactor operations, and failures pertaining to operation of the RWM and RSCS.
The NRC participated in the licensee's " lessons learned" program to discuss the event from the perspective of the NRC.
An enforcement conference was held in early November 1983 between licensee and NRC personnel.
Three sessions were 4
conducted:
th2 first with non-suptrvisory senior reactor operators, reactor operators, and shift technical advisors; the second with supervisory and non-supervisory personnel involved with the event; and the third with corporate and plant management.
On November 3, 1983, the NRC issued Inspection and Enforcement Information Notice No. 83-75 to inform licensees of the Quad Cities Unit 1 and Hatch Unit 2 events.
(Refs. 1 through 3.)
1.2 Uncontrolled Leakage of Reactor Coolant Outside Primary Containment -
Update from Vol. 5, No. 1 During August 1983, the NRC staff completed a preliminary report (Ref. 4) regarding a plant systems interaction event which occurred at Hatch Unit 2* on August 25, 1982.
(This event was discussed briefly in Power Reactor Events, Vol. 5 No. 1, as "RCIC Switch Failure Due to Cocrosion," pp. 16-17.) As described in the report, a complex series of systems interactions during post-scram recovery operations resulted in a sustained and uncontrolled Icss of hot pressurized reactor coolant outside primary containment, and had the potential to threaten the operation of certain vital equipment.
During power operation on August 25, 1982, the main valve disk of the C main steam line isolation (MSIV) had separated from the valve stem, resulting in the valve closing unexpectedly, The closure of the MSIV caused a reactor scram from high power due to the pressure increase associated with the shut valve.
In addition, the closure of an MSIV caused an isolation of the remaining MSIVs, steam line drains, and reactor water sample lines (Group 1) because of increased steam flow in the three open steam lines.
The Group 1 isolation automatically closed all MSIVs.
With the reactor scrammed and. isolated, pressure began to increase quickly towards the opening pressure of the safety relief valves (SRVs).
By a combina-tion of automatic and manual opening of two SRVs, reactor pressure was brought back down to approximately 900 psig. The reactor scram and vessel isolation also resulted in a rapid shrinkage of vessel water level down to the low-low level setpoint, initiating both the high pressure coolant injection (HPCI) system and the reactor core isolation cooling (RCIC) systems.
However, the combination of injection flow coast down from the turbine driven reactor feed pumps and SRV operation quickly brought water level back up to the high level trip setpoints for HPCI and RCIC.
Accordingly, even though both systems had automatically started, no injection occurred prior to tripping off line.
With level restored and pressure stabilized, the control room operators prepared to reopen the closed MSIVs by first resetting the Group 1 isolation signal which had cleared.
Isolation reset allowed pressure equalization around the closed MSIVs via the steam line drain lines which had also isolated during the event.
When all initial reactor trip conditions had cleared, the operators reset the scram, allowing the scram discharge volumes to begin draining and depressurizing.
By this time, the RCIC system was manually restarted for level control of the
- Hatch Unit 2 is a 771 MWe (net) BWR located 11 miles north of Baxley, Georgia, and is operated by Georgia Power.
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isolated vessel.
How3 var, invsntory loss through tha main steam line drain lines resulted in a low reactor water level alarm condition even though RCIC was operating. When this occurred, HPCI was manually started to restore water level.
During the scram, the scram discharge volume drain line isolation valve, which received a close signal, did not fully close.
The result of this malfunction, caused by a loose valve body-to-operator yoke, was that an open flow path existed between the raactor coolant system and the reactor building equipment drainage system.
Operations personnel observed that fluid temperature and level in the reactor building equipment drain sump were rising well beyond expected values.
Based on the averall indications in the reactor building, operations personnel concluded that high temperature scram exhaust water from the still pressurized reactor was discharging at high pressure into the reactor building equipment drainage system.
To terminate the discharge of high temperature fluid into the reactor building, the control room operators realized it would be necessary to reset the scram, which would close the outlet scram valve and effectively isolate the reactor coolant system from the reactor building equipment drain system.
Normal reset of the scram was not possible, however, because shortly after the scram, drywell pressure had risen above the high pressure scram setpoint, initiating a second scram signal which was.still in effect.
This second scram signal had occurred because, as the operators were maintaining pressure by use of safety relief valves, one of the safety relief valve tail pipe vacuum breakers apparently mal-functioned and allowed a momentary steam release into the drywell, pressurizing the drywell to above the drywell high pressure scram setpoint.
Another compli-cation was that the high drywell pressure also initiated a load sheddir.g logic that secured electrical power to the drywell chiller units, which would have been the normal means of reducing the high drywell pressure.
The load shedding logic also tripped the control rod drive (CRD) pumps, resulting in a loss of cooling flow to the CRD seals.
Eventually, CRD temperatures increased to over 500 F, compared to their normal operating range of 160 F to 200 F; however, there was no indication of damage to the CRD seals.
Meanwhile, the RCIC system, which was being used to maintain reactor vessel water level, malfunctioned while it was injecting into the vessel and isolated on an erroneous high turbine exhaust diaphragm pressure signal.
This isolation was caused by instrument drift which had occurred due to abnormally high tem-peratures in the RCIC equipment room.
These abnormally high temperatures, in turn, were caused by the release of steam from the equipment drainage system to the RCIC room via an opening in the drainage system caused by a missing threaded stainless steel pipe cap.
The cap normally was installed on a short drainage hub located in the RCIC room.
The steam in the drainage cystem was the result of the blowdown through the partially open scram discharge volume valve to the drainage system.
Operations personnel started a reactor feed pump and used the feedwater system and main condenser to maintain reactor vessel level.
The high drywell pressure signal was electrically jumpered and the drywell chiller unit restarted.
Inis action reduced drywell pressure to the point where the reactor scram caused by high drywell pressure could be reset.
When this.ction was accomplished, the 6
leakagn of thm rarctor coolant system to tha reactor building equipm nt drain-age system was halted.
The total elapsed time from the initial reactor scram imtil the second scram was reset, was approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
Several otherwise unrelated failures combined to cause the complex chain of events which occurred.
As discussed above:
(1) An MSIV closed unexpectedly when the main valve disk separated from the valve stem.
This was caused by disengagement of the poppet from the stem.
(2) The loss of the drywell chiller units occurred when they were tripped off-line because of load shedding logic associated with their safety buses.
This load shedding feature was provided to prevent a potential faulted con-dition associated with the nonseismically qualified and nonenvironmentally-qualified chiller equipment from adversely affecting the emergency power supplies during a postulated loss-of-coolant accident inside containment.
(3) The safety relief valve discharge to the drywell is believed to have been caused when the valve opened normally but its associated tail pipe vacuum breaker stuck in an open or partially open position.
Thus, when the valve lifted a second time, the stuck open vacuum breaker allowed steam to be released directly into the drywell.
(4) The scram discharge volume drain valve failure was caused by a loose valve body-to-operator yoke which prevented the attached air operator from seating the valve plug tightly into its seat.
(5) The missing RCIC room equipment drain hub cover was probably removed several months earlier during RCIC room equipment maintenance or testing activities.
Removal of this cover allowed hot steam to escape from the opening, which wetted down and significantly increased the temperature of the electrical equipment and devices located in the room.
The increased temperature also set off the fire suppression system sprinkler head located above the drain system opening.
These adverse conditions caused instrument drift of devices located in the room, including the trip setting for the Barksdale pressure switch used for the RCIC turbine exhaust diaphragm high pressure isolat. ion function. This switch's setpoint was found to have l.
drifted from 8 psig to O psig.
The event is significant in that it resulted in sustained and uncontrolled l
leakage of the reactor coolant outside primary containment.
This indicated the potential for a serious and simultaneous degradation of both the reactor coolant I
pressure boundary and the primary containment boundary.
Primary coolant dis-charged through a partially stuck open scram discharge volume drain line isola-tion valve into the equipment drain system, subsequently discharging to the open areas of the reactor building through an open drain hub.
The scram discharge volume drain line has an inside diameter of 2 inches.
Even though the isolation l
valve was only partially open, this represented a direct flow path for the pri-mary coolant, and indicates the potential for an even more significant degrada-tion of the primary coolant boundary.
The resultant harsh environment in the reactor building shut down the operating high pressure injection system impor-l tant to safety (RCIC); had the valve failed completely and the leakage been lar-ger or significantly prolonged, the possibility existed that other vital equip-ment located in the reactor building could have been threatened.
During the
' vent, adequate core cooling capability was available to protect fuel integrity.
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The MSIV manufactursr, Rockwell International, had investigated the cause of similar, earlier, valve failures at Hatch and other facilities and had recom-sended three potential solutions to the disk-to-stem disassembly problem for the Rockwell valves.
These recommended actions had either not been finalized or not been adequately evaluated and implemented for Hatch at the time of the event. The licensee has since replaced the entire disk and stem assembly in both the inboard and the outboard isolation valves on the C steam line.
In addition, the licensee plans to implement the MSIV lockpin installation as recommended by the valve supplier.
This work will p*obably be accomplished in the upcoming Unit'2 refueling outage; furthermore, a procedure will be issued requiring MSIV inspection during each refueling outage after these modifica-tions are completed.
Regarding the scram discharge volume drain valve failure, the licensee had earlier (February 1981) proposed plant technical specification changes which would include the scram discharge volume vent and drain valves in the facility surveillance requirements.
However, the proposed surveillance requirements did not meet NRC requirements, and the licensee acknowledged that revisions to the technical specifications were necessary.
However, the licensee did not submit revised technical specifications.
Therefore, revised technical specifications were not implemented at the time of the event.
The licensee subsequently sub-mitted revised technical specification in September and December 1983, as required by an NRC confirmatory order.
Following issuance of NRC Inspection and Enforcement Information Notice No. 83-44 (Ref. 5), the licensee performed a walkdown to determine the potential for flood propagation through equipment and ficor drains.
This walkdown veri-fied that drain hubs on the 87-ft (basement) elevation were capped.
Further-more, the caps have been tack welded to drain hubs to assure they remain in place.
To prevent the recurrence of a missing drain hub cap, administrative controls over drain hub caps will be upgraded.
A specific maintenance author-ization will be required to break the weld to remove the caps.
The maintenance procedural controls involved will also be revised to specifically address the need to replace covers following completion of the activities requiring their removal.
