ML20211A063
| ML20211A063 | |
| Person / Time | |
|---|---|
| Issue date: | 05/31/1986 |
| From: | Massaro S NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| References | |
| NUREG-BR-0051, NUREG-BR-0051-V07-N5, NUREG-BR-51, NUREG-BR-51-V7-N5, NUDOCS 8606110041 | |
| Download: ML20211A063 (38) | |
Text
NUREC/BR-0051 Vol. 7, No. 5 it.....,X POWER REACTC'R EVE NTS k'
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United States Nuclear Regulatory Commission Date Published: MAY 1986 Power Reactor Events is a bi-monthly newsletter that compiles operating experience information about commercial nuclear power plants. This includes summanes 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 Street, Washington, D C. 20555 for a copymg fee. Subscriptions of Power Reactor Events may be requested from the Superintendent of Documents. U S. Government Printing Office, Washmgton, D C. 20402, or on (202) 783-3238.
Table of Contents Page 1.0 SUMMARIES OF EVENTS 1
1.1 Rextor Trip, Possibly Due to Shorted Photohelic Cellin Output Power Supply at Cook _.
I 1.2 Reactor Trip with Subsequent Safety injection During Load Rejection Test at Palo Verde...
3 1.3 Rextor Trip Results from Erroneous Control Board information Due to inverter Failure at Crystal River 6
1.4 Blockage of Saltwater Flow to Service Water Heat Exchanger While Redundant Service Water System inoperable Due to Maintenance at Calvert Cliffs...
8 1.S Broken Pipe Restraint Reveals Error in Piping Analysis at Crystal River.
10 1.6 Valve Failure to Open When Operated from the Control Room Due to incorrect Torque Switch Setting at Oconee.:
13 1.7 Both Trains of Contool Room Ventilation inoperable Due to PersonnelMisreading Ductwork Drawingsat Byron....
14 1.8 References..-
16 2.0 EXCERPTS OF SELECTED LICENSEE EVENT REPOR TS..
17 3.0 ABSTRACTS / LISTINGS OF OTHER NRC OPERA TING EXPERIENCE DOCUMENTS 27 3.1 Abnormal Occurrence Reports (NUREG-0090) 27 3.2 Bulletins and Information Notices.
28 3.3 CaseStudiesand Engineering Evaluations.
30 3.4 Generic Letters..
34 3.5 Operating Rextor Event Memoranda..
35 3.6 NRC Document Compilations.:
36 Editor: Sheryl A. Massaro Office for Analysis and Evaluation of Operational Data U.S. Nuclear Regulatory Commission Period Covered:
September-October 1985 Washington, D C. 20555 8606110041 860531 PDR NUREG BR-OO51 R PDR J
1.0 SUMMARIES OF EVENTS 1.1 Reactor Trip, Possibly Due to Shorted Photohelic Cell in Output Power Supply at Cook On October 29, 1985 Cook Unit 2* was operating at about 80% power, having just stabilized at that level following a gradual escalation from 50%.
The unit had been in service for about a week, following an extended outage begun in mid-July 1985 to identify and repair leaking steam generator tubes.
The bulk of this previous operating week had been spent with the plant at 30% power, while steam generator chemistry was adjusted within specifications and a boric acid chemical flushing program of the steam generator secondary side was performed.
Unit 2 steam equivalent to about 1.5% power was being utilized for Unit 1 system test-ing.
Repairs to a containment radiation monitoring instrument were in pro-gress, as was a test of the steam generator level set II mismatch portion of the reactor protection system.
At 1:58 p.m., the reactor tripped from an indicated loss of reactor coolant flow on loop B.
No such loss of flow was apparent in the control room, nor were any activities known to be in progress which might be expected to affect either reactor coolant flow, the reactor coolant pumps, or the instrumentation for monitoring these items.
The operators began post-trip recovery, stabilizing the primary and secondary systems.
A few minutes into the recovery, the reac-tor operator observed that one of the two redundant reactor trip breakers (RTB A) had not opened.
Further, the anticipated motor-operated main feedwater isolation valve closure from reactor trip coincident with low average primary coolant temperature had not occurred for two of four main feed lines.
- However, since the feedwater regulating valves had closed in response to the feedwater isolation signal, the failure of the two main feedwater isolation valves to automatically close did not pose any operational concerns.
With all other re-covery operations proceeding normally, the Operations Superintendent, who was in the control room at the time, made the decision not to manually trip the failed breaker so as to preserve the as-failed condition.
The shunt trip attachment had not been converted to automatic; therefore, the only signal to the failed breaker would have been the loss of voltage to the undervoltage trip attachment.
The licensee notified the NRC on October 29, 1985, pursuant to 10 CFR 50.72, of the RTB failure and the apparent partial feedwater isolation failure.
Due to the potential significance of the RTB failure, the NRC conducted several tele-phone discussions with licensee management concerning the necessity for preserv-ing evidence pending a thorough investigation into this event.
Following these discussions on October 29, the NRC dispatched to the site an Augmented Incident Response Team (AIRT).
The following day, October 30, 1985, a Confirmatory
- Cook Units 1 and 2 are 1020 MWe (net) and 1060 MWe (net) MDC Westinghouse PWRs located 11 miles south of Benton Harbor, Michigan, and are operated by Indiana and Michigan Electric.
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Action Letter was sent to the licensee detailing certain commitments made by licensee management during the above telephone discussions.
A report was issued in December 1985 detailing the activities of the AIRT, the licensee, and their respective consultants in gathering information for developing conclusions con-cerning the cause and course of the automatic reactor trip, the actions of the plant operators during this event, the cause of the RTB failure, and associated Confirmatory Action Letter activities.
(Ref. 1.)
Post-trip review showed that the original trip initiator was a spurious indica-tion of loss of flow due to false open indication of the No. 2 reactor coolant pump (RCP) breaker.
Subsequent testing showed that the A reactor trip breaker undervoltage trip assembly had received a valid trip signal from the protection system (voltage had in fact been removed from the undervoltage trip assembly coil) and that the protection system would in fact generate this trip signal on receipt of need-to-trip indications.
Troubleshooting of the associated power supply (CRID-II)* showed it to be operating properly.
The conclusion reached (confirmation of the original hypothesis) was that the trip signal was in reaction to a momentary dip in the output voltage of the CRID and the " Loss of RCP" was the first reaction of this voltage dip.
Investigation of activities in progress at the time of the reactor trip revealed that troubleshooting of a radiation monitoring unit, that receives instrument and control power from CRID II, was in progress.
Reconstruction of the actions of the technician conducting the troubleshooting failed to identify any action that would have affected the CRID II output voltage.
However, subsequent troubleshooting of this radiation monitoring unit revealed a failed photohelic cell (a photoelectric meter indicating air flow) which gave indication of prior intermittent failure before its final failure.
This was discovered by " bumping" the radiation monitoring unit, an action that very conceivably could have occur-red during the technician's troubleshooting activities.
This photohelic cell is powered directly off the CRID II and failure in the manner observed, even intermittently, would very likely have resulted in an unnoticeable, momentary dip in the CRID II output voltage thereby initiating the trip signal.
Although there is i positive evidence that the photohelic cell shorted or otherwise affected t' CRID II output voltage, the licensee believes that this was the cause.
Subsequent to the event, the redundant reactor trip breaker B was tested and found to have suffered a loss of force margin after only 35-40 operations.
That i,, while the undervoltage trip attachment still possessed sufficient force co trip the breaker, the output force had decreased below the total out-put force specified by the manufacturer's test specifications.
Licensee investigation has determined that the breaker failed to trip due to failure of the undervoltage trip assembly device to function properly.
The Unit 2 f. reactor trip breaker has been replaced with a spare breaker which has been thoroughly inspected and tested per prescribed procedures.
The undervolt-age trip assembly which failed has been impounded, and the original A breaker has been set aside, both for further investigation.
Test results for the under-voltage trip attachment from reactor trip breaker A, that had actually failed, suggest that its failure may have been caused by:
(1) high functional forces
- Control room instrumentation distribution inverter No. II.
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caused by a manufacturing deficiency, and (2) degradation of the lubricant due to the high frictional forces.
Test results for the undervoltage trip attach-ment from reactor trip breaker B, that exh'bited a loss of force, suggest that such a loss should not be unexpected.
The staff is currently reviewing these results.
To prevent recurrence:
(1) the Control and Instrumentation Supervisor has cau-tioned all technicians and supt evisors on the potential impact of accidental shorting or component failure in equipment powered from CRID bus inverters; (2) prior to troubleshooting these types of loads, efforts will be made to iso-late the component for the CRID bus inverters, and (3) the reactor trip and by-pass breakers on both Cook Units 1 and 2 have been thoroughly inspected and tested and can be relied upon to function as required because of the following corrective actions:
Replacement of the suspect undervoltage trip assemblies with the new undervoltage trip assemblies and subsequent thorough testing.
Confirmation that the performance characteristics of the breakers themselves were consistent throughout the sequence of testing.
Installation and functional testing of the automatic trip features on the installed shunt trip attachments.
Performance of the technical specification 18-month surveillances on both units prior to startup.
Although Unit 1 was unaffected by the Unit 2 trip, the licensee agreed that both units should not start up until the cause of the Unit 2 breaker failure could be determined.
Careful evaluation of the event in conjunction with Westinghouse Electric Corporation, the manufacturer of the breaker, to ensure that the root cause could be isolated to the undervoltage trip assembly.
Implementation in Unit 2 of the Unit 1 technical specification testing requirements for shunt trip attachments.
Unit 1 had previously installed the automatic trip feature on the shunt trip attachment and had in place the technical specification testing requirements.
As an interim measure, increase from bi-monthly (as currently required) to monthly of the technical specification active testing requirement of the trip breaker, pending further evaluation of the event, including any desirable technical specification changes.
(Ref. 2.)
1.2 Reactor Trip with Subsequent Safety Injection During Load Rejection Test at Palo Verde On September 12, 1985, the licensee for Palc Verde Unit 1* (in power ascension testing) conducted a loss-of-load test from 53% power.
The plant did not per-form as expected.
