ML20237J003
| ML20237J003 | |
| Person / Time | |
|---|---|
| Issue date: | 08/31/1987 |
| From: | Massaro S NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| References | |
| NUREG-BR-0051, NUREG-BR-0051-V09-N1, NUREG-BR-51, NUREG-BR-51-V9-N1, NUDOCS 8708250248 | |
| Download: ML20237J003 (33) | |
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[D POWER REACTdR EVENTSC i,
h/g3United States Nudear Regulatory Commission t
Date Published; AUGUST '1987
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Power Reactor f vents is a bi-monthly newsletter that compile./ operating experidnce ir'tormation about commerciai nuclear power pTa'nts. ilyis includes summaries o' noteworthy events and hstings a'idlor abstacts of USNRC and otbei' documents that discun safety related or possible generir issues. It is intended to hed back some of the lessons learned from operational espaience to the various c, tat pe.tonnel ie., managers. licensed reactor operators training coor-dinators, and support personnel Rehenced documeds are nailable from the USWE C Public Document Room at 1717 H Street, Washington. O C. 20555 for d copying fee. Subscrstions of Power Reactor Event, nay be requested frcirw the Superintendent of Documents. U.S Covernment Priating Officca WashingLn. D.C. 20402, er on (202) 783-3238 c
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1.0 SUMMA RIES OF EVENTS...
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1.1 Feedvator Line Break Due to Severe Pipe Wall Thinning Cauns Fatalitin et Sur.y Unit 1.. +
1 1.2 Containnne Equipment Hatch Air Lock Equalizing Valves Inoperable Due to Failure l
of etitstlorising Mechanism at Seabrook=
4 1.3 Ddective Steam Generator Tubes Nnt Repaired Prior to Startup Due to incorrect Final Review Decisiun at Millstone Unit 2...
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1.4 Referenccs.......
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l 2.D ' EXCERPTS OF SELECTED LICEN5FE EVENT REPORTS....
13 3.0 ABSTRACTS / LISTINGS OF OTHER NRC OPERA TING EXPERIENCE DOCUMENTS....
21 3.1 Abnormal Occurrence Reports (NUREG-0090L 21 3.2 Bulletins and information Notices 23 3.3 Case Studies and Engineering Evaluations.................
2S 3.4 Generic Letters.....
29 34 3.5 Operating Reactor Event Memoranda-3.6 NRC Document Compilations. -
Si G708250248 870831 POM NUREG SR- 0051 R PDR Editor: Sheryl A. Massaro Office for Analysis and Evaluation of Operational Data U S. Nuclear Regulatory Commission Period Covered:
January-February 1987 Washington, D C. 20555
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l' 1.0 SUMMARIES OF EVENTS S
1.1 Feedwater Line Break Due to Severe Pipe Wall Thinning Causes Fatalities at Surry Unit 2
'y On December 9, 1986, at 2:20 p.m., a serious event occurred at the Surry Power Station. While both Units 1 and 2* were operating at 100% power, the 18-inch suction line to the main feedwater pump A for Unit 2 failed catastrophically.
Eight workers who were working in the vicinity, some of whom were replacing d
thermal insulation on a nearby line, were burned by flashing feedwater.
All
.were transported to area hospitals.
Two e rkers were treated and released.
Four other workers subsequently died.
The event was initiated by the unexpected
(
closure of the C main steam trip valve.
The Unit 2 reactor tripped due to low-low water level in the C steam generator (SG).
About 40 seconds after the trip, i
a carbon steel elbow in the 18-inch suction pipe to the A main feed pump ruptured, causing a loss of normal feedwater.
The ruptured feedwater piping has been attributed to pipe wall thinning due to erosion / corrosion, f
The licensee for Surry (Virginia Power) has committed extensive resources toward providing other nuclear plants, and fossil plants, with information on the'causes and corrective actions taken regarding this event.
The Institute of Nuclear Power Operations (INP0) also has provided the U.S. and foreip,n nuclear industry with valuable information through its various reports.
The most informative source regarding the event may be Virginia Power's second supplemental Licensee Event Report (Ref. 1, p. 16), which provides as an attachment the licensee's lengthy "Surry Unit 2 Reactor Trip and Feedwater Pipe Failure Report, Revi-sion 1."
Also, the event was summarized in NRC Information Notice 86-106, Sup-piements 1 and 2 (Ref. 2), and was reviewed in-depth in a report (Ref. 3) written by an NRC Augmented Inspection Team (AIT).
The team consisted of nine experts, including one on water hammer phenomena, from various NRC offices.
In addition to these, the team was assisted by four NRC inspectors knowledgeable in security, fire protection systems, water chemistry, and check valve design.