Prior to being returned to service, those instruments associated with RCIC circuitry that experienced contact with an adverse environment were dried out, inspected, calibrated, functionally tested, and/or replaced as required.
In addition, a previously planned analog trip system, incorporating transmitters and bistables to correct for the RCIC system instrument drift problem, will be installed to replace the mechanical switches and trip devices used in the cur-rent instrumentation and control system.
The scram discharge header drain valve that allowed reactor coolant steam to escape into the RCIC room was inspected, disassembled, cleaned, properly reassembled, and satisfactorily tested after installation.
The potential for loss of coolant through the scram discharge system is a generic concern and is the subject of several new NRC requirements.
These include the installation of redundant scram discharge volume vent and drain valves, and technical specifica-tions for periodic surveillance of these valves.
These requirements are being 8
implem3nted at the Hatch units and will be complete in the near future.
Imple-m:ntation of these requirements thould significantly reduce the probability of a recurrence of the subject event.
Loss (by design) of drywell chillers occurred due to the high drywell pressure Operators were unable to reset the chiller due to the existing scram scram.
signal.
Site personnel have been trained on bypassing signals in general.
It is felt that this training, along with operator training on the functions of systems that would allow signals to be bypassed, if needed, in this or other systems on'an emergency basis, is adequate corrective action.
The control rod drive (CRD) pumps were also lost due to the high drywell pres-This resulted in a long period of time without CRD seal cooling, sure scram.
which caused elevated CRD seal temperatures.
To allow manual restart of the CRD pumps, override switches have been installed on Unit 2 and will be installed on Unit 1.
Safety / relief valve (SRV) functional test procedures have also been revised.
These revised procedures impose new surveillance requirements that call for more frequent SRV exercise including exercise under power conditions.
In addi-tion, SRV tailpipe vacuum breakers were inspected in detail to assure proper operation.
A new vacuum breaker design is currently being studied for probable installation.*
Regarding the' scram discharge volume drain valve failure, NRC had in July 1980, based upon similar failures, requested all operating BWR licensees to propose technical specification surveillance requirements for the existing scram dis-charge volume vent and drain valves.
The surveillance requirements were in-tended to be an interim measure to assure scram discharge volume vent and drain valve operability on a continuing basis during reactor operation.
The NRC determined in December 1980 that long-term hardware improvements in the isola-tion arrangements for the scram discharge volume system would also be required.
A discussed above, the NRC issued a confirmatory order on June 24, 1983 regard-ing the surveillance requirements.
The same order confirmed the licensee's commitment to install permanent scram discharge system modifications (including redundant vent and drain valves) by December 31, 1983.
These modifications were developed by the BWR Owners' Group.
Revised BWR emergency procedure guidelines developed by the BWR Owners Group for this type of event are under final review by the NRC.
The procedure guide-lines are expected to be approved in 1984.
Implementation of the plant specific procedures and training related to the procedures will begin in 1984 and should be completed in 1985.
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- See also AE0D/E322, " Damage to Vacuum Breaker Valves as a Result of Relief Valve Lifting," issued on October 27, 1983.
This is an engineering evaluation performed by the NRC's Office for Analysis and Evaluation of Operational Data, on incidents at Peach Bottom, Browns Ferry, and Hatch.
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1.3 Slow MSIV Closure Times Due to Inad:quate QA on Replacem:nt Parts Between January 1981 and October 1982, Calvert Cliffs Units 1 and 2* experienced a series of main steam isolation valve (MSIV) failures in which the valves failed to meet the closure time specified in the technical specifications.
On January 18, 1981, with Calvert Cliffs Unit 2 in cold shutdown for a scheduled refueling outage, the No. 21 and No. 22 MSIVs failed to close during a routine test in the 3.6 seconds allotted by the technical specifications.
Initially, no specific cause for the failure could be determined.
(Ref. 6.)
On April 4, 1981, during a routine shutdown of Calvert Cliffs Unit 1, an operator noted that the closing time for the No. 12 MSIV was excessive.
At the time of the event, the cause was attributed to contamination of the hydraulic fluid in the valve actuation system causing the system's check valves to stick and delay the transmission of hydraulic pressure to the actuator.
(Ref. 7.)
On September 23, 1981, with Calvert Cliffs Unit 2 in hot shutdown, the No. 22 MSIV exceeded the technical specifications for maximum allowed closure time.
At this time, Combustion Engineering (the nuciear steam system supplier) started an investigation to determine if changes in the upper and lower time limits for MSIV operation were warranted.
(Ref. 8.)
On October 17, 1982, with Calvert Cliffs Unit 2 in cold shutdown, the No. 21 MSIV shut in 12.72 seconds exceeding the 3.6-second allowable closure time.
The cause of the slow closure time could not be immediately determined.
Action was taken to disassemble the actuator and the packing chamber to determine the specific cause.
(Ref. 9.)
On May 19, 1983, the licensee for Calvert Cliffs filed a report pertaining to all of the aforementioned events.
The report indicated the results of the cause of the problems and a plan for corrective action.
It stated that during the most recent refueling outage, the slow closing MSIVs for both Units 1 and 2 were disassembled and overhauled.
During disassembly, heavy stem galling was observed to have extended to the junk ring located inside the packing gland.
Subsequent x-ray spectog aphy indicated that the junk ring was composed of an alloy chemically similar to an AISI grade 4140 chromium molybdenum.
The drawing of the valve calls for an AISI grade 1015-1025 mild carbon steel.
Since the junk ring is the closest stationary part to the valve stem (.005" clearance) upon each stroke of an MSIV, it should be a significantiy softer steel than the stainless steel stem.
If, as found, it is steel similar in l
hardness to the stem, galling may and did occur.
This tended to bind the stem, slowing valve closure.
Before reassembly the licensee made a junk ring of the proper material on site l
and installed it in the valves.
In addition, the purchase specification by which replacement parts are obtained from the manufacturer was changed to re-quire documentation of proper junk ring material composition.
The first junk rings procured since then have been tested by the licensee and determined to
- Calvert Cliffs Units 1 and 2 are 825 MWe (net) PWRs located 40 miles south of Annapolis, Maryland, and are operated by Baltimore Gas and Electric.
10 0
be, in fact, mild steel.
Tha valve overhaul procedure also was changed to make the final bonnat bolt torque pass after backseating the valves.
This results in a better alignment of the bonnet and its enclosed packing chamber parts (including the junk ring) with the valve stems.
(Ref. 10.)
1.4 Inadvertent Reactor Vessel Drainage During Shutdown At Grand Gulf Unit 1* on April 3, 1983, approximately 10,000 gallons of water drained from the reactor vessel to the suppression pool through the residual beat removal (RHR) system.
This drainage was caused by two RHR valves (F004 and F006) being open simultaneously.
At the time of the event, the reactor was at atmospheric pressure with vessel water temperature approximately 100 F (cold shutdown conditions).
Prior to this incident, loop A of the RHR system was lined up for the low pres-sure coolant injection (LPCI) mode and loop B was lined up for the shutdown cool-ing mode.
(Figure 1 shows this lineup of the RHR system.)
In order to change the lineup of lo,p B to LPCI from shutdown cooling, the operator went to close valve F006.
Full closure of the valve would normally result in the red valve position indicating light bulb ~on the control panel being extinguished.
The operator observed the light bulb was not illuminated and assumed that the valve was already full closed.
However, the indicating light bulb had burned out, resulting in a faulty indication of full valve closure since F006 was in fact still partially open.
The operator then opened valve F004 to put loop B in the shutdown cooling mode.
Opening valve F004 resulted in an unintended open flow path from the reactor vessel to the suppression pool, which drained 10,000 gallons of water out of the reactor vessel.
(Water drained out because of the higher reactor vessel elevation. ) Upon receiving the reactor vessel low level alarm, the control room operator attempted to take immedicte action to stop the flow.
The opera-tor attempted to close F004, but the closure was terminated when the electrical breaker to the valve motor operator tripped.
The vessel water level continued to decrease until the low level reactor trip was received, thus automatically closing the shutdown cooling isolation valves, F008 and F009, terminating the event.
Because of the mechanical and physical designs of the reactor vessel and recirculation system, the core could not have uncovered to less than the design one-third level.
A similar incident occurred at LaSalle Unit 1** on September 14, 1983, while the unit was in cold shutdown.
Water drained from the reactor vessel to the suppression pool and the drywell when an operator opened the LPCI B suction valve in accordance with the approved surveillance procedure.
The static head of water in the reactor vessel caused water to drain through the check valve,
- Grand Gulf Unit 1 is a BWR with a design electrical rating of 1250 MWe (net),
and was granted a low power license in June 1982.
It is located 25 miles south of Vicksburg, Mississippi, and is operated by Mississippi Power and Light.
11
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which had failed to stat preptrly.
This caustd the draining of 5,000 to 10,000 gallons of water from the reactor vessel to the suppression pool and the drywell through the containment spray portion of the RHR system in approximately three minutes.
The control room operator noticed indicated reactor vessel water level going down and terminated th'e drainage manually while the automatic system isolated the primary containment.
Inspection of the valve operator for the check valve revealed that the valve had been improperly timed after maintenance earlier in the outa[;e. -Each inter-facing gear between the check valve itself and the air operator has a timing mark used to align the gears for proper reassembly after maintenance.
The timing mark on the spline shaft of the check valve was confused with a score mark on the spline shaft.
This aligned the check valve and the air operator such that the check valve was ~open about 35* and the air operator inhibited movement in the closed direction.
Further inspection of the check valve showed that, in addition, the packing gland was too tight on the check valve shaft and would not permit full closure at low differential temperatures.
The licensee for LaSalle inspected all testable check valves for proper timing, and reviewed their maintenance history for work performed on the packing gland without a subsequent local leak rate test.
Procedures have been changed to require a local leak rate test when maintenance is performed on a packing gland, and closure of the manual injection stop valve on the RHR loop that is being tested..(Refs. 11 and 12.)
- 1. 5 Damage to Reactor Coolant System Components Following completion of hot functional testing at Palo Verde Unit 1* on July 19, 1983, reactor coolant pump (RCP) 1A was disassembled to perform a planned repair.