The test resulted in the loss of all offsite power to non-essential loads (including the reactor coolant pumps), a turbine trip, and a
- Palo Verde Unit 1 is a 1270 MWe (net) MDC Combustion Engineering PWR located 36 miles west of Phoenix, Arizona, and is operated by Arizona Public 5ervice.
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subsequent reactor trip.
During the recovery phase of the event, overcooling of the reactor coolant system (RCS) occurred to the extent that the emergency core cooling systems were automatically initiated, followed by the associated automatic initiation of containment isolation.
The following two sequences occurred during the event that caused the loss of all three charging pumps:
(1) When a safety injection actuation signal (SIAS) occurred, power to certain suction valves for the nonsafety-related charging pumps was lost since the motor control center for these valves was classified as nonessential and, accordiagly was designed to be automatically shed from the safety related electric buses.
(2) Because of a malfunction of the single water level instrument channel for the volume control tank (VCT), automatic control action was lost which would have transferred the suction of the charging pumps from the VCT to the refueling water tank.
Also, after the containment isolation signal was received, all makeup flow to the VCT was isolated.
Due to the above sequences, the VCT emptied, the charging pumps became bound on VCT hydrogen cover gas and the pumps were tripped.
This produced a poten-tially hazardous situation when, to reestablish charging pump flow, the lines from the pumps were vented to remove gas.
The event is detailed below.
At 10:08 p.m., the main generator output breaker at Palo Verde Unit 1 was opened to initiate a load rejection test.
It was anticipated that this would cause the turbine to reduce speed and maintain house load requirements.
How-ever, the turbine electrohydraulic control system was unable to control the turbine at house loads, causing tne main generator frequency to decay.
With the house loads, including the reactor coolant pumps (RCPs), still connected to the main generator, a reactor trip occurred due to the reactor protection system core protection calculators sensing an imminent loss of forced coolant circulation.
The reactor trip generated a turbine trip.
As the generator speed continued to decrease, the RCP breakers opened as designed.
The house loads were deenergized when the auxiliary transformer breakers opened as designed, deenergizing nonessential buses NAN-501 and NAN-S02.
The fast transfer of these leads to offsite power did not occur be-cause of the low frequency on buses NAN-S01 and NAN-502.
As a result, power was lost to all non-class 1E powered radiation monitors (RMs) and to the RM computer.
All RM units required by technical specifications to perform safety-related actuations remained powered and capable of performing their safety function.
In addition, although the RM computer was not functional, all class powered RM units could be monitored using the remote indicating modules located in the control room area.
The reactor operators stabilized the plant at approximately 2000 psia in the reactor coolant system (RCS).
Natural circulation was established and veri-fled per procedure.
The shutdown margin was checked per procedure and was maintained at greater than 6%.
The nonessential auxiliary feedwater pump, AFN-P01, was started to provide feed flow to the steam generators, and an atmospheric dump valve on each steam 4
generator was manually opened to control steam pressure to ensure adequate tem-perature differential for natural circulation.
Circulating water pumps had lost power when buses NAN-S01 and NAN-502 were deenergized, making the condenser unavailable.
The RCS cooldown rate increased due to the feeding of auxiliary feedwater, loss of RCP heat input to the RCS, minimal decay heat, and main steam line drain valves reopening after restoration of power to the nonessential buses (these valves had previously been manually closed from the control room).
This higher than expected cooldown rate resulted in the pressurizer pressure dropping to less than the SIAS setpoint of 1837 psia, causing an automatic SIAS and con-current containment isolation actuation signal at 10:20 p.m.
Both systems performed as designed.
The RCS pressure decreased to appioximately 1819 psia before recovery within 2 minutes.
The total volume of safety injection was about 300 gallons.
The essential auxiliary feedwater pump B automatically started, but was not used immediately to feed the steam generators (SGs) due to adequate level in the SGs.
The charging pumps lost suction and were gas bound by the VCT hydrogen cover gas due to draining of the VCT.
The VCT drained due to the lack of automatic makeup, and failure of the outlet isolation valve (CH-UV-501) to close on a 10-10 level (5%) because of an erroneous level indication of 20%.
This was due to the VCT level instrument reference leg not being entirely full.
Main steam drain line valves were closed, and RCS cooldown stopped at 10,23 p.m.
Forced cooling of the primary system was restored at about 12:30 a.m. on September 13, 19,85.
Also during this event, the essential chiller A tripped due to low refrigerant charge.
Subsequently, the chiller was restarted and tripped again.
A defec-tive solder joint was discovered on the line from the evaporator to the purge.
This line was isolated, the chiller was charged with refrigerant, and was returned to service.
At no time during the evolution did the high pressure safety injection, low pressure safety injection, or containment spray pump room temperature reach a level where chiller operation was required.
Isolation of the purge line does not affect operability of the chiller.
Pressurizer level and pressure could be maintained by the high pressure safety injection pumps with the charging pumps not operating until charging flow was reestablished.
The post trip review identified several actions required for restart.
These were reviewed with the NRC subsequent to their implementation and subsequent restart.
As agreed to in a September 20, 1985 meeting between the NRC and the licensee, the compensatory measures were modified to the following short term measures:
(1) Monitor the reference leg of the VCT level indicator on a daily basis.
(2) Revise the appropriate procedures to require alignment of the refueling water tank to charging pump suction promptly on loss of offsite power.
4 (3) Institute procedural cautions on restart of the charging pumps.
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l (4) Examine the post-trip review process in light of this event to ensure that off-normal events are adequately evaluated, particularly with respect to 1
their potential safety significance.
l (5) Examine the process for vendor reviews of the remaining power ascension tests to assure that, for equipment particularly sensitive to the test being conducted, appropriate vendor input has been provided in the test development.
l (6) Review the shift complement for the remaining power ascension tests prior
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to performance of the test, to determine if additional staffing may be appropriate.
l Also, the licensee has evaluated the auxiliary pressurizer spray design and has identified the following enhancements:
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1 (1) Provide power to CH-501 and CH-536 from a 1E motor control center follow-l ing a loss-of-offsite power and/or an.SIAS.
l (2) Enhance the reliability of the VCT level indication.
(3) Provide automatic realignment of CH-501 and CH-536 on 10-10 VCT level and loss-of offsite power, to align charging pump suction from the refueling water tank.
(Refs. 3-6.)
1.3 Reactor Trip Results from Erroneous Control Board Information Due to Inverter Failure at Crystal River At Crystal River Unit 3* on October 26, 1985, the A inverter failed.
This caused a loss of the A main feedwater pump (FWP-2A), a plant integrated control system (ICS) runback to 55% power, tripping of the A reactor protection system (RPS) channel, and interruption of the primary power supply to the control rod position indication (RPI) system.
A reactor trip had not occurred, since two RPS channels are required to trip to generate a reactor trip.
Due to an impro-perly adjusted backup power supply, the RPI system momentarily indicated that all control rods were on the bottom of the core.
This information, combined with the alarms from the tripped RPS channel, caused control room operators to believe a reactor trip had occurred.
In accordance with plant procedures for a reactor trip, operators manually tripped the main turbine when it was observed that the main turbine had not automatically tripped.
Tripping the main turbine caused an anticipatory reactor trip.
The event is detailed below.
On October 26, 1985, the unit was operating at 95% reactor power. At 2:05 p.m.,
an unplanned turbine / reactor trip occurred following the (undervoltage) failure of the A 120 V ac vital bus inverter.
The failure of the inverter caused numer-ous alarms to occur as well as the loss of various A RPS powered instrument in-dications.
The A main feedwater pump tripped, resulting in initiation of an integrated control system (ICS) reactor / turbine runback to 60% power.
A par-tial trip of the RPS, engineered safeguards actuation system and the emergency feedwater initiation and control system also occurred.
- Crystal River Unit 3 is an 821 MWe (net) MDC Babcock & Wilcox PWR located 7 miles northwest of Crystal River, Florida, and is operated by Florida Power Corporation.
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As the runback progressed, one of the operators observed the control rod drive (CRD) position indicators showing all rods " fully inserted." This indicated that the reactor had tripped.
(Investigation later determined that the indi-cated trip was an erroneous signal.) He promptly announced that the reactor had tripped.
A second Control Board Operator, noticing that the turbine con-trol valves were not closed, manually tripped the main turbine approximately 19 seconds after the inverter failed.
This resulted in an actual anticipatory reactor trip.
During the event there was the smell and sight of smoke in the control room.
Immediate investigation of the smoke proved that the origin was the radiation monitoring panels.
They were deenergized immediately.
Following the turbine trip, a spurious emergency feedwater initiation and con-trol system actuation of emergency feedwater occurred.
The overcooling caused pressurizer level to decrease; the manual opening of one high pressure injec-tion valve maintained pressurizer level at or above 29 inches.
One main steam safety valve failed to reseat properly and required lowering of the main steam pressure to 990 psig to assist in reseating the valve.
There was no signifi-cant adverse affect on reactor coolant system (RCS) temperature.
The B main feedwater block valve did not go shut automatically.
This led to a slight overcooling of the RCS.
The Control Board Operator manually closed the valve.
Approximately 14 minutes after the reactor trip, the A inverter failed to zero voltage, and vital bus distribution panel VBDP-3 switched to the alternate power source.
The bus returned to normal voltage condition and the various associated alarms and indications returned to normal.
The actual cause of the reactor trip was operator action.
The operator be-lieved he had a tripped reactor and announced it as such.
Observation of the main turbine control panel by another operator showed that the main turbine had not tripped.
The second operator tripped the main turbine, which in turn led to an anticipatory reactor trip.
In retrospect, the operator tripped the tur-bine prematurely.
However, the actions taken were conservative for the indica-tions which he saw and were in keeping with the training and procedures provided.
There were two causes of erroneous control board indication, and they are only indirectly related.
The primary cause was that some instruments were powered from the failed A inverter.
They include such items as RC flow and narrow range RCS pressure.
The sustained low voltage condition is attributed to an improper undervoltage transfer setpoint in the static switch.
The second cause of erroneous indication was that the CRD position indication logic failed.
This was apparently caused by low voltage settings on both auctioneered power supplies.
The increased demands placed on the power supplies by the runback situation, combined with the low settings, resulted in logic failure.
The sustained low voltage condition on the vital bus also caused relays (in-cluding those in the radiation monitoring panel in the main control board) to overheat, which was the cause of the smoke in the control room.