The findings of this AIT report are summarized below.
On December 9, 1986, with both units operating at 100% power, a Unit 2 reactor trip followed by a main feedwater (MFW) line rupture occurred.
Unit 2 had recently completed a refueling outage and returned to full power operation on December 8, 1986.
A low-low level in the C SG caused a reactor trip and automatic startup of the two motor-driven auxiliary feedwater pumps.
The control room operators noted the SG code safety valves lifting and regulated SG pressure through the atmospheric dump valves.
Approximately 30 seconds after the trip, the unit's electrical busses auto-transferred to offsite power.
A small steam release noise was heard followed by a very loud noise approximately 5 seconds later.
The 18-inch
- Surry Units 1 and 2 are each 781 MWe (net maximum dependable capacity)
Westinghouse PWRs located 17 miles northwest of Newport News, Virginia, and are operated by Virginia Power.
1
suction line to the A main feedwater pump subsequently was found to have rup-tured at the elbow where the line connects to the 24-inch condensate supply header.
A shift supervisor who was in the turbine building, realizing that a large line break had occurred, went to the control room and alerted the control room operating staff.
All secondary pumps (high and low pressure drains, condensate and main feedwater) were secured, and the break was isolated.
Water to the SGs was supplied by the auxiliary feedwater system.
The primary systems responded normally to the loss of load transient.
Reactor coolant temperature, pressure, and pressurizer level were stabilized in the de-sired band.
A notification of unusual event was declared by the licensee at 2:27 p.m. and was upgraded later to an ALERT in order to ensure accountability of all station I
personnel.
The station's halon and carbon dioxide fire suppression (cardox) systems actuated and the plant security card reader system deactivated because of water short-circuiting control systems in the area.
Control room habitability was a con-cern prior to initiating emergency control room ventilation due to cardox actuation. The carbon dioxide was apparently coming into the control room from the turbine building hallway, and through the normal ventilation supply system.
The emergency was terminated at 4:25 p.m. after personnel accountability had been established.
Eight individuals were injured due tu the blowdown of high temperature steam and water in the turbine building and were transported to area hospitals.
Four of the injured subsequently died.
Two of the injured were treated at a clinic and released.
The remaining two individuals were hospitalized and released later.
The rupture of the 18-inch A MFW suction pipe occurred on a 90-degree elbow at a point about 1 foot from where the suction pipe joins the 24-inch condensate supply header.
Observation of the damaged A MFW pump suction piping indicated significant movement of the piping following the rupture.
The piping attached to the pump suction, dropped and rotated away from the break point, pivoting on the elbow near the pump suction.
Although the piping came to rest against a portion of the B MFW pump discharge piping it did not appear to have damaged it.
Inspection of the area following the event also revealed that one piece of suc-tion piping had ripped off and was blown some distance from the break point.
The piece was about 2 feet by 3 feet in siza.
It appears that the joint between the suction pipe and condensate supply header provided lateral support of the suction piping assembly including the suction isolation valve.
The loss of this support along with the blowdown forces of the failed suction pipe assembly prob-ably contributed to the pivot and rotation of the assembly.
It is also likely that back flow from the B MFW pump through the damaged A MFW pump discharge check valve and ott the broken suction pipe contributed to the severity of the pipe whip motion of the feedwater pump suction pipe.
The failed 18-inch suction line was fabricated from ASTM A-106, Grade B, Extra Strong carbon steel seamless pipe and ASTM A-234, Grade B, Extra Strong, WPB carbon steel wrought fittings with a nominal wall thickness of 0.500 inches.
2
Licensee field metallurgical investigation of the failed elbow resulted in the following observations:
(1) Visual inspection of the inside surface of the elbow revealed a dimpled surface appearance, generally thinned wall and a number of localized very thin areas.
The localized thin areas were small in area, usually less than 1 inch across, with remaining wall thickness as small as 1/16 inch.
The areas were fairly smooth and blended smoothly into the surrounding material.
Ultrasonic wall thickness measurements showed the wall thinning to be a gradual sloping change over most of the surface of the elbow.
The general wall thickness of the elbow varied from 0.120 inches to 0.390 inches.
The short section of upstream pipe varied in thickr.ess from 0.150 inches to 0.450 inches.
Near the elbow, thickness measurements on the section of downstream pipe revealed thicknesses from 0.295 inches to 0.405 inches.
The wall thickness of pipe a short distance downstream of the elbow was within manufacturer's tolerance.
(2) Field metallurgical replicas taken on the surface of the elbow revealed a microstructure typical of ASTM A-106 Grade B material with no signs of strain.
(3) The fracture surface was typical of a ductile tearing mode failure.