It was noted that several bolts that hold the diffuser ring and other bolts that hold the internal suction pipe onto the diffuser were missing or loose., Upon disassembly of the 1B RCP, it was noted that the impeller had a portion of one of the vanes missing.
Further investigation revealed damage in the remaining RCPs and the reactor coolant system.
The following damage was identified:
- Three diffuser cap screws were missing, and several others were loose or broken.
Two suction pipe cap screws were broken, and several others were loose.
- All RCP diffuser vanes were damaged.
One 2-in diameter metal plug and 13 compressien washers were found in the j
primary side of the steam generators.
These pieces were identified as parts of a temporary pump vibration measuring assembly.
l Five cold leg resistance temperature detector (RTD) thermowells were broken f
and missing, another was bent, and the remaining six showed signs of wear.
l
- Palo Verde Unit 1, currently under construction, has a design electrical rating of 1270 MWe (net).
It is located 36 miles west of Phoenix, Arizona, and the licensee is Arizona Public Service.
Planned startup is in mid-1984.
13
Three of tha fiva missing RTD thermow311 piects were found in tha reactor vessel lower flow baffle area.
A thermal sleeve from safety injection line 1A was found in the reactor vessel.
- Several control element assembly (CEA) shroud tubes had longitudinal cracks.
- A powdery material was found in the upper guide structure.
The RCPs at Palo Verde are CE-KSB type 101, and are the first application of this design in the United States.
Similar problems with KSB pumps had been identifed at a foreign plant, which led to numerous' design changes. The CE-KSB design at Palo Verde is similar to that final, successful design.
While it is not yet clear whether the RCP failures were the initiating events or whether they were symptomatic of another problem, changes to the CE-KSB pump design remain under review.
The damage that was evidenced downstream of the RCPs (loose thermal' sleeve, CEA shroud cracks) also remains under investigation as-to cause and relation to the RCP failures.
This event emphasizes the high potential for loose parts in the reactor coolant system during startup testing, and the need for an adequate loose parts moni-toring system during; hot functional testing as well as during power operation.
(Ref 13.)
1.6 Reactor Trip Resul. ting'from Seal Injection System Leak On July 16, 1983, with Lacrosse
- operating at 93% power, an operator made a valving error while attempting to change a filter in the forced circulation (recirculation) pump seal injection system. This valving error started the standby seal injection pump and three piston-type accumulators.
This caused a pressure transient which failed a gasket on the seal injection system causing 14,000 gallons of contaminated condensate and primary coolant water to leak into the sub-basement of the containment building.
The recirculation pumps tripped and a power / flow scram occurred..
The reactor was placed in cold shutdown using the shutdown condenser while the leak was being manually isolated.
Several hours later the leak was isolated and the contaminated water was transferred to the retention tank system and subsequently discharged to the Mississippi. River.
Technical specification release limits were not exceeded.
' During this time, water level in the reactor % maintained using the feedwater system initially and later the high pressure core spray system.
The reactor water = level instrumentation compares the water level in the reactor vessel with the water level in the refererce standpipe. The standpipe has electric heaters to duplicate reactor temperature and pressure.
About three hours after the reactor trip, reactor temperature and pressure had decreased to a point where
- Lacrosse is a 48 MWe (net) BWR located 19 miles south of Lacrosse, Wisconsin, and is operated by Dairyland Power.
14
Tr tha electric heaters w:re causing water in the measuremnnt standpipe to flash to steam.
The heaters were not turned off remotely, and the level readings were erratic until the heaters were turned off locally and ultimately cooled down.
The licensee's evaluation showed that the water level reached a minimum of about 23 inches above the core (normal water level is about 33 inches above the core).
1 That level occurred during the latter part of the event when conditions were I
stable and when the narrow range instrumentation was functioning properly.
The NRC staff 4grees with that evaluation.
T.he licensee has agreed to install a remote switch to turn off the narrow range
' instrument heaters without a containment entry.
The licensee has also developed an interim procedure for remotely turning off the heaters.
Operations personnel have been provided additional training on the use of both the narrow range and wide range *;ater level indicators. The licensee will also install remote mea-suring capability for the containment retention tanks as part of the leak detec-tion system for the plant.
Equipment within the containment has been inspected and evaluated to assure it was not affected by the overpressurization of the seal injection system and subsequent leakage of 14,000 gallons of water into containment.
The NRC has issued a confirmatory action letter to the licensee on its commit-ments to evaluate the water level measurement problems _and other items before resumi.ng operation.
Other NRC concerns expressed in the confirmatory action letter are reactor vessel cooldown in excess of the technical specification limit for a 13-minute period; effects of water in the containment sub-basement on plant equipment; the inability to remotely monitor retention tank levels; and effects of the excessive pressure on the seal injection sys' tem.
During and after the event, radiation protection personnel analyzed containment l
building sub-basement and reactor coolant water samples; sampled and isotopi-l cally measured containment building and stack effluent air; took contamination smears of the containment building and the turbine building; measured dose rates in the conttinment building, including under the control rod drives and the sub-basement floor; controlled entry into the containment building; monitored decon-tamination activities; and measured for whole body extremity, and internal expo-Radiation protection activities during and after the incident appeared sures.
to be accomplished satisfactorily from these analyses.
),
l While resuming operation on August 21, 1983, following repair of the seals on l
the 1A forced circulation pump, the licensee observed erratic pressure and tem-l perature indications for the 18 forced circulation pump, indicative of a seal problem on that pump.
(There are two forced circulation pumps in the Lacrosse unit.)
l The reactor was again placed in cold shutdown, and preparations were made to l
inspect and repair the IB forced circulation pump e.ls.
During the previous repairs on the 1A pump, the 18 pump seals had been inspected and found in satis-factory condition.
The cause of the subsequent seal degradation was determined to'be a pump shaft alignment and not the result of this event.
(Ref. 14.)
15 l
- 1. 7 Unexp?cted Loss of Offsitn Powar to Safety-Ralated Buses On August 1, 1983, Monticello* was operating at 100% power and at reduced main generator terminal voltage (20.9 kV vs. nominal of 22.0 kV) due to light grid loads.
The switch / grid voltage was 344 kV vs. nominal of 355 kV.
The No. 16 safety-related 4160 V essential bus (EB) was operating at 3960 V, which is below the minimum expected voltage of 4025 V.
(Ref. 15.)
In preparation for a reactor core isolation cooling surveillance test, one residual heat removal service water (RHR SW) pump and one RHR pump were operat-ing from the bus.
A voltage transient, resulting from the startup of a second RHR SW pump, caused the degraded voltage relays' timing action to actuate.
The bus then transferred to the emergency diesel generators.
Non-essential loads were shed from the No. 16 bus.
The brief interruption of power caused several plant responses that could be expected.
However, during the event several unexpected plant responses also occurred.
The plant continued to operate at 100% power during the voltage transient.
The transfer of the No. 16 bus caused the uninterruptible motor generator set to switch to de drive, and transferred buses Y20 and Y30 to their alternate source.
Thus, during the event, bus Y20 was supplied from normal station auxiliary sources, and buses Y10 and Y30 were supplied from the uninterruptible motor generator set.
As part of the normal load shed from the No. 16 bus, the No. 12 reactor protec-tion system (RPS) motor generator set source breaker tripped.
Loss of the No. 12 RPS motor generator set resulted in a half-scram, startup of the standby gas treatment system, closure of secondary containment isolation dampers, a trip of reactor building ventilation fans, closure of appropriate Group 2** primary containment isolation valves, closure of Group 3*** primary containment isolation valves, and loss of other loads connected to the motor generator set.
These events are normal for a loss of the No. 12 RPS motor generator set.
The following unexpected effects were observed on plant instrument and control systems:
(1) The 100-in range Yarway reactor level indicators failed downscale.
(All other reactor level indicators were functional.)
- Monticello is a 536 MWe (net) BWR located 30 miles northwest of Minneapolis, Minnesota, and is operated by Northern States Power.
- Group 2:
drywell ventilation, purge and sample lines, reactor building ventilation system, transient in-core probe command, shutdown cooling and head spray modes of residual heat removal.
- Group 3:
reactor water cleanup system.
16 w
(2) Tha A main ferdwater control valve closad and locked in position.
(Reactor level was maintained using the 8 main feedwater control valve and the low flow control valve.)
(3) The total feedwater flow indication decreased from 6.8E6 lb/hr to approxi-mately 5.0E6 lb/hr.
(Not real flow change.)
(4) The turbine control valve cam position indication decrease from about 93%
to 80%.
(Not real position change.)
-(5) The standby liquid control tank wide range level indicator and pump dis-charge pressure indicator failed downscale.
(This did not affect opera-bility of the standby liquid control system.)
(6) The reactor water cleanup regenerate heat exchanger inlet pressure indi-cator and dump flow indicator failed downscale.
(7) The reactor building vent wide range noble gas effluent monitors and one of the two off gas stack wide range noble gas effluent monitors exhibited erratic indication.
(One reactor building vent plenum monitor and one off gas stack wide range noble gas monitor were unaffected.)
(8) The. recirculation motc,r generator set scoop tubes locked.
(9) The process computer tripped.
The cause of the event was operation of the No. 16 4160 V EB at a voltage below the reset setpoint of the degraded voltage protection relays.
The degraded grid setpoint is 3885 V with a 10-second time delay, and the 4160 V EB was operating at 3960 V.
The voltage transient which occurred due to the start of the RHR SW pump caused the bus voltage relays to drop below their setpoint and begin the relay timing action.
The bus voltage recovered within the 10 seconds, but was too low to allow the relays to reset.
The bus then transferred to the emergency diesel generator.
Prior to the event, the licensee had submitted analysis to support the adequacy of the design of the station electric distribution system.
In this analysis, the worst-case minimum grid voltages were assumed to be 350.8 kV and 119.7 kV (under. heavy load conditions), and the minimum voltage on safety-related 4160 V EBs was calculated to be 4025 V after all safety-related loads were started and running.
During the light load conditions at the time of the event, the main 4
generator was being operated at a reduced output voltage for grid system voltage j
control.
This resuled in the switchyard being at 344 kV (the voltage level on j
the 115 kV grid ~was 120 kV).