The B main feedwater block valve was investigated, and it was determined that the A side inverter feeds the ICS control for the B main feedwater block valve.
l Investigative maintenance determined that a defective oscillator board caused I
the low voltage failure of the inverter, and it was replaced.
The three failed alarm relays in the radiation monitoring panels were also replaced.
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Licensee Engineering is developing recommendations for verifying the vital bus static switch undervoltage transfer setpoints.
In addition, the inverter / bus voltage and current alarms are being reviewed.
Possible changes to setpoints will be considered based on the information gained from the review.
The current limited power supplies for the CRD system were readjusted to proper setpoints.
These power supplies will be included in the preventive maintenance program to periodically verify the setpoints.
Licensee Engineering also is investigating the need for a modification to the B main feedwater block valve control circuit.
(Refs. 7 and 8.)
1.4 Blockage of Saltwater Flow to Service Water Heat Exchanger While Redundant Service Water System Inoperable Due to Maintenance at Calvert Cliffs On October 15, 1985, while Calvert Cliffs Unit 2* was at full power, service water (SRW) subsystem #21 was declared inoperable due to a partial blockage of saltwater (SW) system flow through SRW heat exchanger #21.
The redundant SRW subsystem was out of service for maintenance at the time.
The technical speci-fications do not permit operations for an extended period with both SRW trains inoperable (i.e., corrective actions are to be taken or the plant must be shut down within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />).
SRW subsystem #22 was restored and returned to service the same day while SRW subsystem #21 continued to provide non-accident SRW cooling loads.
The inlet channel head of SRW heat exchanger #21 was inspected and found to contain 10 gallons of shells.
The heat exchanger was cleaned and returned to service with normal SW flow.
The root cause of this event was marine growth being dislodged from the internal surfaces within the SW system, traveling into the inlet channel head of the heat exchanger and partially block-ing the inlet tube sheet.
The licensee plans to evaluate the effectiveness of the anti-biofculing system for the SW system, to determine more exactly the ef-fect of reduced SW flow on an SRW heat exchanger, and to add a cautionary note to an SW system preventive maintenance procedure.
The event is detailed bele At 3:45 a.m. on October 15, 1985, SW subsystem #22 was out of service for tube bulleting and eddy current testing of SRW heat exchanger #22 and emergency core cooling system (ECCS) pump room cooler #22 quarterly preventive maintenance (PM).
This meant that SRW subsystem #22 was inoperable, and also caused containment coolers #23 and #24 to be inoperable for lack of SRW cooling, and containment spray (CS) pump #22 to be inoperable for lack of room cooling.
At 11:30 a.m., during normal operation at 100% power, the Unit 2 Turbine Build-ing Operator noted a higher than normal differential pressure across SRW heat exchanger #21 on the SW side.
By 1:00 p.m., with the differential pressure still increasing, the Shift Supervisor ordered maintenance on SRW heat ex-changer #22 stopped, and ordered a performance evaluation (PE) of SRW heat ex-changer #21 to determine whether sufficient SW flow was being passed.
The PE, using SW pump discharge pressure, showed that SW flow was 17,000 gpm.
Since the dated Final Safety Report (FSAR), Section 9.5.2.3, statas that the required
- Calvert Cliffs Unit 2 is an 825 MWe (net) MDC Combustion Engineering PWR located 40 miles south of Annapolis, Maryland, and is operated by Baltimore Gas and Electric.
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SW flow for the SRW heat exchanger during a loss of coolant incident (LOCI) is 20,000 gpm, SRW heat exchanger #21 was declared inoperable.
This meant that both SRW subsystems were inoperable and limiting condition for operation (LCO) 3.7.4.1 was not met.
At 5:16 p.m. on October 15, SRW subsystem #22 was returned to service, providing one operable SRW subsystem.
The total elapsed time from the discovery of the degraded performance of SRW subsystem #21 and the return to service of SRW sub-system #22 was 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 16 minutes.
It is doubtful that SRW heat exchanger
- 21 was inoperable for a significant period prior to discovery, since the dif-ferential pressure across the heat exchanger increased rapidly.
During this period, SRW subsystem #21 continued to operate and provide heat removal for all non-LOCI components served without excessive SRW temperatures.
At 8:00 p.m. on October 15, the channel head for SRW heat exchanger #21 was cleaned, and 10 gallons of shells were removed.
At 11:30 p.m., SRW heat exchanger #21 was re-turned to service with normal SW flow.
The root cause of this event was marine growth being dislodged from the internal surfaces within the SW system.
The marine growth was apparently killed during tube bulleting and eddy current PMs on SW subsystem #21 from October 9-11, 1985.
The marine growth began to detach from internal surfaces after the subsystem had been back in service for approximately 3 days.
The marine growth, mostly shells, rapidly collected in the channel head of SRW heat exchanger #21 and partially blocked SW flow.
The other components served by SW subsystem #21 were not significantly affected.
An anti-biofouling system is installed for the SW system in order to minimize marine growth.
The safety functions served by euch SRW subsystem are to provide cooling water for two containment coolers to remove heat from the containment during a LOCI, and to provide cooling water for an emergency diesel generator (EDG).
During this event, however, SRW subsystem #21 was not supplying cooling water to EDG #12, since the redundant supply, SRW subsystem #12 (Unit 1), was being used.
Two CS pumps and associated heat exchangers provide redundant heat removal capability for the containment during a LOCI.
Each CS pump and heat exchanger can remove approximately 50% of the LOCI heat load.
Each of the four contain-ment coolers can remove approximately 33% of the LOCI heat load.
During this event, two of the containment coolers (supplied by SRW subsystem #22) and one of the CS pumps (cooled by ECCS pump room cooler #22) were not operable.
The components that remained available for containment heat removal during this event were CS pump #21 and its associated heat exchanger, and containment coolers #21 and #22.
The follow'ng long term corrective actions will be taken:
(1) Evaluate the effectiveness of the SW anti-biofouling system to determine whether modifications are necessary.
(2) Perform an analysis to determine whether an SRW heat exrbanger is still operable when SW flow is partially blocked.
(3) Add a cautionary note to the PM procedures for tube bulleting and eddy current testing of SW system heat exchangers to separate performance of the PM on SW subsystems for the same unit by a least two weeks, if possible.
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a The SRW heat exchanger used at Calvert Cliffs is made by Foster Wheeler, and is a Model #58-888-1, counter-flow, shell and tube type.
(Ref. 9.)
Between December 1984 and April 1985, the NR'C published a series of articles on bivalve fouling similar to that which occurred in this event.
These arti-cles are included in Bivalve Fouling of Nuclear Power Plant Service Water Systems, Vols. 1, 2 and 3 (NUREG/CR-4070), and are available from the Superin-tendent of Documents, U.S. Government Printing Office, P.O. Box 37082, Washing-ton, DC 20013-7892.
The reports contain detailed discussions of acute and chronic biofouling, provide good preventive and remedial actions, and also in-clude monitoring techniques.
1.5 Broken Pipe Restraint Reveals Error in Piping Analysis at Crystal River On October 28, 1985, Crystal River Unit 3* was operating at 96% reactor power when a cracked concrete support pedestal for the seawater discharge piping from the A and B nuclear services closed cycle cooling water system heat exchangers (SWHE 1A and SWHE IB) was discovered.
Investigation into the cause of the crack revealed an error in the computer piping analysis; expansion joints in the nu-clear services seawater system piping had been modeled incorrectly. While the piping reanalyses were being performed, an additional problem was discovered.
A rigid seismic restraint used in the computer model for the nuclear services seawater system was not included in construction documentation and, therefore, was never installed.
Piping anlayses were rerun and preliminary results indi-cated that the damaged pedestal could not withstand the revised design loads (pressure, dead weight and seismic.) Further refinement of the piping analysis showed that the original (undamaged) pedestals were also not capable of with-standing the revised loads.
Modifications to reinforce the pedestals and reduce the pressure related loading effects of the expansion joint were completed for the heat exchangers on November 3, 1985.
Installation of the missing seismic restraint was completed on November 4, 1985.
The event is detailed below.
On October 28, 1985, the unit was operating at 96% reactor power when a cracked concrete support pedestal for the seawater discharge piping from the A and B nuclear services closed cycle cooling water system heat exchangers (SWHE 1A and IB) was discovered by an operator doing routine surveillance.
Engineering personnel performed a field walkdown and examined the problem on October 29, 1985.
Following the walkdown, design load information for the cracked pedestal was requested from the plant's architect / engineer (A/E).
While waiting for this information, available design loads for a similar pedestal on the seawater inlet side of the heat exchanger were reviewed.
The loads were minimal and preliminary evaluation showed that the cracked pedestal would still provide adequate restraint.
On October 31, 1985, a second field inspection of the cracked support pedestal was performed.
Based on this inspection of expansion joints, pipe routing, and the support scheme, concerns were raised that a potential discrepancy between the analyzed design load and the actual load on this restraint might exist.
- Crystal River Unit 3 is an 821 MWe (net) MDC Babcock & Wilcox PWR located 7 miles northwest of Crystal River, Florida, and is operated by Florida Power Corporation.
10
After the second field inspection, the requested design loads for the cracked pedestal were received from the A/E.
The loads were of minimal magnitude and the A/E was asked to verify the accuracy of the existing computer analysis to address the concerns raised during the field walkdown.
This verification effort confirmed that the nuclear services seawater system piping model was deficient because there was an error in modeling the system expansion joints.
At that time, licensee Engineering and the A/E discussed design and repair alternatives and decided to prefabricate reinforcing plates for the cracked nuclear services seawater system pedestals.
These were to be used in the event that new analyses showed the cracked pedestal incapable of restraining actual loads.
On November 1, 1985, licensee Engineering performed hand calculations to model the effects of previously omitted system pressure effect on the expansion joints.
This analysis contained some very conservative assumptions to facilitate hand calculation.
The most notable assumption was applying all of the torsion load from the corrected pressure term to the pedestal; the results of the analysis indicated that none of the pedestals in the system were adequate to restrain the increased loads.
The A/E was directed to perform a new computer analysis using the original computer model and corrected pressure loading to determine how the new load would be distributed through the piping system and reduce load-ing on the pedestals.