Tears, which appeared to be fracture origination points, were noted at two localized thin cavity areas of the fracture.
Small defects, indicative of laps, laminations and inclusions, typical for A-106, Grade B, materials, were noted at the fracture surface.
One of these small defects was noted at one of the thin overload tear areas and could have been the start of the fracture.
The licensee's analysis revealed the following probable scenario for the pipe failure:
(1) The pipe failed because of a thinned wall.
A corrosion / erosion mechanism is the probable cause of the wall loss.
Wall loss by this mechanism occurs by a gouging-out pattern on the carbon steel surface under the action of a flowing medium and an electrochemical action.
This phenomenon has been well documented for two phase flow such as extraction steam systems, and the licensee has an inspection procedure documented for monitoring the piping wall thickness of its two phase systems.
However, for single phase flow systems, such as the feedwater and condensate systems, the problem had not been previously recognized.
The only place where the phenomenon has been documented in a single-phase flow system is in the steam generator feed ring J-tubes.
The design geometry of the failed elbow in the feed-water suction line is similar to the design geometry of the feed ring J-tubes.
Both consist of a header or large diameter pipe and a right angle discharge pipe with a 90- or 180-degree turn.
The licensee concluded that the turbulent flow created by the georoetry and the low oxygen feedwater probably contributed to the corrosion / erosion thinning of the pipe wall.
(2) Because of the thinned wall (as thin as 0.048 inch in a localized area and 0.100 inch over a more general area), local membrane stresses were near yield at system pressure and temperature of 367 psig and 374 degrees F, respectively.
When the piping system underwent a pressure transient, the localized tensile stresses exceeded yield, resulting in failure in a thin 3
wall' cavity.
The ASME Code minimum wall equation, assuming an internal pipe pressure of 600 psig, a temperature of 370 degrees F, and an ultimate strength of 60,000 psi, results in a calculated burst thickness of 0.090 inches and a yield thickness of 0.173 inches.
Therefore, with a local cavity thickness of 0.040 inches, a genera 1' thickness of 0.100-inch, and an upward pressure transient, the material easily exceeded its burst strength.
The initial tensile overload tear was considered to have arrested and not to have developed into an unstable tearing mode.
Water flashing to steam was heard by station personnel.
As water continued to flash to steam for a few seconds and' pressure continued to increase in the elbow, an unstable tear developed in a second thin walled area.
The pipe then' ruptured, ejecting the fragment from the elbow.
Based on the failure of Surry Unit 2 main feedwater pump suction line and the fact that the Surry Unit 1 suction line design was similar to Surry Unit 2, the licensee decided to shut down Surry Unit 1 and inspect the main feedwater pump suction line. The Surry Unit I suction line was found to have reduced wall thicknesses similar to Surry Unit 2.
As a result of finding thinned pipe at both units, the licensee initiated a pipe wall thickness measuring inspection program to define the extent of pipe wall thinning at Surry Units 1 and 2.
P* ping showing unacceptable thinning was replaced.
Additional corrective actions are being assessed and implemented.
1.2 Containment Equipment Hatch Air Lock Equalizing Valves Inoperable Due To Failure of Interlocking Mechanism at Seabrook On February 11, 1987, while Seabrook* was in hot shutdown preparing to enter hot standby, the licensee discovered a breach in containment integrity when the 1-inch globe valves on the personnel doors to the containment equipment hatch were found open.
These valves normally are opened to equalize pressure in order to open the personnel hatches to allow personnel access into the chamber leading into and out of the containment. When the personnel hatches are closed, these valves are interlocked to close with the hatches.
Investigation founo a failure in the interlocking mechanism, as discussed below, which prevented the valves from closing when the personnel hatches were shut.
On February 11, 1987, about 1:45 p.m., during the performance of Technical Specification Surveillance 4.6.1.3 (local leak rate test Type B) on the equip-ment hatch air lock 0-ring seals, the sound of air flow was detected by the en-gineer performing the test.
Further investigation revealed air leaking through the pressure equalizing valves (1-inch ball valves) located on the outer door of the equipment hatch air lock.
(See Figure 1.) The door was then opened, and it was observed that the valve linkage assembly was not operating the equalizing valve in the outer door, indicating a problem with the valve linkage assembly.
Once inside the air lock, personnel removed the cover plate from the linkage assembly and found that the linkage arm was separated from its connecting pin
- Seabrook is a 1150 MWe Westinghouse PWR located 10 miles south of Portsmouth, New Hampshire, and is operated by Public Service of New Hampshire.
The plant is licensed for fuel loading and precriticality testing.
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Figure 1. Equipment Hatch Air Lock 5
1 and bushing.
The outer door was then closed and air flow noise was again noticed.