Since the 4160 V EBs were in their normal align-ment of being powered from the unit auxiliary transformer which in turn is powered from the output of the main generator, the reduced generator output i
voltage resulted in the correspondingly lower voltages of 3990 V and 3960 V on EBs 15 and 16, respectively.
It should be nottd that when a degraded voltage at Monticello is sensed on any EB, the EB is transferred directly to the emergency onsite power source, even if a reliable offsite source is available.
This situation is undesirable, since 17
tha cause of tha d: grad d voltagn could be equipm:nt related to only the genar-ator or only one offsite power circuit, and an alternate offsite circuit might be available.
A design that inherently precludes access to alternate sources of offsite power is not consistent with the design objective of providing redundant access circuits for offsite power.
When the uninterruptible motor generator set transferred to the DC power source, it failed to properly maintain regulation of its output frequency.
This re-sulted in a variety of malfunctions of instrumentation and control systems.
Except for the following items, all indications and control functions returned to normal when the motor generator set was returned to ac drive.
(1)
Internal fuses in the 100-in Yarway indicators were found blown.
Upon replacement of the fuses, the indicators operated properly.
(2) The standby liquid control system instrument power supply was found to have a failed transformer.
The power supply was replaced.
(3) The reactor water cleanup instrument power supply was found to have a failed transformer.
The power supply was replaced.
Following review and analysis of the event (Ref. 16), the NRC required the licensee for Monticello to take certain short-and long-term corrective actions, including:
Analysis to determine an appropriate minimum operating limit for the voltage on safety-related 4160 V buses.
Analysis to determine the extent to which the 4025 V minimum level will be maintained on a reliable basis.
Procedures to define actions to be taken in the event that voltage falls below the minimum limit.
Revised analysis of the adequacy of the onsite electrical distribution system, using assumptions that are realistic and reflect plant operating experience.
Reevaluation of the degraded voltage protection system with regard to use of redundant accesses to offsite power.
1.8 Reactor Trip With Indicated Slow Feedwater Flow Reduction Times On August 31, 1983, Calvert Cliffs Unit 1* was manually tripped from full power to avoid an automatic turbine / reactor trip on low condenser vacuum.
The low condenser vacuum was a result of shutting down two of six circulating water pumps because their inlet screens had become clogged with fish (6-to 8-in croaker).
The atmospheric steam dump valves did not operate properly to control primary coolant temperature.
Manual local valve control was achieved 20 minutes
- Calvert Cliffs Units 1 and 2 are 825 MWe (net) PWRs located 40 miles south of Annapolis, Maryland, and arc operated by Baltimore Gas and Electric.
18
sfter the trip by use of a handwh:el/ chain operator at the valves. Action was then taken to place Unit 1 in hot standby.
The licensee's post-trip review of this event determined that the response time for feedwater regulating valve closure assumed in safety analyses, and required by technical specifications, may have been exceeded for flow through one of the two feedwater headers.
The safety analyses assume that feedwater flow is reduced to 5% within 20 seconds or less; the event recorder readout indicated that this did not occur on the affected header until approximately 38 seconds after the trip.
This response time is critical in avoiding potential contain-ment overpressurizatian following a postulated main steam line break.
No such overpressure transient was involved in this case.
The licensee had previously committed to a main feedwater pump trip design change, to be installed by Novem-ber 17, 1983, in response to the NRC's IE Bulletin 80-04 which addressed this problem.
(Ref. 17.)
The licensee subsequently reviewed post-trip data from two previous trips of Unit 1 and three trips of Unit 2.
One out-of-specification response time for feedwater flow reduction was identified.
Based upon this information, the licensee declared an unusual event for Unit 2 at 3:00 p.m. on August 31, and began a shutdown of Unit 2 as required by technical specifications.
Unit 2 subsequently tripped from about 30% power due to a different feedwater flow problem.
Action was taken at this time to place Unit 2 in hot sta.ndby.
The cause of the abnormal influx of fish has been attributed to the inability of the screenwash system to handle an unusually high fish impingement.
Nine 55 gallon drums of fish were removed from the Unit 1 waterboxes.
Efforts are being made on a long-term basis to improve both the screenwash and the opera-tion of the traveling screens.
The problems experienced with the Unit 1 atmospheric dump valves were due to defective diaphragms which have been replaced.
Corresponding Unit 2 diaphragms were verified acceptable prior to Unit 2 restart, and the licensee will modify his preventive maintenance program as necessary to prevent recurrence.
The Unit 2 feedwater pump flow problem during shutdown was attributed to an auxiliary boiler steam control problem which was corrected before startup.
As a result of this event, specific correlations for pertinent parameters to assure a more detailed review of feedwater and other responses were developed, reviewed by the onsite safety review committee, and incorporated in station procedures prior to restart.
Plant restarts began after completion of the upgraded post-trip reviews.
Unit 1 achieved criticality about 10:30 a.m. on September 1, 1983, and Unit 2 achieved criticality by noon the same day.
(Refs. 18 and 19.)
19
1.9. Rafir nces
_(1.1) 1.
Letter from James G. Keppler, Regional Administrator, NRC Region III, to James J. O'Connor, President, Commonwealth Edison Company, trans-mitting a Notice of Violation and Imposition of Civil Penalties, Docket No. 50-254, June 21, 1983.
2.
Letter from B. L. Thomas, Executive Vice President, Commonwealth Edison Company, to James G. Keppler, Regional Administrator NRC Region III, Docket No. 50-254, August 12, 1983.
i 3.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 83-75, " Improper Control Rod Manipulation,"
November 3,1983.
(1.2) 4.
NRC, Office for Analysis and Evaluation of Operational Data, Prelimi-nary Case Stedy, "Edwin I. Hatch Unit No. 2 Plant Systems Interaction Event on August 25, 1982," August 1983.
5.
NRC, IE Information Notice 83-44, " Potential Damage to Redundant Safety Equipment as a Result of Backflow through the Equipment and Floor Drain System," July 1, 1983.
(1.3) 6.
Baltimore Gas and Electric Company, Docket 50-318, Licensee Event Report 81-05, January 29, 1981.
7.
Baltimore Gas and Electric Company, Docket 50-317, Licensee Event Report 81-24, May 1,1981.
8.
Baltimore Gas and Electric Company, Docket 50-318, Licensee Event Report 81-40, October 23, 1981.
9.
Baltimore Gas and Electric Company, Docket 50-318, Licensee Event Report 82-50, November 12, 1982.
10.
Baltimore Gas and Electric Company, Dockets 50-317 and 50-318, updates to Licensee Event Reports listed in Refs. 6 through 9 above, May 19, 1983.
i (1.4) 11.
NRC, AE00 Technical Review Report T-344, " Reactor Vessel Drainage,"
November 15, 1983.
12.
Commonwealth Edison, Docket 50-373, Licensee Event Report 83-105, September. 27, 1983.
(1.5) 13.
NRC, Preliminary Notifications PNO-V-83-29A (July 26, 1983) and PNO-V-83-29B (August 2, 1983).
(1.6) 14.
NRC, Preliminary Notifications PNO-III-83-62 (July 18, 1983),
PN0-III-83-62A (July 20, 1983), PNO-III-83-62B (July 27, 1983),
and PNO-III-83-75A (August 22, 1983).
20
(1.7) 15.
EG&G Idiha, Spuricus Undsrvoltaga Transfer of tha #16 4160 Volt Essential Bus to the Emergency Diesel Generator, Monticello Generating Plant. Unit 1, Docket 50-263, D. A. Weber, August 13, 1983.
16.
NRC memorandum from F. Miraglia, NRR, to G. Lainas, NRR, forwarding a Safety Evaluation Report on Monticello Nuclear Generating Plant j
Unexpected Loss of O'fsite Power to Class IE Buses, August 22, 2983.
(1.8) 17.
NRC, IE Bulletin 80-04, " Analysis of a PWR Main Steam Line Break with Continued Feedwater Addition," February 8,1980.
18.
NRC, Preliminary Notification PNO-I-83-94 (August 31, 1983) and PNO-I-83-94A (September 1, 1983).
19.
Letter from E. Bauereis, Baltimore Gas and Electric, to NRC Region I, September 23, 1983.
These referenced documents are available in the NRC Public Document Room at 1717 H Street, Washington, D.C. for inspection and/or copying for a fee.
l l
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2.0 ABSTRACTS OF OTHER OPERATING EXPERIENCE DOCUMENTS 2.1 Abnorn.a1 Occurrence Reports (NUREG-0090) Issued in July-August 1983 An abnormal occurrence is defined in Section 208 of the Energy Reorganization Act of 1974 as an unscheduled incident or event which the NRC determines is significant from the standpoint of public health or safety.
Under the pro-i visions of Section 208, the Office for Analysis and Evaluation of Operational Data reports abnormal occurrences to the public by publishing notices in the Federal Register, and issues quarterly reports of these occurrences to Congress.in the NUREG-0900 series of documents.
Also included in the quarterly reports are updates of some previously reported abnormal occurrences, and sum-maries of certain events that may be perceived by the public as significant but do not meet the Section 208 abnormal occurrence criteria.
No reports to Congress on abnormal occurrences were published during this report period.
I 1
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2.2 Bulletins and Information Notices Issu:d in July-August 1983 The Office of Inspection and Enforcement periodically issues bulletins and information notices to licensen: and holders of construction permits.
During the period, two bulletins and 15 information notices were issued.
Bulletins are used primarily to communicate with industry on matters of generic importance or serious safety significance; i.e.,
if an event at one reactor raises the possibility of a serious generic problem, an NRC bulletin may be issued requesting licensees to take specific actions, and requiring them to submit a written report describing actions taken and other information NRC should have to assess the need for further actions.
A prompt response by affected licensees is required and failure to respond appropriately may result in an enforcement action, such as an order for suspension or revocation of a license.
When appropriate, prior to issuing a builetin, the NRC may seek comments on the matter from the industry (Atomic Industrial Forum, Institute of Nuclear Power Operations, nuclear steam suppliers, vendors, etc.), a tech-nique which has proven effective in bringing faster and better responses from licensees.
Bulletins generally require one-time action and reporting.
They are not intended as substitutes for revised license conditions or new requirements.
Information Notices are rapid transmittals of information which may not have been completely analyzed by NRC, but which licensees should know.
They require no acknowledgment or response, but recipients are advised to consider the applicability of the information to their facility.