As a contingency, installation of the prefabricated pedestal restraints and expansion joint tie rods began.
Later in the day, the A/E provided preliminary results of the reanalysis which showed a decrease in load when compared to the hand analysis.
However, it was agreed that the damaged pedestal could not adequately restrain the revised loads while it was judged that the undamaged pedestals would be adequate to restrain the revised design loads.
Heat exchangers SWHE 1A and 1B were declared inoper-able because of the cracked support and revised analysis.
The A/E was directed to refine the analysis and determine the effect of the revised loads on the un-damaged support pedestals.
Installation of the pedestal restraints and expan-sion joint tie rods for inoperable heat exchangers continued and was completed on November 2, 1985.
The refined analysis was completed on November 2, 1985, and showed that the undamaged support pedestals for heat exchangers SWHE 1C and 10 were not capable of withstanding the design loads.
These heat exchangers were declared inoper-able on the basis of the refined analysis.
The situation was corrected by in-stallation of reinforcement plates and expansion joint restraints like those used on heat exchangers SWHE 1A and 18.
Repairs were completed on November 3, 1985.
During the reanalysis of the nuclear services seawater system piping on Novem-ber 2, 1985, the A/E informed the licensee that they had discovered an addi-tional problem.
A rigid seismic restraint, used in the computer model, had not been included in construction documents and, therefore, was never installed in the plant.
The computer analysis was rerun without this restraint and the system was found to be unable to restrain seismic loads.
Temporary restraints were installed and remained in place until a permanent restraint was installed on November 4, 1985.
The cause of the cracked concrete support pedestal is attributed to a piping design error.
The compter model input used to analyze the system did not properly model the pip expansion joints.
This error allowed pressure forces 11
to exceed the design loads of the pedestal.
The cracks were probably induced by hydrostatic testing conducted during the 1985 refueling outage.
It should be noted that hydrostatic test pressure (110 psig) is significantly in excess of the normal system pressure (one pump operation - 35 psig) or emergency sys-tem operation (two pumps - approximately 70 psig).
The missing seismic re-straint was the result of an omission during transfer of the computer design output to restraint fabrication documents.
To investigate the cause of this design error and determine if there were generic implicatons, the A/E conducted a review of 10% of the original piping support analysis packages.
This review concentrated on work done by the origi-nator and verifier of the package with the omitted restraint.
Drawings used during this review were the seismic isometric drawings which were confirmed to as-built status as part of the NRC IE Bulletin 79-14 effort.
This review re-vealed no other examples of missing restraints.
During the operating life of the plant, approximately 13 additional percent of the piping analyses have been redone as part of the modification process.
This redesign process typically includes a review of original design basis assump-tions which would detect an error of this type.
To date, none has been discovered.
From this investigation, the A/E concluded the event to be an isolated human error.
To assure this assessment is correct, licensee Engineering and Quality Assurance personnel conducted a design control audit of the A/E's design pro-cess and, specifically, the investigations conducted as a result of the miss-ing restraint.
The scope covered compliance with ANSI N45.2.11 design require-ments as well as other areas.
The audit team issued no findings relative to the missing restraint.
Also, since the original design documents were confirmed to be in agreement with the seismic isometric drawings, the validity of the work done in response to IE Bulletin 79-14 was reaffirmed to be correct and complete.
The pipin-analysis error could have led to a failure which would render both trains of nuclear services closed cycle cooling inoperable.
The missing seis-mic restraint, combined with a seismic event, could have also led to a similar event. The less of both trains would be a condition outside the design basis of the plant.
The design of piping systems is very conservative, however, and the loss of both trains of these heat exchangers is considered extremely remote, even when the design errors are accounted for.
Repairs have been made to reinforce all of the piping support pedestals for the nuclear services closed cycle cooling heat exchangers.
Tie rods were installed across the nuclear services seawater system piping expansion joints to eliminate the pressure on the pedestals and a new seismic restraint was fabricated and installed in the location that was omitted in the original design.
An investi-gation is in progress by the A/E to determine the design adequacy for all safety-related rubber expansion joints.
(Ref. 10.)
12
1.6 Valve Failure to Open When Operated from the Control Room Due to Incorrect Torque Switch Setting at Oconee On October 15, 1985, an unsuccessful attempt to open an electric motor-operated (EM0) valve (3LP-2) was made from the Oconee Unit 3* control room.
Unit 3 was
'in hot shutdown after coming off-line for maintenance.
The valve is required to open in order to initiate the decay heat removal cooling mode.
The cause of the incident was the torque switch settings on the valve.
Rotork Nuclear Actuator settings were not set high enough to operate the valve under system The EMO valve torque switch settings were not specified in the design pressure.
modification package used to replace the valve actuator with a new Rotork Nuclear Actuator.
The immediate corrective action was to open the valve from the valve actuator contactors at the motor control center, bypassing the valve actuator's torque switch limit control circuit.
The event is detailed below.
On October 15, 1985, while the Jnit was in hot shutdown, an unsuccessful attempt was made to open the reactor coolant return block valve from the control room.
The reactor coolant pressure was between 300-400 psig.
There was an attempt made to open the valve, but it failed, and the valve was opened manually by actuating the contactors at the motor control center.
This was the fifth known occurrence of this valve not opening when operated from the control switch since the installation of a new actuator in April 1984.
The root cause of this incident, and the prior incidents when valve 3LP-2 failed to open when it was operated from the Unit 3 control room, is that the valve operator did not have the correct torque switch settings installed.
The set-tings for opening and closing the valve were both set at "1," as they had been set at the factory on November 16, 1983.
These settings were adequate for the factory test, but were not intended to be the settings for the valve actuator in the field.
The torque switch settings were not specified to be any different in the design modification package.
Rotork Control, Inc., also did not speci-fically state the torque switch settings in their " Instruction Manual for Rotork Valve Actuators." This incident is, therefore, attributed to failure to pro-perly install a component.
Another contributing cause is a procedural deficiency.
The Maintenance Proce-dure for Rotork limit / torque switch settings is not written to set torque switches for valves that cannot be cycled under normal operating conditions and system pressures.
Also, because it contains conditional steps for setting the opening and closing torque switches, the opening torque switch setting.tep was never required to be performed.
This step, if performed, would have set the torque switch setting to the maximum setting, "5."
The immediate corrective action was to manually close the valve actuator contac-tors at the motor control center, which opened the valve, initiating decay heat removal cooling mode.
A work request was written to check and repair the valve.
The torque switch settings for closing and opening were raised to "4" and "5,"
respectively.
The actuator passed the stroke time test, and on November 7, 1985 the valve successfully opened when operated from the control room under system differential pressure.
- 0conee Unit 3 is an 860 MWe (net) MDC Babcock & Wilcox PWR located 30 miles west of Greenville, South Carolina, and is operated by Duke Power.
13
I I
In addition,'a review will be performed for potential generic problems relating to the problem of not specifying the torque settings on design documents for implementation of new valve actuator installations.
Maintenance will verify that the Rotork Nuclear Actuator torque / limit switch setting procedure is in l-accordance with the Rotork Instructional Manual Procedure, and will make correc-tions to deficiencies found.
Maintenance will also completely rework valve 3LP-2 during the next cold shut-down outage of sufficient duration.
This should determine if any problems existed with the valve that may have caused it to fail to open.
(Ref. 11.)
1.7 Both Trains of Control Room Ventilation Inoperable Due to Personnel Misreading Ductwork Drawings at Byron On September 13, 1935, it was discovered that one of the two trains of control room ventilation (VC), the 0A train, was inoperable for eight days at Byron Unit 1* without the plant Operating Department's knowledge, due to an incor-rectly placed blank-off plate installed in the VC makeup unit ductwork as a modification done by the Project Construction Department.
Throughout the event, the unit had been operating at greater than 45% power.
On the eighth day, the i
OB train was made inoperable due to an intake damper being placed out of ser-vice, causing the main discharge damper to fail closed.
This condition was also not recognized by the operators, because power supply listings did not adequately call out multiple components on single electrical feeds.
This was npt discovered until 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> later, when the OB train was started.
The two trains were repaired and returned to service.
To prevent recurrence, the Pro-ject Construction Department has been directed to review heating, ventilating, t
and air conditioning (HVAC) drawing conventions'with the people responsible for interpreting them, including personnel responsible for the incorrect installa-tion of the blank-off plate.
The' master book of electrical feeds was being revised to include all electrical feeds with multiple loads.
The event is detailed below.
On September 5, 1985, a blank-off plate was installed in the control room VC make-up unit (M/U) ductwork.
This plate prevented filtered make-up air from reaching the control room.
The Project Construction Department installed the blank-off plate as part of a modification that was intended to replace a tem-porary alteration, and make the temporary alteration permanent.
However, the Project Construction Department made an error in reading the HVAC ductwork drawings and, as a result, incorrectly identified the location for the blank-l off plate. Thus, a new blank-off plate was placed in the M/U ductwork, and the blank-off for the temporary alteration, which was installed in the correct l
location, was removed.
In addition, when the contractors removed the blank-off plate for the temporary alteration, they failed to notify the Shift Engineer, which is a violation of the temporary alteration program.
With the blank-off plate improperly installed, the OA train of VC was inoper-able.
However, the Operating Department was not aware of the improper location of the new blank-off plate and, therefore, considered the 0A train operable.
The OB train of VC remained in operation at this time (without the M/U running),
and the OA train of VC was in standby.
- Byron Unit 1 is a 1129 MWe (net) MOC Westinghouse PWR located 17 miles southwest of Rockford, Illinois, and is operated by Commonwealth Edison.
l l
14 i
At 6:20 p.m. on September 12, the OB train of VC was shutdown and the OA train of VC was started with the M/U.
About 25 minutes later, the minimum outside air intake damper for the OB train (0VC16Y) was taken out-of-service for main-tenance, and the OB train of VC was declared inoperable.
At this time, both trains of VC were inoperable (although tne Operating Department was still un-aware of the inoperable 0A train).
The OVC16Y damper, however, did not make the OB train inoperable.
The OVC16Y damper fails closed when power is removed which is the required position for emergency VC operation.
The damper that did make OB train inoperable was the OVC172Y, the OB train main supply damper.
Both the OVC16Y and OVC172Y receive power from the same electrical feed.