The air flow noise was discovered to be leakage into the air lock through the inner door equalizing valves.
Further investigation revealed that the linkage arm on the inner door was also disconnected from its connecting pin and bushing.
At 2:10 p.m., the Shift Test Director arrived at the door.
Recognizing the potential significance of the loss of containment integrity by the observed leakage through the equalizing lines of both doors, the Shift Test Director went to the control room to explain the situation to the Shift Superintendent, instructing the test engineer to continue with his planned test of the 0-ring seals of the inner and outer doors.
It was subsequently determined that the root cause of the open equalizing valves was the separation of the mechanical
. linkage between the equalizing valves and their respective handwheels.
(See Figure 2.)
In the Control Room, the Shift Superintendent on watch recognized that if air lock integrity was not established on at least one of the two air lock doors within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> (from 2:10 p.m.), a cooldown would have to be started in order to comply with Technical Specification 3.0.3, which requires that if unable to comply with the most limiting condition of a technical specification, a shut-down to cold shutdown condition must be started within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The Shift Superintendent sent the Shift Test Director bacP. to the door to attempt to expedite restoration of containment integrity and air lock operability.
At 2:45 p.m., the linkage was reconnected on the inner door; however, a test performed by connecting compressed air to a fitting between the inner and outer valves on the inner door indicated that at least the inner valve was still leaking. Work on the inner door was suspended to try to restore the equalizing valves on the outer door to normal.
About 10 minutes later, the linkage on the outer door equalizing valves was reconnected and the door shut.
A test of the valves indicated that the outer valve was leaking.
The door was reopened and an assistant was stationed inside the air lock to ensure that the valve linkage was staying in place while the door was shut again.
The linkage appeared to operate normally, although the outer valve still leaked.
At 3:10 p.m., as the 1-hour time limit had been reached, and emergency equipment door air lock integrity had not been restored, a cooldown was started to comply with Technical Specification 3.0.3.
The oncoming Shift Superintendent realized that initiating a shutdown to cold shutdown condition because of inability to meet technical specification requirements may be classified as an Unusual Event by the Emergency Plan, and began checking the appropriate references in the plan and the implementing procedures.
He also called the Operations Manager to discuss the situation.
By coincidence the Operations Manager was also assigned as Duty Station Emergency Director (a position which is assigned on a weekly rotation basis to senior staff members).
The Operations Manager disagreed with the classification of the forced cooldown as an unusual Event, and the two continued their review of the procedures.
At 3:15 p.m., the test engineer was able to close the outer equalizing valve on the outer door a few more degrees with a wrench.
A test rig was connected to determine if the valve had sealed.
The leak test was satisfactory and the 6
HandwheelN I
i Shaft Conected to pDisengaged Equalizing Valve Link I
on Opposite Side of Door O
Linkage (3 -
(,
O Equalizing O
Valve i
NLink Shortened T
as Corrective NQ Action i
LJ Figure 2. Equalizing Valve and Handwheel 7
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Control Room was notified that the integrity of one of the two air lock doors had been restored, and the cooldown was terminated.
The licensee experienced further difficulty regarding the Unusual Event classi-fication.
At 3:30 p.m., the Shift Superintendent classified the forced cooldown as an Unusual Event, and immediately declassified it, since the condition no longer existed.
The Shift Superintendent began to make notifications in accor-dance with Emergency Plan implementing procedure ER 1.0, which requires notify-ing both New Hampshire and Massachusetts of an Unusual Event classification within 15 minutes.
The Operations Manager instructed the Shif t Superintendent to go ahead with the call to New Hampshire, but to wait until he verified that Massachusetts should be called before calling them.
The Shift Superintendent notified New Hampshire via the State hotline.
This necessitated dialing the number for New Hampshire alone, as the normal procedure requires dialing one number which connects to both Massachusetts and New Hampshire State Police.
At 3:48 p.m., the licensee reported the declaration of the Unusual Event to the NRC Headquarters Operations Officer via the Emergency Notification System.
The Operations Manager then informed the Shift Superintendent to also call Massa-chusetts. The Shift Superintendent attempted to call Massachusetts via the State hotline, but an incoming call from New Hampshire requesting additional information on the hotline prevented him from making the call to Massachusetts.
After providing additional information to New Hampshire, and making another failed attempt to call Massachusetts on the State hotline, the notification to the Massachusetts State Police was made via backup commercial telephone, in accordance with the reporting procedure.
Repair of the inner door mechanical inkage was performed at about 5:30 p.m.
l and the inner door equalizing valves were successfully tested and verified closed.
In accordance with Technical Specification Surveillance 4.6.1.3.b, an overall air lock leakage test was subsequently performed.