Date Bulletin Issued Subject 83-06 7/22/83 NONCONFORMING MATERIALS SUPPLIED BY TUBE-LINE CORP 0 RATION FACILITIES AT LONG ISLAND CITY, NEW YORK; HOUSTON, TEXAS; AND CAROL STREAH, ILLIN0IS All nuclear power reactor facilities or fuel facilities holding an operating license or con-struction permit were notified about findings from Region IV Vendor Program Branch inspections at the Tube-Line Corporation (T-L) facilities at Long Island City, New York; Houston, Texas; and Carol Stream, Illinois, which indicated potential generic safety implications at plants which either have received pipe fittings and flanges directly from T-L or piping subassemblies and other components that incorporate these T-L materials.
Recipients of this bulletin were asked to review the information for applicability to their facilities and to (1) take appropriate action to confirm the adequacy of affected components for intended service; or (2) submit reports stating that T-L materials received from the referenced manufacturing locations will not be used in safety-related systems at their facilities.
24
Data Bulletin Issued Subject 83-07 7/22/83 APPARENTLY FRAUDULENT PRODUCTS SOLD BY RAY MILLER, INC.
Within eight months of the date of this bulletin all nuclear power facilities and fuel facilities holding an operating license or construction permit were to report in writing on their deter-mination if any apparently fraudulent products l
sold by Ray Miller, Inc. and listed in Attach-ments 1 and 2, or identified by other means, were installed in safety-related systems at their facilities or were still in stock.
The presence of such material was to be evaluated insofar as its safety significance, and disposition was to be determined.
All identified Ray Miller, Inc. material was to be segregated into two groups:
(1) material in the fraudulent data file, and (2) other Ray Miller materials.
Group 1 materials should be discarded or tagged for use only in systems not classified as safety-related or important to safety.
Group 2 materials could be tested to demonstrate 90% con-fidence and then used as desired if found accept-able, or material that passed examination and test of a limited sample could only be used in systems important to safety after NRC's evaluation was complete.
Recipients of this bulletin were urged to be sensitive to the fact that equipment suppliers may be substituting substandard or nonconforming materials when filling orders.
Information Notice 83-44 7/1/83 POTENTIAL DAMAGE TO REDUNDANT SAFETY EQUIPMENT AS A RESULT OF BACKFLOW THROUGH THE EQUIPMENT AND FLOOR DRAIN SYSTEM All nuclear power reactor facilities holding an operating license or construction permit were informed that as a result of backflow through equipment and floor drainage systems, safety-related compartments can be flooded.
Eechtel Corporation notified Baltimore Gas &
Electric Co. (BG&E) that the water-tight integ-rity of the service water pump rooms at both units of its Calvert Cliffs plant could be impaired because check valves had not been 25
Infermation D:ta Notice Issued Subject 83 installed in the floor drain systems which drain (continued) by gravity to the turbine condenser pit in the turbine building.
BG&E has sealed some of the roce drains and modified the remaining drain lines by installing check valves to prevent potential backflow into the safety-related rooms.
Older plants not necessarily designed to the standards of SRP Section 9.33 may be susceptible to the same or equivalent potential problem identified at Calvert Cliffs.
83-45~
7/1/83 ENVIRONMENTAL QUALIFICATION TEST OF GENERAL ELECTRIC COMPANY "CR-2940" POSITION SELECTOR CONTROL SWITCH All holders of a nuclear power reactor operating license or construction permit were notified of a potentially significant problem pertaining to the premature degradation and failure of a Dupont TM "Delrin" switch cam within the GE "CR-2940" four position selector switch.
The specimen tested by the Philadelphia Electric Company failed to function following the radia-tion aging phase, after it was exposed to a radiation doce of 37 megarads.
The cam material (Delrin) had fractured into many small pieces, changing the setting of the contact arrangement of the four-way position switch during the test.
The subject switch had been installed at Peach Bottom to operate safety-related equipment.
The licensee modified wiring to the switches to assure that safety-related equipment at Peach Bottom will function as required and is review-ing long-term actions to provide switches that will meet environmental requirements.
A related matter involved a recent 10 CFR 50.55(e) report to the NRC from the Cleveland Electric Cc. that GE CR-2940 tandem block switch assem-blies contained blocks with loose mounting screws.
83-46 7/11/83 COMMON-MODE VALVE FAILURES DEGRADE SURRY'S RECIRCULATION SPRAY SUBSYSTEM All nuclear power reactor facilities holding an operating license or a construction permit were notified about the apparent common-mode failures 26
Infcrm;ticn Dats Notice Issued Subject 83-46 that affected motor-operated 30-inch butterfly (continued) valves which admit service water to the recircu-lation spray coolers at Surry Power Station Units 1 and 2.
All four of the subject valves failed to open during surveillance tests of the recirculation spray subsystem of Unit 1.
Three of four such valves in Unit 2 failed to open.
These failures jeopardized the plant's ability to mitigate the effects of a LOCA.
Failures have been attributed to several factors, including:
biofouling, corrosion, infrequent testing, low torque switch settings, and margin-ally sized motors and/or improperly geared valve operators.
The licensee has taken corrective actions.
In addition, recipients of this notice were alerted that components using brackish and/or silty service water have experienced (1) plug-ging at several facilities as a result of bio-fouling or silt deposit, and (2) leaking as a result of corrosion or erosion or a combination of these effects.
83-47 7/12/83 FAILURE OF HYDRAULIC SNUBBERS AS A RESULT OF CONTAMINATED HYDRAULIC FLUID All nuclear power reactor facilities holding an operating license or construction permit were notified about recent failure of hydraulic snub-bers at Crystal River Unit 2 to meet their func-tional test requirements because hydraulic fluid was contaminated.
A likely source of contamina-tion was thought at first to be particulate matter left in the fluid reservoirs after fabri-cation.
Other possible sources may be the reservoir vent opening and the new hydraulic fluid (GE type SF9650).
Corrective action includes disassembling, cleaning, reassembling, and filling all the snubbers with new fluid.
In addition, (1) the reservoir manufacturer must flush each reservoir with cleaning solution before shipping, (2) independent preshipment inspections will be performed to verify cleanli-ness before shipping, (3) reservoirs will be flushed with cleaning solution before the snubber is assembled, (4) reservoir vents that are open to the atmosphere have been replaced with fil-tered vents, and (5) new hydraulic fluid is being filtered several times before use.
27 I
Information Data Notice Issued Subject J
83-48 7/14/83 GASEOUS EFFLUENT RELEASES OF RADI0 ACTIVE I0 DINE-125 AND IODINE-131 IN EXCESS OF NUCLEAR REGULATORY j
COMMISSION LIMITS j
Byproduct material users licensed by NRC, includ-ing all medical and academic institutions, radiopharmaceutical suppliers, and industrial research and development facilities were alerted that several users of radioiodine isotopes for pharmaceutical preparation and research do noc have provisions for adequately evaluating amounts of radioiodine gases in effluents released to unrestricted areas.
Licensees were reminded that NRC requires them to conduct surveys upon release of radioactive material to unrestricted areas, to ensure compliance with 10 CFR 20.106.
83-49 7/25/83 SAMPLING AND PREVENTION OF INTRUSION OF ORGANIC CHEMICALS INTO REACTOR COOLANT SYSTEMS All nuclear power reactor facilities holding an operating license or construction permit were reminded that sampling programs can prevent the intrusion of organic contaminants in the reactor water cleanup and storage systems.
Two events were cited which involved the contamination of nuclear plant water systems.
In the first event, 3000 gallons of glycol and water which were spilled at Hatch 1 ran into the floor drains to the radwaste system.
Glycol, being nonionic, is not removed by the radwaste demin-eralizers.
However, the contaminant was detected by a subsequent sample analysis for total organic carbon.
This prevented the transfer of the glycol to the condensate storage tank and then to the reactor coolant system.
The second event occurred at La Salle 1:
Contam-inants (freon and other organic solvents were not detected until they intruded into the reactor t
coolant system where they were broken down by the action of the heat and radiation, causing an observed decrease in pH and an increase in conductivity and chloride concentration.
To l
clean up the contaminants in this event involved the normal water cleanup system as well as draining and vacuum cleaning the condensate storage tank.
The suppression pool was circu-lated and heated to 105 F and the pool spray and an air sparge were run to evaporate the organic material out of the solution.
28
Informaticn Data Notice Issued Subject 83-50' 8/1/83 FAILURES OF CLASS 1E SAFETY-RELATED SWITCHGEAR CIRCUIT BREAKERS TO CLOSE ON DEMAND All nuclear power reactor facilities holding an i
operating license or a construction permit were told that NRC had studied 108 LERs to determine why Class 1E safety-related switchgear circuit breakers failed to close on demand.
It appears that improvements in local surveillance of the circuit breakers, maintenance procedures, and training of operations personnel could improve the functional performance of these circuit breakers to close on demand.
83-51 8/1/83 DIESEL GENERATOR EVENTS All nuclear power facilities holding an operating license or a construction permit were told that NRC has recently identified more than 100 LERs pertaining to diesel generator problems.
Most of these appear to be material, equipment, or component failures, and although no single common trend can be identified, it appears that many of these events coula have been eliminated or prevented by implementation of a con,cien-tious maintenance and inspection program as well as by monitoring equipment through a plant's trend program.
A list of several representative events and corrective actions taken was attached to this information notice.
83-52 8/9/83 RADI0 ACTIVE WASTE GAS SYSTEM EVENTS All nuclear power reactor facilities holding an operating license or construction permit were alerted to two recent events involving radio-l active waste gas systems at a BWR and a PWR:
(1) On May 9, 1983 abnormally low readings (for j
existing reactor power level) were noted on both main condenser steam jet air ejector (SJAE) offgas radiation monitors at Brunswick Unit 2, a BWR.
Manual root isolation valves (2-06-V35 and l-V36) were found to be shut, and when they were opened, all control-room SJAE-related indications, including radiation level and hi-lo flow annunci-ator, returned to normal levels / conditions.
A subsequent licensee investigation revealed that the valves had been shut off on April 10.
On April 26 the unit was shut down and the low flow condition on the SJAE was noted and ticketed, l
29 l.
Infcrmation Ditt Notice Issued Subject-83-52 but the ticket was cancelled rince (in a shutdown (continued) condition) no flow is normal.