Thus, when the OVC16Y was taken out-of-service, the OVC172Y was affected and became inoperable.
The latter condition was not identified during the out of-service period, and OVC172Y was considered operabic.
At 7:00 a.m. on September 13, it was observed that the 0A train of VC was unable to maintain the control room >1/8" positive pressure with the M/U in operation.
At this time, operators were ' dispatched to verify the VC line-up and the integ-rity of the control room boundary.
At 7:40 a.m., the M/V was shut down to enable further inspection of the ductwork and fire dampers.
With the M/U not in operation, the control room returned to
>1/8" positive pressure.
During this time the OB train was declared operable since damper OVC16Y was closed.
The Operators were not aware that the OB trair was actually inoperable because of the OVC172Y damper.
Therefore, both trains of VC were still inoperable.
At 10:00 a.m. on September 13, the blank-off plate was found in the OA train M/U ductwork, and the 0A train was declared inoperable.
Operators then began switching to the OB train.
Twenty minutes later, with the OB train now in operation, and the M/V running, the control room again could not be maintained at >1/8" positive pressure.
The OB train was then declared inoperable and limiting condition for operation (LCO) 3.0.3 was entered.
The operators then found the failed OVC172Y damper and began taking steps to return it to service.
By 10:52 a.m., electrical power was restored to 0VC172Y, the OB train was de-clared operable and LC0 3.0.3 was exited.
At 12:15 p.m., the blank-off plate was removed from the M/U ductwork and a new plate was installed in the proper section of ductwork.
About an hour later, the 0A train was declared operable.
The root cause of 0A train inoperability was construction personnel misreading HVAC ductwork drawings; OB train inoperability was due to operators taking out of service a single electrical feed affecting multiple unidentified load.
To prevent recurrence of this event, the Project Construction Department has been directed to review HVAC drawing conventions with those people responsible for interpreting them, including the personnel responsible for improperly install-ing the blank-off plate.
The Construction Department has been counseled on the requirements of the temporary alteration program (i.e. the Shift Engineer's ap-proval must be obtained before any temporary alteration is removed).
- Finally, a procedure has been written to track revision of the master book of electrical feeds to identify all electrical feeds with multiple loads.
(Ref. 12.)
15 i
1.8 References r
(1.1) 1.
NRC, Augmented Incident Response Team Report 50-316/85035, Decem-ber 17, 1985.
2.
Indiana and Michigan Electric, Docket 50-316, Licensee Event Report 85-35, November 27, 1985.
(1.2) 3.
NRC, Preliminary Notification PNO-V-59 (PNO-V-85-58 Update),
September 18, 1985.
4.
Letter from H. L. Thompson, Jr., NRC, to E. E. Van Brunt, Jr.,
Arizona Nuclear Power Project, October 2, 1985.
5.
Arizona Nuclear Power Project, Docket 50-528, Licensee Event Report 85-63, October 23, 1985.
6.
NRC Region V, Inspection Report 50-528/85-32, December 5, 1985.
(1.3) 7.
Florida Power Corporation, Docket 50-302, Licensee Event Report 85-23, November 25, 1985.
8.
NRC Region II, Inspection Report 50-302/85-42, December 16, 1985.
(1.4) 9.
Baltimore Gas and Electric, Docket 50-318, Licensee Event Report 85-09, November 14, 1985.
(1.5) 10.
Florida Power Corporation, Docket 50-302, Licensee Event Report 85-24-01, December 19, 1985.
(1.6) 11.
Duke Power, Docket 50-287, Licensee Event Report 85-03, November 14, 1985.
(1.7) 12.
Commonwealth Edison, Docket 50-454, Licensee Event Report 85-89, October 8, 1985.
These referenced documents are available in the NRC Public Document Room at 1717 H Street, Washington, DC 20555, for inspection and/or copying for a fee.
(AE00 reports may also be obtained by contecting AE00 directly at 301-492-4484 or by letter to USNRC, AE00, EWS-263A Wasnington, DC 20555.)
16
2.0 EXCERPTS OF SELECTED LICENSEE EVENT REPORTS On January 1, 1984, 10 CFR 50.73, " Licensee Event Report System" became effec-tive. This new rule, which made significant changes to the requirements for licensee event reports (LERs), requires more detailed narrative descriptions of the reportable events.
Many of these descriptions are well written, frank, and informative, and should be of interest to others involved with the feedback of operational experience.
This section of Power Reactor Events includes direct excerpts from LERs.
In general, the information describes conditions or events that are somewhat un-usual or complex, or that demonstrate a problem or condition that may not be obvious.
The plant name and docket number, the LER number, type of reactor, and nuclear steam supply system vendor are provided for each event.
Further information may be obtained by contacting the Editor at 301-492-9752, or at U.S. Nuclear Regulatory Commission, EWS-263A, Washington, DC 20555.
Excerpt Page 2.1 Inadequate Design Assumption Results in Non-Single Failure-Proof Circuit at Fort Calhoun.................................
18 2.2 Charcoal Adsorber Damage Due to Exposure to Fire Protection Water at Cook.................................................
19 2.3 Loss of Residual Heat Removal from Partial Loss of Instrument Power Due to Personnel Error at Cook..........................
20 2.4 Inadvertent Actuation of the Reactor Protective System Due to Personnel Error at Arkansas...................................
20 2.5 Isolation Condenser Steam Supply Pipe Weld Cracking, Possibly Due to Intergranular Stress Corrosion at Millstone............
22 2.6 Low Condenser Vacuum Scram Caused by Air Inleakage through Steam Relief Valve Discharge Line at Dresden..................
22 2.7 Reactor Water Cleanup Isolation Due to High System Differential Flow from Valve Leakage Past Seals at Hatch...................
23 2.8 Reactor Water Cleanup System Isolation on High Differential Flow Due to Failure of Outlet Vent Valve to Fully Close at Limerick......................................................
24 2.9 Reactor Trip Due to Loss of Main Feedwater at Rancho Seco.....
25 17
2.1 Inadequate Design Assumption Results in Non-Single Failure-Proof Circuit Fort Calhoun; Docket 50-286; LER 85-09; Combustion Engineering PWR In 1982, the licensee opted to change the. logic for isolation of the main feed-water isolation valves to be identical to that used for isolating the main steam isolation valves.
This change was to prevent isolating feedwater for all events causing a containment isolation signal (as was formecly the case).
Because the circuitry for the isolation of the main steam isolation valves already existed, the decision to duplicate this circuitry via an additional relay was made.
This circuitry change was made such that main feedwater is now isolated on a containment pressure high signal (CPHS) or a steam generator low pressure signal (SGLS).
The actuation signals used on the main steam isolation valves were applied to the added relay, now responsible for closing, on one train, one containment (feedwater) isolation valve, and the backup to the feedwater isolation valve.
The other train is responsible for, closing one containment (feedwater) isolation valve, one backup feedwater isolation valve, and both main steam isolation valves.
This maintained necessary separation between trains.
- Further, since the single relay in question was a normally energized GE Type HFA relay, upon loss of power, it would assume its accident mode.
Thus the system was designed fail safe.
During a refueling outage on October 18, 1985, while conducting a review of circuit drawings as part of an unrelated review, a question was raised because a system description logic diagram had listed both main steam isolation valves was being signaled off of the same train of accident signal.
Further investi gation was conducted, and it was determined that the wiring diagrams agreed with the logic diagram.
Field verification confirmed that the installed wiring was consistent with the drawings.
At this point, it was decided that, given the possibility of failure in other than the deenergized mode, the design was not single failure proof, and could have led to operation outside the design basis v the plant.
Subsequ to the installation of this modification, it has been realized that HFA relays have the poteatial for f ailure in other than their " failure" mode; e.g.,
remaining energized when expected to deenergize, or deenergizing but not releasing, thus behaving as if still energized.
In.he event that a main steam line break would have occurred, concurrent with the failure of the relay to assume its correct accident position, the automatic closure of both main steam isolation valves would not occur.
This event, is outside the bounds of the plants safety analysis for a main steamline break event.
The corrective steps taken in order to correct this deficiency are as follows:
(1) Modify the logic for isolation of the main steam isolation valves in order to eliminate this single failure concern.
(2) Review other modifications designed during the time frame (1982-1983 re-fueling outage) to ensure no other safety system was designed utilizing this design philosophy regarding single-failure modes of relays.
18
r I
l 2.2 Charcoal Adsorber Damage Due to Exposure to Fire Protection Water Cook Unit 2; Docket 50-316; Westinghouse PWR During visual inspections conducted between September 3 and 9, 1985, it was dis-covered that the charcoal adsorber banks within three technical specification filtration units had been inadvertently exposed to fire protection water.
On September 8, 1985, it was determined that, as a consequence of the water expo-sure, the charcoal adsorbers could have incurred damage.
The filtration units involved include:
(1) Unit 2, engineered safety features (2-HV-AES-2), discovered September 3, 1985.
(2) Unit 1, control room emergency ventilation (1-ACRF), discovered Septem-ber 7, 1985.
(3) Unit 2, control room emergency ventilation (2-ACRF), discovered Septem-ber 9, 1985.
During a thorough inspection, each charcoal tray within 2-HV-AES-2 was found to contain potassium iodide crystals.
This signifies degradation of the charcoal media due to excessive exposure to water.
Since all charcoal trays within the unit had been affected, it is concluded that the water damage was the result of apparent spray header pressurization.
Water damage was not apparent in all charcoal trays within the ACRF systems (control room emergency ventilation for both Units 1 and 2).
Only the charcoal trays positioned at the bottom of the filter bank were found to have been ex-posed to water.
This indicates fire protection system leakage rather than a complete deluge.
The system consists of an automatically actuated isolation valve which separates this particular system from the fire protection water header. Wetting of the charc ml trays occurred when the isolation valve leaked and its associated drain did not function.
This resulted in the filling of the fire protection spray header, wetting of the filtration unit, and subsequent charcoal damage.
All affected charcoal trays within the three units were removed, emptied, cleaned and refilled with new charcoal.
Following completion of the charcoal changeout and repair of the mechanically damaged trays, in place filter tests were conducted.