Short term corrective actions have been initiated to increase the reliability of the linkage connections until a permanent design modification can be imple-mented.
The short term corrective actions include replacing one of the links on each door (see Figure 2) with a shorter link.
The shortened link will assure proper equalizing valve closure.
In addition to shortening the link, the stacking arrangement on the connecting pins for the linkage assemblies was reversed to assist the pin retaining ring in keeping the linkage intact.
Long term corrective actions have been initiated to develop a permanent design change to prevent a recurrence of this event.
Although in this particular event no real threat to the health and safety of the public existed, several generic weaknesses in the licensee's procedures and training, particularly in the areas of classification and notification, were identified.
These areas will require review and corrective action by the licensee:
(1) Failure to report the declaration of an Unusual Event to the Commonwealth of Massachusetts within 15 minutes is contrary to the requirements of procedure ER 1.0, " Classification and Notification of Events at Zero Power."
(2) The discussion between the Operations Manager and Shift Superintendent unnecessarily delayed the classification and reporting of the event.
If 8
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the Shift Superintendent had not delayed the classification by consulting with the Operations Manager / Duty Station Emergency Director, apparen',1y both New Hampshire and Massachusetts would have been notified within the allowed 15 minutes.
The relationship between the Shift Superintendent and Operations Manager (or other Duty Station Emergency Director) during emergency classification and notification, needs to be clarified and stressed in training.
(3) Based on the noted disagreement between the Shift Superintendent and the Operations Manager, additional training may be necessary to clarify what events are classified as Unusual Events.
(4) The procedure for reporting events which have been classified under the Emergency Plan, but have cleared before reporting is possible, needs to be further evaluated to determine if present guidance for operators is sufficient.
(5) The acceptability of using the State notification hotline by the States for calling in for additional information needs to be evaluated.
(6) The lack of sensitivity of the test engineering staff, in failing to promptly inform the operations crew of the loss of containment integrity, needs to be evaluated and corrected.
(7) The generic implications of the common-mode failure of the equalizing valve linkage on both the inner and outer emergency personnel air lock doors needs to be evaluated, and necessary reports completed if appropriate.
(Refs. 4 and 5.)
1.3 Defective Steam Generator Tubes Not Repaired Prior to Startup Due to Incorrect Final Review Decision at Millstone Unit 2 while Millstone Unit 2* was operating at 100% power, a On January 29, 1987 5 reanalysis of steam generator (SG) tube examination data, originally collected in October and November 1986, identified that one tube which had contained a repairable defect had r.ot been repaired, as required by technical specifications, prior to declaring the (SG) operable.
A plant shutdown was initiated and the plant brought to cold shutdown approximately 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> later.
Continuing reanalysis of 1986 eddy current data identified 3'7 other tubes which also con-tained repairable defects which had not been repaired.
These conditions occurred because of (1) errors in judgment of a properly qualified and certified Level III (Senior) Nondestructive Examiner, and (2) failure of other Level II Non-destructive Examiners to follow the prescribed techniques for identifying the extent of eddy current examination.
The event is detailed below.
On January 29, 1987, a reanalysis of SG eddy current examination data collected in October and November of 1986 was performed because the licensee was experi-encing a primary-to-secondary leak rate of about 0.15 gpm.
The reanalysis showed that the tube at Line 136, Row 42 in the No. 1 SG contained a repairable defect
- Millstone Unit 2 is an 857 MWe (net maximum dependable capacity) Combustion Engineering PWR located 5 miles southwest of New London, Connecticut, and is operated by Northeast Nuclear Energy.
9 j
2.9 inches above the secondary face of the cold leg tubesheet.
This defect had not been identified during the 1986 examination and thus had not been repaired.
At 5:15 p.m., plant shutdown from 100% power was started as required by Technical Specification 3.0.3, and the plant was brought to cold shutdown at 6:24 p.n..
on January 30, 1987.
On January 31, a second unrepaired defect was identified.
This defect was located 0.2 inches above the secondary face of the hot leg tubesheet in SG No.2, at Line 48, Row 94.
Licensee investigation into the cause of the event identified two separate and unrelated causes for this failure to accomplish all required repairs:
(1) The defect in SG No.1 had not been repaired because a Level III Nondestruc-tive Examiner had improperly determined, on final review, that the eddy cur-rent signals were indicative of external tube deposits rather than a defect.
Two independent Level II Data Analysts had previously indicated that the tube contained a through-wall defect.
(2) The defect in SG No. 2 had not been repaired because incorrect recording of the extent of the original test resulted in a portion of the tube not being analyzed during the examination.
Specifically, the original analyst had indicated that the tube had been examined and analyzed up to but not through the first egg crate support.