From May 8 to May 9, Brunswick Unit 2 operated for a 25-hour period without the automatic isolation function capability on the condenser offgas system.
Three different operations shifts failed to identify and act on the abnormally low SJAE radiation monitor readings, although other indications were avail-able to let the staff know there was a problem.
The licensee initiated corrective actions to pre-vent recurrence.
(2) On February 27, 1983, during normal power operation of Turkey Point Unit 3 (a PWR), approximately 18 curies of gas were in-advertently released to the environment from waste gas decay tank (WGDT) No. 2.
The low pressure reading (10 psig) prompted a review of associated process radiation monitoring equipment printouts which confirmed that a radioactive release had occurred during the WGDT pressure decay period.
The licensee determined that the 4638B waste gas safety (relief) valve had apparently not seated properly, and the hand controller for the RCV-014 valve was slightly off zero, leaving the valve slightly open.
83-53 8/11/83 PRIMARY CONTAINMENT ISOLATION VALVE DISCREPANCIES All boiling water reactors holding an operating license or construction permit were advised that it may be prudent to compare their listed tech-nical specifications (TS) isolation signals against the actual logic.
A discrepancy between the isolation signals listed in TS and the actual logic may be widespread.
The resident inspector at Browns Ferry reported a discrepancy in isolation signals between TS sec-tion 3.7, the FSAR, and the actual logic after he noted on January 3, 1983 that the isolation valves in the reactor water sample line were listed as Group I* isolation valves and these valves receive a close signal from all the Group I initiating signals.
The FSAR also stated that all Group I initiating signals will shut these sample valves.
These findings appeared to contlict with the actual logic and an examination of the electrical diagrams inoicated that the sample valves rnly close from two of the five Group I isolation signals.
- Group I:
main steam isolation valves, steam line drains, and reactor water sample lines.
30
Infcrmaticn Data Notict Issusd Subject 83-53 During the summer of 1982 the TS surveillance (continued) requirements were reviewed at Brunswick Station.
The listed group 1 isolation valves were com-pared with the valves that actually isolate from i
each group 1 isolation signal.
The reactor sample valves were listed as isolating on all Group 1 isolation signals when they actually close on only two signals.
83-54 8/11/83 COMMON MODE FAILURE OF MAIN STEAM ISOLATION NONRETURN CHECK VALVES All nuclear power reactor facilities holding an operating license or construction permit were notified about the June 8, 1983 failure of all four main steam isolation nonreturn check valves at the Trojan Nuclear Plant.
The valves appar-
'v stuck open because of increased friction overtightening the packing gland to pre-L venc from leaking past the packing and valve The increased friction was enough to prevent i.he valve from closing under no flow conditions.
The packing was tightened following the last refueling outage and subsequent startup in July 1982.
The valves had previously been repacked in the spring of 1981.
The 2 year interval between repacking seems to be too long as the packing removed from the valves was dried and brittle.
This condition contributed to the frictional forces that prevented the valves from closing.
Because the main steam isolation check valves had been inadvertently omitted from the inservice testing program, they were not routinely tested for operation.
Portland General Electric Company is planning corrective action before reaching full power following the 1983 refueling.
83-55 8/22/83 MISAPTLICATION OF VALVES BY THROTTLING BEYONC DESIGN RANGE All nuclear power facilities holding an operating license or a construction permit were' alerted to potentially generic problems regarding the throttling of high pressure injection (HPI) valves in PWRs and low pressure coolant injec-tion (LPCI) valves in BWRs outside the design limits of those valves.
31
Information Date.
Notice Issued Subject 83-55 The HPI valves at Crystal River Unit 3 (CR-3)
(continued) manufactured by the Walworth Company are not designed for throttling and such activity could damage the valve, imposing a significant safety hazard.
Some Combustion Engineering plants do throttle and could be susceptible to the same problems encountered at CR-3, a Babcock & Wilcox plant. Westinghouse plants do not throttle the safety injection valves but rather vary the flow with the safety injection pumps.
It is possible that PWR plants constructed before the requirement for throttling were included in the emergency operating procedure guidelines for small-break LOCAs contain valves not specifically designed for these purposes.
Similar problems have been reported in BWR plants Following the February 18, 1983 discovery at Susquehanna that a severely vibrating LPCI valve in the B loops of the RHR system had lost its packing and its valve position indicator, and had broken welds on the adjacent saddle-type pipe hanger, it was concluded that the shutdown cooling flow rates were outside the optimum throttling range of the LPCI throttle valve, causing severe valve vibration.
As a result of the February 18th problem, the skirt nut finally worked itself free from the valve disc on June 9, 1983, allowing the disc to separate from the stem, block the keep fill system flow, and render the B loop of the LPCI inoperable.
Similar problems had occurred in 1975 during startup and the early operational phase at Browns Ferry 1.
The Walworth Company advised TVA that the disc characteristics were improper for the throttling that was necessary for con-trolling the cooldown rate.
83-56 8/26/83 OPERABILITY OF REQUIRED AUXILIARY EQUIPMENT All nuclear power facilities holding an operating license or a' construction permit were reminded of the need to identify equipment whose operabil-ity is required to support the operation of safety-related systems.
Such required auxiliary equipment must be maintained operable to the same extent as the equipment it supports.
32
Information Data N;tica Issued Subject 83-57 8/31/83 POTENTIAL MISASSEMBLY PROBLEM WITH AUTOMATIC SWITCH COMPANY (ASCO) SOLEN 0ID VALVE MODEL NP. 8316 1
All nuclear power reactor facilities holding an operating license or construction permit were advised of an error in a 1978 version of the manufacturer's installation instruction bulletin for ASCO three-way solenoid-operated pilot valves, type NP-8316 in 3/8-inch and 1/2-inch NPT sizes.
Franklin Research Center noticed that the origi-nal ASCO Installation and Maintenance Instruction (Form V-5967) for Bulletin NP-8316 valves pic-tured the pressure and exhaust diaphragm assem-blies backwards.
The 1981 revision, Form V-5967R1, shows the correct orientation.
It is possible that between 1978 and 1981 some maintenance crews installed the diaphragms backwards.
ASCO assured the NRC that valves installed in this manner will still operate, but would leak.
83-58 8/30/83 TRANSAMERICA DELAVAL DIESEL GENERATOR CRANKSHAFT FAILURE All nuclear power facilities holding an operating license or a construction permit were informed about a recent event at the Shoreham Nuclear Station in which emergency diesel generator No. 102 (manufactured by Transamerica Delaval) failed during post-modification full-load test-ing when its crankshaft assembly fractured at the crankpin and crankarm (web) on the generator side of the Cylinder No. 7 crank.
The licensee examined the crankshafts of the two other diesel generator units at Shoreham and found cracks on some cranks and crankwebs.
In addition, a connecting rod-to-crankpin bearing failure occurred.
The manufacturer identified 16 sites to which it supplied its diesel generators.
At this time it is not clear to what extent other diesel generators manufactured by Transamerica Delaval are vulnerable to the same or similar failures.
33
2.3 Enginnring Evaluations cnd Casa Studi::s Issurd in July - August 19838 The Office for Analysis and Evaluation of Operational Data (AE0D) has as a primary responsibility the task of reviewing the operational experience reported by NRC nuclear power licensees.
As part of fulfilling this task, it selects events of apparent interest to safety for further review as either an engineering evaluation or a case study.
An engineering evaluation is usually an immediate, general consideration to assess whether or not a more detailed, protracted case study is needed.
The results are generally short reports, and the effort involved usually is a few staffweeks of investigative time.
Case studies are in-depth investigations of apparently significant events or situations.
They involve several staffmonths of engineering effort, and result in a formal report identifying the specific safety problems (actual or potential) illustrated by the event and recommending actions to improve safety and prevent recurrence of the event.
Before issuance, this report is sent for peer review and comment to at least the applicable utility and appropriate NRC offices.
These AE00 reports are made available for information purposes and do not impose any requirements on licensees.
The findings and recommendations contained in these reports are provided in support of other ongoing NRC activities concerning the operational event (s) discussed, and do not represent the position or requirements of the respon-sible NRC program office.
Engineering Date Evaluation Issued Subject E315 7/8/83 MISUSE OF VALVE RESULTING IN VIBRATION AND DAMAGE TO THE VALVE ASSEMBLY AND PIPE SUPPORTS Two events at Susquehanna Unit 1, described in LERs83-034 and 83-056, involved operation of the residual heat removal (RHR) system in the shutdown cooling mode.
Such intermittent opera-tion has the potential for cumulative damage to valve assemblies.
Valve misuse with throttling outside the optimum range resulted in excessive vibration and damage to the low pressure coolant injection (LPCI) throttle valve assembly and the system piping supports.
Current procedures rely on administra-tive controls to prevent such misuse.
The February 18, 1983 event (LER 83-034) involved severe vibration of the LPCI system injection valve F0 178.
Inspection revealed that the valve
- No case studies were issued during July - August 1983.
34
Engin n ring Date Evaluation Issued Subject E315 had lost it3 packing, the position indicator had (continued) vibrated off, the adjacent saddle-type pipe hanger had two broken welds, and weld cracks were observed on another pipe hanger. All damaged components were repaired.
In addition, two snubbers attached to the saddle-type pipe hanger were replaced, although no damage was evident.
(A later investi-gation revealed that the valve disc had separated from its stem; weld tabs which hold the disc nut locked had cracked and permitted the nut to back off.) The B loop was declared inoperable and the A loop was placed in service.
Although several pipe hanger welds in the A loop had cracks, operability was not affected.
The vibration was apparently caused by operation of the RHR shutdown cooling loop with flow rates outside the optimum throttling range of valve F0178 (valve misuse);
system operation was procedurally allowed by a temporary change notice which was implemented to provide a finer control of reactor coolant temper-ature.
The operating procedure was revised to impose operating restrictions that will prevent a recurrence of this event.
Another event at Susquehanna Unit 1 occurred on April 17, 1983 (LER 83-056) and involved the same system and components as the event reported in LER 83-034.
Severe damage to the LPCI system injection valve was directly related to RHR system flow limita-tions that result from a cc,../sination of system design, configuration, flow control system, and a low level of decay heat.