The filtration units were returned to service on the following dates:
Unit 2, HV-AES-2, October 4, 1985; Unit 1, ACRF, September 24, 1985; and Unit 2, ACRF, October 3, 1985.
To prevent the recurrence of inadvertent fire protection system actuations, a design change has been initiated to change fire protection system actuation from automatic to manual.
To prevent future spray header leakage, the leaking isolation valves and associated drains were repaired as required.
19
/
t 2.3 Loss of Residual Heat Removal from Partial Loss of Instrument Power Due to Personnel Error Cook Unit 1; Docket 50-315; LER 85-46; Westinghouse PWR On September 7, 1985, at 0720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> with Unit 1 in cold shutdown for refueling and Unit 2 in cold shutdown for maintenance, voltage'was lost on control room (Unit 1) instrument bus' distribution for channel 3 circuits.
Channels 3 and 4 were being powered from an alternate 120-V ac power source because of design change modifications being performed on the normal power supplies.
Instrument channels 1 and 2 were supplied by their normal vital buses.
A licensed reactor operator proceeded to investigate the. loss of power.
The operator thought both channel 3 and channel 4 circuit breakers had tripped open.
The operator then attempted to reset both breakers bj opening, then closing.
This caused the channel 4 instrument circuit to be momentarily deenergized.
This resulted in various ESF reactor trip signals and loss of residual heat re-moval pumps due to the refueling water storage tankilow level indication read-ing low from power loss (the refueling water storage tank low level signal is designed to protect the pumps from loss of suction head).
The loss of the heat removal system placed the unit in a limiting condition for operation per Tech-nical Specification 3.4.1.3.
The residual heat removal _ system was restored to an operable condition within 2 minutes of the power loss to the channel 4 instrument circuit.
The channel 3 circuit breaker was investigated and found to.tave an inadequately terminated lead.
The connection,was remade and the brdaker returned to service at 0835 hours0.00966 days <br />0.232 hours <br />0.00138 weeks <br />3.177175e-4 months <br />.
The NRC was notified at 0832 hours0.00963 days <br />0.231 hours <br />0.00138 weeks <br />3.16576e-4 months <br /> of the ESF signals and th.e loss of res~idual heat removal capability.
The error is considered to be a failure on the part of the operator to recognize the true condition of the channel 4 circuit breaker and taking action when no immediate action was required.
AIternate power for two out of four instrument circuits is only used for mainte-nance while in a cold shutdown condition.
Therefore, this event would not have occurred in a' hot shutdown, hot standby or power operation.
Control room in-strument cha"inels 1 and 2 were protected by their respective vital buses during No sour'e range nuclear in'strumentation was lost and no emergency r this event.
c core cooling system actuation occurred: The inadequate terminated lead in the channel 3 circuit breake.r is considered to bs a random failure and not generic in nature.
Topreventrecurrence,theoperatorhasbeencouns(Iednottotakeimmediate
~
actions where the situation does not require it.
2.4 Inadvertent Actuation of the Reactor Protection System Due to Personnel Error Arkansas Unit 2; Docket 50-368; LER 85-?0; Combustion Engineering PWR On September 19, 1985, the plant was in cold shutdown for reactor coolant pump seal replacement.
Shutdown bank A control rods were withdrawn for " cocked rod" s
s 20
protection, as required by procedure.
Core protection calculator (CPC) channels B, C and D were in the trip bypass condition for the CPC calculated low departure from nucleate boiling ratio (DNBR) and high local power density (LPD) trip func-tions.
Because normal low power operation cause CPC trips, these CPC trip func-tions are bypassed at the CPC operator's module as allowed by a <10 4 percent power reactor protection system (RPS) log power bypass permissive bistable.
Due to an electronics problem within the A RPS channel log pcwer nuclear instru-mentation, the <10 4 percent power bypass permissive bistable was not available.
The CPC low DNBR and high LPD trip functions were therefore bypassed at the A RPS channel remote operator's console as an operational alternative.
At approximately 0830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br />, monthly surveillance testing was initiated on the C RPS channel.
Procedures require the RPS trip functions to be bypassed at the RPS remote operator's console in order to f acilitate the surveillance testing of the tested channel.
The RPS trip function bypasses are configured such that only one channel can be bypassed at a time (also a technical specification re-quirement).
The A RPS channel bypasses for the CPC low DNBR and high LPD trip functions were removed placing the A RPS channel in the trip condition for these functions.
This permitted C RPS channel trip bypasses to be instated for sur-veillance testing.
At 0858 hours0.00993 days <br />0.238 hours <br />0.00142 weeks <br />3.26469e-4 months <br /> the licensee instrumentation and control technicians completed testing of the C RPS channel high logarithmic power trip function and removed the bypasses for the RPS high log power, low DNBR, and high LPD trip func-tions.
Testing of the RPS high log power trip function requires placing the RPS channel nuclear instrumentation circuit in a test condition which also generates an RPS low DNBR and high LPD trip (even with the CPC <10 4 percent power bypass permissive bistable in bypass).
One of the technicians noted that the sequence of events (SOE) computer printer had jammed and the procedure step requiring verification of SOE actuation on a high log power trip could not be completed.
The technician decided to repeat the previous test step to verify the SOE actuation.
The high log power trip was then reinitiated, but contrary to procedural requirement, the high LPD trip function bypass was not reinstated prior to the high log power trip initiation.
Hence, simultaneous trip conditions existed in RPS channels A and C on high LPD, which satisfied the necessary two out of four channel trip logic for RPS actua-tion.
The RPS actuation caused the reactor trip circuit breakers (RTCBs) to open, which resulted in the insertion of the withdrawn group of control rods.
After notifying the Shift Supervisor of the event, the technicians reset the RPS and closed the RTCBs.
At approximately 0903 hours0.0105 days <br />0.251 hours <br />0.00149 weeks <br />3.435915e-4 months <br /> the shutdown bank of control rods was again withdrawn for cocked rod protection.
RPS surveillance testing was resumed and completed without incident.
No abnormal plant condi-tions were noted as a result of the actuation.
The test procedure has been reviewed and it has been determined that the event was not the result of procedural inadequacy.
Therefore, the technician involved was counseled by plant management regarding attention to detail and procedural compliance.
The electronic problem associated with the A channel log power nuclear instrumentation will be resolved during the next outage of sufficient duration.
21
[
2.5 Isolation Condenser Steam Supply Pipe Weld Cracking, Possibly Due to Intergranular Stress Corrosion Millstone Unit 1; Docket 50-245; LER 85-22; General Electric BWR On October 31, 1985 at 1400 hours0.0162 days <br />0.389 hours <br />0.00231 weeks <br />5.327e-4 months <br />, as a result of performing inservice inspec-tion (ISI) during the 1985 refuel outage, ultrasonic test indications that are believed to be intergranular stress corrosion cracking (IGSCC) were identified within the heat affected zone of a 12-inch isolation condenser weld, designated ICAC-F-13. More than one indication was observed within the 8-inch length.
Flaws extended 0.22-inch deep by 2.5-inch long, with two other areas within the 8-inch area that were not as deep. The ISI pipe weld inspection scope was increased per A.S.M.E.Section XI article IWB-2430.
The indication in ICAC-F-13 which is in an A.S.M.E. Class II piping system, was repaired using the weld overlay repair technique in accordance with the A.S.M.E.
Code,Section XI, 1980 edition.
The filler metal was type 308L to ensure the weld overlay has immunity to IGSCC and superior weld metal toughness.
The weld overlay was surface inspected using liquid penetrant to ensure weld integrity, and was ultrasonically inspected to ensure weld to base metal bonding and a defect free overlay volume.
The addition of the weld overlay to the piping system was analyzed to ensure that the global piping structure integrity cri-teria (USAS B31.1) was not compromised.
Furthermore, the impact of the addi-tional mass was evaluated to ensure that the applicable piping support struc-tural integrity has not been degraded.
A pressure test of the isolation con-denser was also performed.
A similar incident occurred in 1984 (LER 50-245/
84-08).
2.6 Low Condenser Vacuum Scram Caused by Air Inleakage through Steam Relief Valve Discharge Line Dresden Unit 2; Docket 50-237; LER 85-35; General Electric BWR On September 29, 1985, during a scheduled shutdown, a full reactor scram occurred due to low condenser vacuum.
The scram occurred at 2355 hours0.0273 days <br />0.654 hours <br />0.00389 weeks <br />8.960775e-4 months <br /> and while reactor power was at 0.08%.
The loss of vacuum was attributed to air inleakage through a ruptured expansion joint (bellows) on the seal steam relief valve (2-3018-700) discharge line.
The line is directly connected to the main condenser.
Discussion with the Unit Foreman on shift previous to the event revealed that at approxirtately 2215 hours0.0256 days <br />0.615 hours <br />0.00366 weeks <br />8.428075e-4 months <br /> on September 29, due to difficulty maintaining seal steam header pressure at approximately 4 to 6 psig, a minor adjustment had been made to the seal steam pressure regulator on the turbine floor to increase seal steam pressure.
The seal steam header pressure gauge was indicating 0 to 1 psig.
The minor adjust-ment of the pressure regulator resulted in an immediate increase of header pressure to approximately 20 psig as indicated by the gauge.
The Unit Foreman immediately decreased the pressure to a stable 5 psig.
Dresden Operating Pro-cedure 5600-2 (gland seal system) does not address operation of the seal steam pressure regulator.
22
It was hypothesized that at 2215 hours0.0256 days <br />0.615 hours <br />0.00366 weeks <br />8.428075e-4 months <br /> on September 29, the seal steam relief valve (2-3018-700) performed its designed function and lifted.
The flow of steam past the relief valve may have caused line movement, resulting in damage to the bellows and subsequently causing a complete failure.
The safety significance of the event was minimal since all reactor scram func-tions performed their designed intent.
The bellows on the discharge line was replaced.
However, to prevent recurrence of this event tags will be made for both Dresden Unit 2 and Unit 3 and will be located at the seal steam pressure regulators to notify Operators of the sensi-tivity of the regulators when minor adjustments are made.
An Action item Re-cord will be submitted to determine if a design modification is needed to pre-vent future bellows failures and a " caution" statement will be added to Dresden Operating Procedure 5600-2 to further notify Operators of the seal steam pres-sure regulators' sensitivity.