In order to comply with contract requirements the tube was retested and analyzed in the area of the first egg crate support.
Since the retest data in the area of the top tubesheet was believed to be redundant, the available data was not analyzed.
Reanalysis of eddy current data for all other instances where the reviewer in question had reversed the evaluation of other analysts revealed that in 36 of 260 instances this reversal was inappropriate. To assure that other reviewers had not made similar errors, a sample (approximately 39%), of other reviewers' work was also analyzed.
In every case the final reviewers' decision was con-sidered appropriate.
To assure that all tubes were analyzed over their full required length, every tube that was not fully analyzed during the original test because of tube restrictions to the passage of the eddy current probe was reviewed to assure that all areas of the tube were analyzed.
Four additional tubes were identified that had not been completely analyzed.
None of these contained defects.
Additionally, the hydrostatic testing of SG No. 1 during the unit shutdown identified a leaking tube at Line 25, Row 19.
Eddy current examination found a large volume indication at the top of the tubesheet, circumferentially oriented and extending about 225 around the tube.
A through-wall opening was approxi-mately 40 of this circumference, with an estimated 0.052-inch opening.
Further licensee review found that the 1985 and 1986 outage eddy current examination program identified a 31% through-wall degradation of this tube.
Stress corro-sion has been identified as the most likely cause of this failure.
Licensee structural analysis identified that this tube is in a high stress area, and near a tie rod support.
This tube was plugged, and the five adjacent tubes were staked and plugged to prevent multi-tube failure from fretting and wear.
As corrective action for the previously noted tube leak problems, all tubes which contained defects were repaired by plugging.
Other tubes were also plugged to 10
1 reduce SG primary-to-secondary leakage and to minimize the probability of future leakage. A total of 81 tubes were plugged.
The procedures and specifications for conducting the SG eddy current examinations will be reviewed to assureThis adequate controls are implemented to prevent recurrence of these errors.
review will be complete prior to the next regularly scheduled inservice inspection.
(Ref. 6-9.)
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1.4 References (1.1)
- 1. Virginia Power, Docket 50-281, Licensee Event Report 86-20-02, March 31, 1987.
- 2. NRC, Information Notice 86-106, "Feedwater Line Break," December 16, 1986; Supplement 1, February 13, 1987; and Supplement 2, March 18, 1987.
- 3. NRC, " Augmented Inspection Team Report on Feedwater Pipe Rupture Event on December 8, 1986 at Surry Unit 2," February 10, 1987.
(1.2)
- 4. NRC, Region I Inspection Report 50-443/87-08, March 10, 1987.
- 5. Public Service of New Hampshire, Docket 50-443, Licensee Event Report 87-04, March 13, 1987.
(1.3)
- 6. Northeast Nuclear Energy, Docket 50-336, Licensee Event Report 87-03, February 26, 1987.
- 7. NRC, Region I Inspection Report 50-336/87-01, February 27, 1987.
- 8. NRC, Region I Inspection Report 50-336/87-04, March 9, 1987.
Summary of Meeting Held with Northeast Nuclear Energy Company (NNECo) Concern-ing Millstone Unit 2 Steam Generator leakage, March 18 1987.
1 i
These referenced documents are available in the NRC Public Document Room at 1717 H Street, N.W., Washington, DC 20555, for inspection and/or copying for a fee.
(AEOD reports also may be obtained by contacting AE0D directly at 301-492-4484 or by letter to USNRC, AEOD, EWS-263, Washington, DC 20555.)
12 l
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 feed-back 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 301-492-4493, or at U.S. Nuclear Regulatory Com'ission, EWS-263A, Washington, DC 20555.
Excerpt Page 2.1 Unit Trip and Safety Injection Actuation Caused by Loss of Instrument Bus at Indian Point Unit 3.......................
13 2.2 Inoperability of the Auxiliary Feedwater System Due to Problems with Static-0-Ring Pressure Switches at Davis-Besse Unit 1...
15 2.3 Reactor Trip Due to High Steam Generator Water Level Caused by Calibration Drift of Current to Pressure Converter at Diablo Canyon Unit 1.......................................
16 2.4 Fire Caused by Oil Leak from Diesel Engine Oil Injection Line at Palo Verde Unit 2........................................
18 a
2.1 Unit Trip and Safety Injection Actuation Caused by Loss of Instrument Bus Indian Point Unit 3; Docket 50-286; LER 87-02; Westinghouse PWR At 8:28 a.m. on February 11, 1987, the output breaker on the No. 34 static in-verter opened automatically in response to an overcurrent condition.
When the breaker opened, all power was lost to the No. 34 instrument bus (IB), which provides power to various control circuits in the plant.