Further, intermittent operation of the RHR system in the shutdown cooling mode has the potential for cumulative damage and may be related to the valve operator motor burnout.
It would be appropriate to review RHR system operation for compatibility with valve assembly design and qualification requirements.
E316 7/8/83 FR0 ZEN ICE CONDENSER INTERMEDIATE DECK D0 ORS Two of the three plants currently equipped with ice condenser containments reported 26 events between July 1979 and March 1983 in which inter-mediate deck doors of ice condenser containments 35
Enginnring D:ta Evaluation Issuid Subject E316 froze shut.
Most of the time one or two doors (continued) froze shut; on three occasions at D.C. Cook 1, six, eight, and 21 doors froze shut.
D.C. Cook 1 reported 11 events of frozen doors; Sequoyah 1, nine events; Sequoyan 2, four events; and D.C.
Cook 2, two events. McGuire 1 and 2 reported no events in which the intermediate doors froze shut.
Most of the problems occurred while the plants were new, and have decreased as operating experience was gained.
Since recent failures have consisted of isolated cases of one or two doors freezing shut, the ability of the ice condenser to perform its safety function has not been jeopardized.
E317 8/1/83 LOSS OF HIGH PRESSURE INJECTION SYSTEM Despite the design requirement of GDC 35 that
" suitable redundancy in components and features, and suitable interconnections, leak detection, isolation, and containment capability shall be provided to assure that the system safety func-tion can be accomplished assuming a single failure," a dozen events were reported in operat-ing Westinghouse plants which made the high pressure injection (HPI) system inoperable.
Four of the events identified had common mode failures that were representative of systems interaction.
The charging pumps which are used in HPI mode for some plants are part of the ECCS but are not physically separated since a common suction header and a common discharge line exist between the two trains of the ECCS.
Therefore all pumps are susceptible to a common mode failure such as loss of suction because of (1) gas ingression, or (2) emptying the volume control tank, or (3) inadequate procedures.
The Standard Review Plan can be revised so that future plants will have two separate flow paths isolated from each other per GDC 35.
That is, the suction and discharge of each safety grade centrifugal charging pump should be isolated from the other safety grade centrifugal charging pump in order to avoid the complete loss of the HPI system due to a common mode failure.
It is l
suggested that operating experience dealing with the failure of the HPI system due to system interaction should be integrated into the ongoing generic activity A-17, " Systems Interaction in Nuclear Power Plants" of NUREG-0371.
Particular 36
Engin2: ring D:ts Evalurtien Issu:d Subbet E317 attention should be focused on the need to fix (continued) the volume control tank instrumentation problem to eliminate this system interaction.
E318 8/15/83 ENGINEERING EVALUATION REPORT "BIOFOULING AT SALEM UNITS 1 AND 2" Salem Unit 2 has reported thirteen flow blockages to containment for cooling units since May 1982.
These blockages have been attributed to an accu-mulation of oyster shells (biofouling) and to an accumulation of silt.
Only by taking the valve apart can the cause (shells or silt) be specified.
On April 28, 1983 the first incident of biofoul-ing was recognized at Salem Unit 1 when the 1C diesel generator tripped off the bus during a one-hour surveillance test as a result of high temperature in the diesel generator's jacket water cooler.
It is believe that the salinity increase in the Delaware River from the 1981 drought made it possible for oyster spat to migrate up the river and enter Unit 1.
It is believed that debris generated during the exten-sive cleaning of Unit 2's service water system during the last refueling outage may be respon--
sible for recent flow blockages there.
The licensee is implementing continuous (ratNr than less effective intermittent) chlorination and an inservice monitoring program to control the magnitude and effects of the biofouling.
Divers have also been used to mechanically remove the attached bivalves from service water yard piping.
System components will be disas-sembled and inspected as necessary.
37
l 2.4 Centric Lotters Issutd in July - August 1983 Generic letters are issued by the Office of Nuclear Reactor Regulation, Division of Licensing.
They are similar to IE Bulletins (see Section 2.2) in that they transmit information to, and obtain information from, reactor licensees, applicants, and/or equipment suppliers regarding matters of safety, safeguards, or environmental significance.
During July and August 1983, six letters were issued.
Generic letters usually either (1) provide information thought to be important in assuring continued safe operation of facilities, or (2) request information on a specific schedule that would enable regulatory decisions to be made regarding the continued safe opeation of facilities.
They have been a signifi-cant means of communicating with licensees on a number of important issues, the resolutions of which have contributed to improved quality of design and operation.
Generic Date Letter Issued Subject 83-12A*
7/11/83 ISSUANCE OF NRC FORM 398 - PERSONAL QUALIFICATIONS STATEMENT - LICENSEES All non power-reactor licensees were advised to begin using NRC Form 398 (1-83) by August 11, 1983.
Non power-reactor licensees should com-plete only those questions that are clearly applicable to their facilities and should indi-cate "N/A" (not applicable) for the other ques-tions.
For Item No. 12, licensees should follow the guidance provided in ANSI /ANS-15.4 (1977) until the instructions on Form 398 for this item have been revised.
83-23 7/29/83 SAFETY EVALUATION OF " EMERGENCY PROCEDURE GUIDELINES" All Combustion Engineering (CE) licensees and applicants were notified that NRC suggests the implementation of the proposed CE Owners' Group (CE0G) Emergency Procedure Guidelines (EPGs).
The NRC staff finds that the EPGs represent a significant improvement over the guidance pro-vided in current emergency operating procedures.
The staff's SER, enclosed in this generic letter, identifies a number of items that need more work; notably the EPGs do not incorporate reacter vessel level instrumentation in general, nor the CE heated junction thermocouple, in particular.
- Replaces 83-25 38
G2n:ric Date Letter Issued Subject 83-23 The NRC requires CE to provide a revision to the (continued)
EPGs to address the vessel level instrumentation.
In addition CE is required to address the long-term items identified in the SER.
The staff finds that the CEGG Guidelines (CEN-152) provide sufficient guidance so that they can be translated into acceptable emergency operating procedures using the process identified in NUREG-0899, " Guidelines for the Preparation of Emergency Operating Procedures."
83-26 7/5/83 CLARIFICATION OF SURVEILLANCE REQUIREMENTS FOR DIESEL FUEL IMPURITY LEVEL TESTS All applicants for operating licenses and holders of construction permits for power reactors were offered clarification for subject requirements as stated in the Standard Technical Specifications (STS) in use by applicants for operating licenses.
The revisions to STS requirements for diesel fuel impurity level tests in Specification 4.8.1.1.2 are to be used in submittals of proposed Technical Specifications (TS), or, if proposed TS have already been submitted the staff will make the necessary revisions.
83-27 7/6/83 SURVEILLANCE INTERVALS IN STANDARD TECHNICAL SPECIFICATIONS All licensees and applicants for operating power reactors and holders of construction permits for power reactors were advised that NRC intends to retain the 18-month and 12-month surveillance intervals given in the Standard Technical Specifications (STS) except that infrequent one-time-only changes may be granted for plant-specific conditions where adequate justification is given.
The STS and most custom technical specifications include a provision which permits any surveil-lance interval to be extended by 25% of the nomi-nal interval, provided that the total time inter-val does not exceed 3.25 times the specified surveillance interval over any three consecutive surveillance intervals.
39
G;nsric Data Lettsr Issutd Subject 83-28 7/8/83 REQUIRED ACTIONS BASED ON GENERIC IMPLICATIONS OF SALEM ATWS EVENTS All licensees of operating reactors, applicants for operating license, and holders of construc-tion permits were told what intermediate-term actions they were to perform as a result of the anticipated transient without scram (ATWS) events at Salem Unit 1 on February 22 and 25, 1983, as reported in NUREG-1000. Actions will address issues related to reactor trip system reliability and general management capability in four areas:
post-trip review, equipment classi-fication and vendor interface, post-maintenance testing, and reactor trip system reliability improvements.
83-30 7/21/83 DELETION OF STANDARD TECHNICAL SPECIFICATION SURVEILLANCE REQUIREMENT 4.8.1.1.2.d.6 FOR DIESEL GENERATOR TESTING All holders of operating licenses, applicants for operating licenses, and holders of construc-tion permits for power reactors were told that diesel generator Surveillance Requirement 4.8.1.1.2.d.6 in the Standard Te'chnical Speci-fications (STS) should be deleted because the current revision of the STS for all power reac-tors is not consister.t with the provisions of GDC-17, Regulatory Guide 1.108, and the NRC Standard Review Plan (SRP 8.2 and 8.3.1).
To rectify this inconsistency the revised Surveil-lance Requirements for diesel generator testing were enclosed.
40
2.5 Operating Reactor Event Memorande Issund in July - August 1983 use Director, Division of Licensing, Office of Nuclear Reactor Regulation (NRR), disseminates information to the directors of the other divisions and program offices within NRR via the operating reactor event memorandum (OREM) system. The OREM documents a statement of the problem, background information, the safety significance, and short and long term actions (taken and planned).
Copies of OREMs are also sent to the Offices for Analysis and Evaluation of Operational Data, and of Inspection and Enforcement for their information.
No OREMs were issued during July - August 1983.
l 41
7 a 2.6 Regulatcry and Technical Reports Issu!d in July - August 1983 The abstracts listed below have been selected from the Office of Administration's quarterly publication, Regulatory and Technical Reports (NUREG-0304), This document compiles' abstracts of-the formal regulatory and technical reports issued by the NRC staff and its contractors.
Bibliographic data for the reports are also included.
Copies and subscriptions of NUREG-0304 are avail-able from the NRC/GP0 Sales Program, PHIL-016, Washington, DC 20555 or on (301) 492-9530.
Report Title NUREG-0020 LICENSED OPERATING REACTORS ' STATUS
SUMMARY
REPORT (VOL. 7, Vol. 7, No. 3 N0. 3 - Data as of 2/28/83; Vol. 7, No. 4 - data as cf July 1983; 3/31/83; Vol. 7, No. 5 - data as of 4/30/83)
Vol. 7, No. 4 August 1983; This report provides data c.; the operation of nuclear units Vol. 7, No. 5 as timely and accurately as passible.
This information is August 1983 collected by'the Office of Resource Management from the staff of NRC's Office of Inspection and Enforcement, from NRC's Regional Offices, and from utilities.