2.7 Reactor Water Cleanup Isolation Due to High System Differential Flow from Valve Leakage Past Seals Hatch Unit 2; Docket 50-366, LER 85-32; General Electric BWR At approximately 1235 CDT on October 5, 1985, with the unit operating at 2436 MWt (about 100% power) and following performance of the reactor water cleanup demineralizer procedure (HNP-2-1326), plant personnel were placing the reactor water cleanup (RWCU) system in service per the " Reactor Water Cleanup System" procedure (HNP-2-1325).
At that time, they noted that the RWCU pump inboard suction isolation valve (2G31-F001) had isolated on high system differential flow.
After an investigation, plant personnel determined that the RWCU backwash air supply isolation valves 2G31-F076B and 2G31-F109B were leaking past their poly-ethylene seats, which were worn out from normal service.
Consequently, when the RWCU system was placed in service, water flowed past the two valves and exited into the radwaste collection system through RWCU air supply relief valve 2G31-F049.
This caused the RWCU system to isolate (i.e., isolation valve 2G31-F001 closed) on high differential flow.
Subsequent to the investigation, RWCU air supply isolation valves 2G31-F076B and 2G31-F109B were rebuilt by replacing their valve seats and "0" ings.
The valves were functionally tested when the RWCU system was satisfactorily returned to service on October 8, 1985, about 1500 CDT.
This event had no adverse safety consequences (i.e., the isolation of valve 2G31-F001 occurred as required and as such had no impact on safe operation of the plant), nor were other safety systems in Unit 1 or Unit 2 affected.
The identification information for the failed valves was as follows:
(1) Isolation valve 2G31-F076B:
Part No. 198-00-367.
Manufactured by Contromatics Corporation.
(2) Isolation valve 2G31-F109B:
Part No. 998-00-08.
Manufactured by Contromatics Corporation.
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2.8 Reactor Water Cleanup System Isolation on High Differential Flow Due to Failure of Outlet Vent Valve to Fully Close Limerick Unit 1; Docket 50-352; LER 85-72; General Electric BWR On September 7, 1985 at 1039, with Unit 1 at 22.4% power, an isolation of the reactor water cleanup (RWCU) system occurred.
The isolation resulted from high differential flow between the inlet and outlet of the RWCU system while placing the A RWCU filter /demineralizer in service following regeneration.
The high differential flow developed when out " vent valve HV-45-1-07A (Zomax Tufline) did not fully close.
Seals on two flow glasses in the backwash piping ruptured and the reactor coolant water / resin mixture was released to the RWCU area on elevation 313 of the reactor enclosure.
The increase backwash line pressure caused the pressure relief valve PSV-45-1-67 to open and discharge resin in the A hold pump room.
The RWCU system i,) lated as a result of high differential flow between the sys-tem's inlet and ou,let.
The high differential flow developed when outlet vent valve HV-45 '.-07A cid not fully close.
The limit switch incorrectly indicated the valve was closed.
The valve was examined and found to biad during closure.
The ven*,line pressure increased and ruptured the seals on two flow glasses, allowis.g the release of the reactor coolant / resin mixture to the area.
The increased line pressure also caused PSV-45-1-67 to open and discharge resin into the A hold pump room.
The remotely operated manual isolation valve upstream of the air-operated vent valve was closed and the isolation signal reset.
Decontamination was started and the RWCU system was returned to service by 1710.
The outlet vent valve and limit switch were examined and equipment trouble tags were assigned to have them repaired.
The RWCU area was cleaned and released for unrestricted use by September 18, 1985.
The A hold pump room is still under Radiation Work Permit restrictions as it was before the event occurred.
The RWCU filter /demineralizer startup procedure S45.8.A was revised to include the closing of isolation valves (1-39A(B) and 1-29A(B)) upstream from each vent valve prior to pressurizing the regenerated RWCU filter /demineralizer.
This revision will prevent damage which could result from another automatic vent valve failure.
Engineering is investigating the implementation of additional modifications.
The RWCU system was in service before the isolation occurred, and reactor water chemistry remained stable during the event.
The liquid release to the affected areas is estimated to be 5.06 E-3 millicuries.
The release was terminated by the RWCU system isolation which occurred 45 seconds after the high differential flow signal was generated.
No personnel received any excessive expcsure as a result of this event.
No radioactive material escaped beyond the boundaries of the reactor enclosure.
The affected areas have been decontaminated.
The adverse consequences, as a result of the RWCU system isolation, were minimal.
24
...-.'yly'in-2.9 Reactor Trip Due to Loss of Main Feedsater Rancho Seco; Docket 50-312; LER 85-19; Babcock & Wilcox PWR On October 2,1985, with the reactor at approximately 15% power, a loss of main feedwater (MFW) caused a high reactor coolant system pressure, resulting in a reactor trip.
An automatic start of the auxiliary feedwater (AFW) system occurred as a result of the loss of main feedwater.
The AFW system functioned properly.
Several other problems occurred either immediately prior to or sub-sequent to the loss of main feedwater.
Condenser vacuum was lost, the main turbine did not trip at the low vacuum setpoint, the fourth point feedwater heater relief valves lifted and remained open, the reactor cooled down greater than 100 F per hour, and a flow anomaly was observed when high pressure injection was manually initiated due to decreasing pressurizer level.
Mainly due to the prolonged opening of the fourth point feedwater heater re-lief valves, the reactor coolant temperature decreased below the normal post reactor trip temperature of approximately 550 F to approximately 490 F in 20 minutes.
This cooldown exceeded the 100 F per hour cooldown rate limit given in Figure 3.1.2-2 of the technical specifications.
The fourth point feedwater heater relief valves were required to be set at 160 i 5 psig.
The pegging steam which supplies these heaters at low power was controlled at 150 5 psig.
The setpoints on these nonsafety related relief valves were not checked since plant construction, according to the licensee.
After the event, the licensee det. ermined that one relief valve lifted at 151 psig and the other at 158 psig.
It appears that the prolonged opening was due to a lack of setpoint surveil-lance (which allowed drift) and inadequate design margin for the relief valve setpoint above system working pressure of 150 5 psig.
The licensee's correc-tive action included raising the relief setpoints to 175 5 psig and reducing the pegging steam setpoint to 130 1 5 psia.
25
3.0 ABSTRACTS / LISTINGS OF OTHER NRC OPERATING EXPERIENCE DOCUMENTS 3.1 Abnormal Occurrence Reports (NUREG-0090) Issued in September-October 1985 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 provi-sions 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 summaries of certain events that may be perceived by the public as significant but do not meet the Section 208 abnormal occurrence criteria.
No Abnormal Occurrence Reports were issued during September-October 1985.
27 I
3.2 Bulletins and Information Notices Issued in September-October 1985 The Office of Inspection and Enforcement periodically issues bulletins and information notices to licensees and holders of construction permits.
During the period, one bulletin and ten 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 af a serious generic problem, an NRC bulletin may be is-sued requesting licensees to take specific actions, and requiring them to sub-mit a written report describing actions taken and other information NRC should have to assess the need for further actions).
A prompt response by affected li-censees is required and failure to respond appropriately may result in an en-forcement action. When appropriate, prior to issuing a bulletin, the NRC may seek comments on the matter from the industry (Atomic Industrial Forum, Insti-tute of Nuclear Power Operations, nuclear steam suppliers, vendors, etc.), a tech-nique which has proved 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 acknowledgement or response, but recipients are advised to consider the applicability of the information to their facility.
Date Bulletin Issued Title 85-01 10/29/85 STEAM BINDING OF AUXILIARY FEEDWATER PUMPS (Issued to several PWRs holding an operating license, as listed in an attachment, and to all PWRs holding a construc-tion permit)
Information Date Notice Issued Title 85-76 9/19/85 RECENT WATER HAMMER EVENTS (Issued to all nuclear power reactor facilities holding an operating license or a construction permit) 85-77 9/20/85 POSSIBLE LOSS OF EMERGENCY NOTIFICATION SYSTEM DUE TO LOSS OF AC POWER (Issued to all holders of a nuclear power plant operating license or a construction permit) 85-78 9/23/85 EVENT NOTIFICATION (Issued to all power reactor facili-ties holding an operating license or construction per-mit) 85-79 9/30/85 INADEQUATE COMMUNICATIONS BETWEEN MAINTENANCE, OPERA-TIONS, AND SECURITY PERSONNEL (Issued to all nuclear power reactor facilities holding an operating license or a construction permit, research and nonpower reactor 28
facilities, and fuel fabrication and processing facili-l ties using or processing formula quantities of special nuclear material) 85-80 10/15/85 TIMELY DECLARATION OF AN EMERGENCY CLASS, IMPLEMENTA-TION OF AN EMERGENCY PLAN, AND EMERGENCY NOTIFICATIONS (Issued to all nuclear power facilities holding an operating license or a construction permit) 85-81 10/17/85 PROBLEMS RESULTING IN ERR 0NE0USLY HIGH READING WITH PANASONIC 800 SERIES THERM 0 LUMINESCENT 00SIMETERS (Issued to all nuclear power reactor facilities hold-ing an operating license or a construction permit, and certain materials and fuel cycle licensees who may use the subject thermoluminescent dosimeters) 85-82 10/18/85 DIESEL GENERATOR DIFFERENTIAL PROTECTION RELAY NOT SEISMICALLY QUALIFIED (Issued to all nuclear power reactor facilities holding an operating license or a construction permit) 85-83 10-30-85 POTENTIAL FAILURES OF GENERAL ELECTRIC PK-2 TEST BLOCKS (Issued to all nuclear power reactor facilities hold-ing an operating license or a construction permit) 85-84 10/30/85 INADEQUATE INSERVICE TESTING OF MAIN STEAM ISOLATION VALVES (Issued to all power reactor facilities holding an operating license or a construction permit) 85-85 10/31/85 SYSTEMS INTERACTION EVENT RESULTING IN REACTOR SYSTEM SAFETY RELIEF VALVE OPENING FOLLOWING A FIRE-PROTECTION DELUGE SYSTEM MALFUNCTION (Issued to all nuclear power reactor facilities holding an operating license or a construction perait) 29
3.3 Case Studies and Engineering Evaluations Issued in September-October 1985 The Office for Analysis and Evaluation of Operational Data (AE0D) has as a pri-mary responsibility the task of reviewing the operational experience reported by NRC nuclear power plant 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 AEOD 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 require-ments of the responsible NRC program office.