A runback of both main boiler feedwater pumps (MBFPs) occurred when the No. 34 IB was deenergized since the MBFP speed controls are powered from this bus.
The decrease in feed-water system flow caused by the MBFP runback ultimately resulted in an auto-matic reactor trip on steam flow /feedwater flow mismatch coincident with low steam generator (SG) level.
The trip occurred with the unit at 100% power.
A main turbine generator trip was initiated automatically upon receipt of the re-actor trip signal.
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Immediately following the reactor trip, a high steam flow safety injection (SI) actuation occurred due to high steam flow signal
- coincident with the low steam line pressure logic being made up for two steam generators.
All equip-ment associated with the SI signal operated properly.
The SI was a result of the low steam line pressure matrix being completed by the loss of the No. 34 IB concurrently with the high steam flow matrix being completed during the trip.
Since the reactor coolant system (RCS) was at normal operating pres-sure, no water was injected as a result of the SI actuation.
During or immediately after the reactor trip /SI actuation, the voltage on the No. 33 IB began to fluctuate and a safety valve on the No. 32 SG (MS-46-2) lifted.
This safety valve did not fully reseat and was closed locally by plant operators.
Also, the circulating water pumps (CWPs), which tripped during the SI actuation, could not be remotely restarted.
This resulted in an overpressure condition in the main condensers as air, in contact with hot condenser inter-nals, heated up.
The resulting pressure buildup was relieved through the main turbine rupture disks.
s Approximately 5 minutes after the reactor trip, during investigation of the voltage fluctuation on the No. 33 IB, it was determined that an overcurrent condition was beginning to develop on the No. 33 static inverter (codes X,EE,INVT,W120-Westinghouse No. 125CT).
In order to protect the integrity of the inverter, it was deenergized at the direction of the shift supervisor.
As expected, this action initiated a second SI signal because two instrument buses (Nos. 34 and 33) were now deenergized.
Since the initial high steam flow SI signal had not yet been reset, the second SI did not affect the opera-tion of plant equipment.
During subsequent post-trip load testing of the No.
33 static inverter, three component parts were found to have failed:
a trans-former, a pre-charge resistor, and a silicon controlled rectifier.
The partial opening of main steam safety valve MS-46-2 was found to have been caused by the rapid steam pressure increase which occurred when the main steam isolation valves closed in response to the high steam flow SI signal.
The cause of this valve to not fully reseat was traced to a broken retaining pin (codes X,SB,2999,Z999) associated with the valve spindle lift nut.
This re-taining pin was replaced, the opening setpoint was verified and all other main steam safety valves were inspected.
The nonessential service water pumps, which were supplying seal water to the CWPs were automatically deenergized when the SI actuation occurred.
The CWPs tripped automatically upon loss of seal water.
The control room operators were unable to immediately restart the CWPs because the loss of seal water pump trip must be reset locally at the CWP control building.
The unavail-ability of these pumps caused the pressure and temperature of non-condeisible gases within the condensers to increase.
An overpressure condition sose-quently developed within the main condensers, which was relieved threJgh main j
turbine rupture disks.
- The high steam flow signal is expected to occur after a turbine trip.
The signal occurs because turbine impulse pressure drops rapidly, causing an equally rapid decrease in the high steam flow setpoint.
The decreasing setpoint overtakes the slower decrease in steam flow, causing the signal to occur.
14
Investigation into the cause of the automatic opening of the output breaker on the No. 34 static inverter revealed that the breaker opened due to an over-current condition.
The coil for solenoid valve 50V-1197 (codes X,BD,PSV, A610.-
Asco No. X8308-100), on the weld channel pressurization system was found to be shorted to ground.
This short circuit caused the No. 34 static inverter to exceed its instantaneous 90-amp breaker trip setpoint.
The shorted solenoid valve coil was replaced with a coil of a higher temperature design.
In addition, three identical solenoid valve coils in the system were similarly rep' aced as a precautionary measure.
Inspection of other solenoid valve coils revealed no abnormalities.
Since the inverter breaker trip device provides instantaneous overcurrent protection, the individual branch circuit protection devices, which provide time delayed overcurrent protection, had insufficient time to actuate.
To prevent recurrence, the design of the No. 34 static inverter was improved by removing the instantaneous output breaker trip.
This change will not alter the thermal overload protection but will allow the individual branch circuit breakers sufficient time to isolate specific areas without affecting operation of the entire inverter.
2.2 Inoperability of the Auxiliary Feedwater System Due to Problems with Static-0-Ring Pressure Switches i
Davis-Besse Unit 1; Docket 50-346; LER 87-04; Babcock & Wilcox PWR Recent problems experienced during monthly technical specification testing of the Static-0-Ring pressure switches (PSL 106A, B, C and D) installed on auxiliary feedwater (AFW) Train 1, resulted in declaring the train inoperable.