The three sec-tions of the report are:
monthly highlights and statistics for commercial operating units, and errata from previously reported data; a compilation of detailed information on each unit, provided by llRC's Regional Offices, IE, and the utilities; and an appendix for miscellaneous information such as spent fuel storage capability, reactor years of experience and non power reactors in the U.S.
It is hoped the report is helpful to all agencies and individuals interested in maintaining an awareness of the U.S. energy situation as a whole.
NUREG-0304 REGULATORY AND TECHNICAL REPORTS Vol. 8, No. 2 August 1983 This compilation lists all NRC regulatory and technical reports published under the NUREG series during the second quarter of 1983.
NUREG-0540 TITLE LIST OF DOCUMENTS MADE PUBLICLY AVAILABLE (Vol. 5, Vol. 5, No. 4 No. 4 - Data for 4/83; Vol. 5, No. 5 - data for 5/83; July 1983; Vol. 5, No. 6 - data for 6/83)
Vol. 5, No. 5 l
August 1983; This document is a mnthly publication ccntaining Vol. 5, No. 6 descriptions of information received and generated by the August 1983 NRC.
This information includes (1) docketed material associated with civilian r" clear power plants and other uses of radioactive materials, and (2) nondocketed material received and generated by NRC pertinent to its role as a regulatory agency.
The following indexes are included:
Personal Author Index, Corporate Source Index, Report Number Index, and Cross Reference to Principal Documents Index.
l 42
.A_.
4
-i.-
-em Rrport Title NUREG-0871 SUtWARY INFORMATION' REPORT (Data as of 6/30/83)
Vol.'2, No. 3 August 1983 Provides summary data concerning NRC and its licensees for general use by the Chairman, other Commissioners and i
Commission staff offices, the Executive Director for Operations, and the Office Directors.
NUREG-0936 NRC REGULATORY AGENDA (Data for March - May 1983)
Vol. 2, No. 2 July 1983.
The NRC Regulatory Agenda is a compilation of all rules on which the NRC has proposed or is considering action and all petitions for rulemaking which have been received by the Commission and are pending disposition by the Commission.
The Regulatory Agenda is updated and issued each quarter.
The Agendas for April and October are published in their entirety in the Federal Register while a notice of avail-
~ ability is published in the Federal Register for the January and July Agendas.
NUREG-0939 ENFORCEMENT ACTIONS:
SIGNIFICANT ACTIONS RESOLVED Vol. 2, No. 2 July 1983 This compilation summarizes significant enforcement actions that have been resolved during one quarterly period (April - June 1983) and includes copies of letters, notices, and orders sent by the NRC to the licensee with respect to
'the enforcement action and the licensee's response.
It is
' anticipated that the information in this publication will ce widely disseminated to managers and employees engaged in activities licensed by the NRC, in the interest of
~
promoting public health and safety as well as common tufense and security.
r i
NUREG-0985 U.S. NUCLEAR REGULATORY COMMISSION HUMAN FACTORS PROGRAM s
Vol. 1 PLAN August 1983 J j
c The Human Factors-Program Plan has been developed to u
i ensure consideration of human factors in the design, operation and maintenance of nuclear facilities.
This s
initial plan addresses nuclear power plants and describes staff development activities planned to (1) provide tech-l -
~
nical bases for resolution of the remaining human factors
,y Lrelated tasks described in NUREG-0660 and NUREG-0737, and (2) investigate and resolve additional human factors problems,that have been identified since publication of NUREG 0660 and NUREG-0737.
The Plan has seven major 7
program elements:
(1) Staffing and Qualifications, (2) Training, (3) Licensing Examinations, (4) Procedures, L
(5) Man-Machine Interface, (6) Management'and Organization, s.
04 and (7) Human Reliability.
Activities within these program elements are directed to providing technical bases for developing guidance to the nuclear industry, improving i
.A L
\\i 1
i 43 i
' ~,
Lfi 3;
y
+
L'
f Report Title NUREG-0985-staff capabilities to perform licensing activities, and (continued) supporting staff recommendations regarding the degree of regulation required to resolve technical issues.
Appendixes to the Plan dcscribe the status of TMI Action Plan human factors issues, staff responses to recommendations pravided by the Human Factors Society, and schedules for the seven program elements.
This edition (Vol. 1) of the Plan describes activities in progress and planned for Fiscal Years 1983 - 1985.
NUREG-1000 GENERIC IMPLICATIONS OF ATWS EVENTS AT THE SALEM NUCLEAR Vol. 2 POWER PLANT (Licensee and Staff Actions)
This report, Vol. 2 of two volumes of NUREG-1000, describes the intermediate term actions to be taken by licensees and applicants of the NRC, on the one hand, and by NRC staff, on the other, to address the generic issues raised by two anticipated transients without scram (ATWS) at the Salem Nuclear Generating Station, Unit 1, on February 22 and 25, 1983.
These actions came about as a result of the findings of NUREG-1000, Vol.1, and of reviews by the NRC Committee I
to Review Generic Requirements, the NRC Program Offices, and the Commission.
The actions to be taken by licensees and applicants have been detailed in a letter pursuant to 10 CFR 50.54(f).
NUREG/BR-0051 POWER REACTOR EVENTS (Events from 1/83 - 2/83)
Vol. 5, No. 1 August 1983 This is a bi-monthly newsletter that compiles operating experience information about commercial nuclear power plants.
It includes summaries of noteworthy events and listings and/or abstracts of NRC and other documents that discuss safety-related or possible generic issues.
It is intended to feed back some of the lessons learned from operational experience to the various plant personrel, i.e., managers, licensed reactor operators, training coordinators, and support personnel.
NUREG/CR-2000 LICENSEE EVENT REPORT (LER) COMPILATION (Vol. 2, No. 6 -
Vol. 2, No. 6 data for 6/83; Vol. 2, No. 7 - data for 7/83)
July 1983; Vol. 2, No. 7 This monthly report contains Licensee Event Report (LER)
August 1983 operational i:. formation that was processed into the LER data file of the Nuclear Operations Analysis Center-(NOAC) during the one month period identified on the cover of the document.
The LERs, from which this information is derived, are submitted to the NRC by nuclear power plant licensees in accordance with federal regulations.
Procedures for LER reporting are described in detail in NRC Regulatory Guide 1.16 and NUREG-0261, Instructions for Preparation of Data Entry Sheets for Licensee Event Reports.
The LER 44 C
Report Title NUREG/CR-2000 summaries in this report are arranged alphabetically by (continued) facility name and then chronologically by event date for each facility.
Component, system, keywords, and component vendor indexes follow the summaries.
The components, systems and vendors are those identified by the utility when the LER form is initiated; the keywords are assigned by the computer using correlation tables from the Sequence Coding and Search System.
NUREG/CR-2254 A PROCEDURE FOR CONDUCTING A HUMAN RELIABILITY ANALYSIS FOR July 1983 NUCLEAR POWER PLANTS This document describes in detail a procedure to be followed in conducting a human reliability analysis as part of a probabilistic risk assessment when such an analysis is performed according to the methods described in NUREG/CR-127,
" Handbook for Human Reliability Analysis with Emphasis on Nuclear Power Plant Applications." An oterview of the procedure describing the major elements of a human reliabil-ity analysis is presented along with a detailed description of each element and an example of an actual analysis.
An appendix consists of some sample human reliability analysis problems for further study.
NUREG/CR-2331 SAFETY RESEARCH PROGRAMS SPONSORED BY OFFICE OF NUCLEAR Vol. 2, No. 4 REGULATORY RESEARCH (Progress report for Fourth Quarter, July 1983 1982)
The Advanced and Water Reactor Safety Research Programs Quarterly Progress Reports have been combined and are included in this report entitled, " Safety Research Programs Sponsored by Office of Nuclear Regulatory Research Quarterly Progress Report." This progress report will describe current activities and technical progress in the following projects:
HTGR Safety Evaluation, SSC Development, Validation and Application, CRBR Balance of Plant Modeling, Thermal-Hydraulic Reactor Safety Experiments, LWR Plant Analyzer Development LWR Code Assessment and Application; Stress Corrosion Cracking of PWR Steam Generator Tubing, Bolting Failure Analysis, Probability Based Load Combinations for Design of Category I Structures, Mechanical Piping Benchmark Problems, Soil Structure Interaction; Human Error Data for Nuclear Power Plant Safety Related Events; Criteria for Human Engineering Regulatory Guides and Human Factors in Nuclear Power Plant Safeguards.
The previous reports have covered the period October 1, 1976 through September 30, 1982.
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Report Title NUREG/CR-2989 RELIABILITY OF EMERGENCY AC POWER SYSTEM AT NUCLEAR POWER July 1983 PLANTS Reliability of emergency onsite ac power systems at nuclear power plants has been questioned within the NRC because of the number of diesel generator failures reported by nuclear plant licensees and the reactor core damage that could result from diesel failure during an emergency.
This report contains the results of a reliability analysis of the onsite ac power systems.
Included is a design and operating experience review.
Eighteen plants representative of typical onsite ac power systems and ten generic designs were selected to be modeled by fault trees.
Operating experience data were collected from the NRC files and from nuclear plant licensee responses to a quettionnaire sent out for this project.
t Important centributors to onsite power system reliability were identified, and the costs and improvement in reliability for modifications were estimated.
Sensitivity of the onsite system unreliability to independent diesel generator failure, common-cause failure, and scheduled maintenance unavailability were analyzed, and costs of decreasing the probabilities of failure for these contributors were estimated.
The important factors affecting onsite ac power reliability were found to be dependent upon plant-specific features.
NUREG/CR-3289 COMMON CAUSE FAULT RATES FOR INSTRUMENTATION AND CONTROL July 1983 ASSEMBLIES This report presents estimates of common cause fault rates and related quantities, based on License Event Reports of instrumentation and control assemblies in nuclear reactors.
The License Event Report data base is briefly described, and imperfections in the data are discussed.
Th components are grouped into assemblies, for which rates are estimated.
For estimating rates, the binomial failure rate model is used, extended to allow for the substantial observed plant-to plant variability, and for shocks that by their nature cause all the assemblies in a system to fail.
Every quantity is estimated by both a point estimate and a 90% interval.
All rates are expressed per calender hour.
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