Case Date Study Issued Title C502 9/85 OVERPRESSURIZATION OF EMERGENCY CORE COOLING SYSTEMS IN B0ILING WATER REACTORS This report presented the results of a generic review and evaluation of operational events involving actual and potential overpressurization of emergency core cool-ing systems in boiling water reactors.
Eight events, each entailing the failere of a testable isolation check valve on the injection line of an emergency core cooling syste'n, were identified and evaluated.
Five of the eignt events involved an additional failure of the second and final isolation barrier--the inadvertent opening of a normally closed motor-operated injection valve.
Four of these five events occurred during power operation, thus leading to an actual overpressurization of an emergencj core cooling s,ystem.
Each'of these operational events is considered a precursor to an interfacing loss-of-coolant accident between the reactor coolant system and an emergency core cooling system.
Such an accident would involve the suiden discharge of reactor coolant at operating pressure a1d temperature outside the primary containment, and would also likely disable one or more of the safety systems required to mitigate the accident.
Collectively, these operating events indicate a trend which has serious safety implications--that the likeli-hood of an interfacing loss-of-coolant accident is higher 30
by two to several orders of magnitude than had been I
previously assessed.
Although none of the operating events has yet resulted in an actual pipe failure, AE0D's assessment concluded that generic corrective measures are needed to prevent recurrences involving potentially more serious consequences.
Special Date Study Issued Title S503 9/85 EVALUATION OF RECENT VALVE OPERATOR MOTOR BURN 0UT EVENTS AE0D has been monitoring operating events pertaining to motor operated valves since the issuance of AE0D case study C203, " Valve Operator-Related Events During 1978, 1979, and 1980," in May 1982.
One issue covered by that report was a recommendation addressing valve operator motor burnout.
Because of recent events, AE0D conducted a limited review and evaluation of a few events.
Based on the limited review, it has been concluded that valve operator motor burnout continues to pose a potential safety problem.
The data corroborates the original AE0D recommendation in C203 relative to a reassessment of Regu-latory Guide 1.106 concerning bypassing of thermal over-load (TOL) devices.
Although only a few events were reviewed and analyzed, additional search techniques have identified more than 180 events subsequent to the original 19 events in C203.
These additional events cover the time frame from 1981 to early 1985.
Accordingly, this study recommended that the Office of Nuclear Reactor Regulation use this report as a basis to expedite implementation of the NRR proposed plan to address valve operator motor burnout and a reassessment of Regulatory Guide 1.106.
Engineering Date Evaluation Issued Title E512 9/4/85 FAILURE OF SAFETY-RELATED PUMPS DUE TO DEBRIS This evaluation found that due to the design of cen-trifugal pumps used in high head safety injection sys-tems for pressurized water reactors (PWRs), these pumps could be susceptible to mechanical problems from abra-sive foreign particles in the pumped fluid.
Foreign ma-terial having similar characteristics could potentially exist inside containment and pass through most exist-ing sump screen designs.
A significant finding in this evaluation was that the use of hinged-type screen access doors or grates employed in some containment sump designs have the potential to fail open as a result of not being properly secured.
These would result in 31
defeating the safety function of the sump screens, which would lead to potential damage and failure of multiple pumps in the emergency core cooling system (ECCS) and block flow through spray orifices in the containment spray system.
Because of the potential safety implications of degrada-tion and/or possible failure of multiple pumps in the ECCS from debris due to imptoperly secured containment sump screen doors or grates, this evaluation suggested that an NRC information notice be issued addressing the safety significance of sump screen integrity and the need for administratively controlling these access openings to the sump.
The information notice should also notify all PWR licensees of the potential undetect-able common cause failure of the ECCS due to foreign ma-terial contamination of the ECCS borated storage tanks.
It was also suggested that the scope of NRC Generic Is-sue 38, " Potential Recirculation System Failure as a Consequence of Ingestion of Containment Paint Flakes or Other Fine Debris," De expanded to evaluate the poten-tial loss of the high pressure recirculation system during small-break LOCA mitigation for PWRs.
E513 9/16/85 HIGH PRESSURE CORE SPRAY SYSTEM RELIEF VALVE FAILURES Prompted by several high pressure core spray (HPCS) system relief valve failures reported at LaSalle Units 1 and 2, AE0D initiated a review of these events and an evaluation of the potential for similar failures at other boiling water reactors (BWRs) with HPCS systems.
The investigation found that the relief valve failures at LaSalle were caused by excessive backpressure on the discharge port of the relief valve.
At LaSalle, back-pressure on the valve port occurred whenever the HPCS system operated because the relief valve discharge was hard piped to the HPCS minimum flow line.
The minimum flow line operates at relatively high internal pressure when the HPCS pump is running.
Special tests performed at LaSalle showed that the backpressure at the HPCS pump discharge relief valve reached approximately 100 psi.
However, the Crosby Valve Company relief valves involved in the failures have a backpressure rating of only 90 psi.
The consequences of the valve failure were significant valve leakage into the HPCS compartment, and a loss of containment integrity.
At LaSalle, the excessive back-pressure problem was corrected by routing the relief valve discharge to the reactor building equipment drain-age system.
From this review of the HPCS system flow diagrams and the relief valve designs for each of the other potentially affected BWRs, AE00 concluded that River Bend Unit 1 32
7 is the only other plant with a potential for relief valve failures of the type which occurred at LaSalle.
At River Bend, the HPCS pump discharge line relief valve is also manufactured by the Crosby Valve Company and has a dis-charge which is hard piped to the HPCS minimum flow line.
In view of the similarities between the two plant designs, the evaluation suggested that NRC's Region IV Office request the licensee to evaluate the suitability of the HPCS system relief valve discharge piping design in light of the failures which occurred at LaSalle.
E514 10/8/85 CORE DAMAGE PRECURSOR EVENT AT TROJAN During 1984, five events occurred at the Trojan nuclear power plant which could have had serious consequences for equipment or personnel had they occurred under dif-ferent circumstances.
The potentially most serious event occurred on September 20, 1984 when multiple, inde-pendent undetected failures of safety-related components resulted in the partial loss of the emergency onsite power supply and the total loss of the safety grade aux-iliary feedwater system.
The other four events are also discussed in detail in the report.
The findings of this evaluation indicate that the Sep-tember 20 event was a severe accident precursor with a conditional core melt probability of 3.5E-2 to 4.9E-3, depending upon the assumptions made.
The significance of this event as a severe accident precursor and its po-tential consequences had not previously been recognized.
It also was found that the reliability of the safety grade auxiliary feedwater (AFW) pumps was poor, and re-sulted in the need to rely on the nonsafety grade motor-driven pump r> ore than is desirable.
If the safety grade AFW pumps continue to S monstrate a poor reliability record, as in the pa it was recommended that the NRC Region V Offics uke steps to require improvement.
Collectively, the five events indicate a lack of atten-tion to detail, a lack of good maintenance practices, and a lack of appreciation or the significance of oper-ating experience at other facilities.
Positive actions to correct all of these deficiencies have been initiated.
The NRC Region V Administrator met with the licensee on October 12, 1984 to discuss the significance of the September 20 event.
The Region emphasized that senior management must take more of an interest in the operation of the plant.
They are also closely following the li-censee's corrective actions, both short term and long term.
33
(.
3.4 Generic Letters Issued in September-October 1985 Generic letters are issued by the Office of Nuclear Reactor Regulation, Division of Licensing.
They are similar to IE Bulletins (see Section 3.2) in that they transmit information to, and obtain information from, reactor licensees, appli-e cants, and/or equipment suppliers regarding matters of safety, safeguards, or environmental significance.
During September and October 1985, three 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 regard-ing the continued safe operation of facilities.
They have been a significant means of communicating with licensees on a number of important issues, the reso-lutions of which have contributed to improved quality of design and operation.
Generic Date Letter Issued Title 85-17 8/23/85 AVAILABILITY OF SUPPLEMENTS 2 AND 3 TO NUREG-0933, "A PRIORITIZATION OF GENERIC SAFETY ISSUES" (Issued to all licensees of operating reactors, applicants for operating licensees, and holders of construction permits) 85-18 9/27/85 OPERATOR LICENSING EXAMINATIONS (Issued to all power reac-tor licensees and applicants for an operating license) 85-19 9/27/85 REPORTING REQUIREMENTS ON PRIMARY COOLANT IODINE SPIKES (Issued to all licensees and applicants for operating power reactors and holders of construction permits for power reactors) 34
3.5 Operating Reactor Event Memoranda Issued in September-October 1985 The Director, Division of Licensing, Office of Nuclear Reactor Regulation (NRR) disseminated information to the directors of the other divisions and program of-fices 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 Office for Analysis and Evaluation of Operational Data, and of Inspection and Enforcement for their information.
No OREMs were issued during September-October l'385.
35 i
e-3.6 NRC Document Compilations The Office of Administration issues two publications that list documents made publicly available.
The quarterly Regulatory and Technical Reports (NUREG-0304) compiles bib-liographic data and abstracts for the formal regulatory and technical reports issued by the NRC Staff and its contractors.
The monthly Title List of Documents Made Publicly Available (NUREG-0540) contains descriptions of information received and generated by the NRC.
This information includes (1) docketed material associated with civilian nuclear power plants and other users of radioactive materials, and (2) non-docketed material received and generated by NRC pertinent to its role as a regulatory agency.
This series of documents is indexed by Personal Author, Corporate Source, and Report Number.
The monthly Licensee Event Report (LER) Compilation (NUREG/CR-2000) might also be useful for those interested in operational experience.
This document contains Licensee Event Report (LER) operational information that was processed into the LER data file of the Nuclear Safety Information Center at Oak Ridge during the monthly period identified on the cover of the Jocument.
The LER summaries in this report are arranged alphabetically by facility name and then chronologically by event date for each facility.
Component, system, keyword, and component vendor indexes follow the summaries.
Copies and subscriptions of these three documents are available from the Super-intendent of Documents, U.S. Government Printing Office, P.O. Box 37082, Washing-ton, DC 20013-7982.
36
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