During testing of these switches, it was discovered that they had not held their calibrated setpoints.
The switches were calibrated and exercised three separate times, but each time the setpoint would drift lower.
As a result, a concern was raised as to the operability of identical model switches (PSL 107A, B, C and D) installed on AFW Train 2.
Due to the failure mechanism oc-curring in a short timeframe, management decided to test AFW Train 2 com-ponents before Train 1 was repaired.
The performance of Surveillance Test, ST 5071.23, " Auxiliary Feedwater Train 1-2 Auto Essential Level Control System, Suction Pressure Interlocks, Turbine Inlet Pressure Interlock and Flow Transmitter Test," Section 5.4 resulted in an intentional entry into Technical Specification 3.0.3 with both AFW trains temporarily inoperable.
As a result, an unusual event was declared as defined by the Davis-Besse Emergency Preparedness Plan.
At the time the unusual event was declared, the unit was in power operation, with the reactor at 51% power and the reactor coolant system at 2155 psig and 582 degrees.
No engineered safety features were challenged.
Completion of ST 5071.23 Section 5.4 verified that the pressure switches on AFW Train 2 would perform their functions.
The unusual event was terminated 30 minutes after it was declared with AFW Train 2 being declared operable and returned to service.
Investigation into the setpoint drift of Static-0-Ring pressure switches (Model 6TA-84-NX-01A-JJTTX6) PSL 106 A through D by licensee and vendor 15
personnel revealed that the failure was caused by the formation of an ammonia gas bubble between the three layers (Kapton-fluorinated silicone-Kapton).
The ammonia gas bubble was formed over a period of time by ammonia gas migration across the first layer of the diaphragm (Kapton) from the process system (main steam).
The root cause of the failure was detertined to be that licensee personnel failed to consider in their design evaluation the effects of the main steam system chemistry on the diaphragm; therefore, the chemical specifications of the system were not provided to the vendor.
q Inadequate review of maintenance history and/or Licensee Event Reports re-sulted in a failure to identify that s4milar problems were encountered in 1979 and 1980.
Three LERs were written on Static-0-Ring pressure switches in 1979 and 1980.
In each case, severe corrosion of the aluminum piston had occurred as a result of fluid permeating the thin Buna N diaphragm, but a single definitive cause was not specified.
Replacement with stainless steel diaphragm pressure switches occurred in all three cases.
For this event, the Model 6TA-B4-NX-CIA-JJTTX6 Static-0-Ring pressure switches on PSL 106/107A through D were replaced by Model 6TA-B4-NX-CIA-JJTTX8.
Model 6TA-84-NX-CIA-JJTTX8 diaphragms are made of stainless steel and are less sus-ceptible to ammonia migration.
The new switches are currently being checked for setpoint drift on an in-creased surveillance frequency.
The switches presently installed have per-formed satisfactorily since mid January 1987.
The increased test frequency will be reduced to the normal technical specification requirement as confi-dence is established in performance of the switches.
All other Static-0-Ring pressure switches within the plant, some of which are safety related, will be reevaluated and verified with the vendor to ensure that the required specification for each Static-0-Ring pressure switch is in accordance with its current application.
This is expected to be completed by April 1, 1987.
A Systems Engineering Group has been established for all systems within the plant.
System engineers are responsible for the review of system operation and testing results, maintaining a working knowledge of maintenance history and reviewing changes to their assigned systems.
Design and procurement pro-cedures have been reviewed with the engineers specifying new equipment to ensure they consider both external and process chemistry in ordering equipment.
l 2.3 Reactor Trip Due to High Steam Generator Water Level Caused by l
Calibration Drift of Current to Pressure Converter Diablo Canyon Unit 1; Docket 50-275; LER 87-02; Westinghouse PWR j
On February 22, 1987, at about 8:40 a.m., with Unit 1 in power operation at 30% power, licensed operators were preparing to return to 100% power following a power reduction.
16 l
While preparing to return to power, licensed plant operators experienced a feed-water flow instability condition that resultad in increasing steam generator water levels.
This condition is not uncommon while operating at low power levels with the feedwater regulating valves being nearly closed.
In an attempt to stabilize the rising steam generator levels, a licensed plant operator placed the main feedwater pump speed control in manual and reduced feed flow.
Addi-tionally, the operator took manual control of three of the feedwater regulating valves to further reduce flow.
At this time it was noted the steam generator 1-1 level was still increasing and attempts to reduce flow by manually closing feedwater regulating valve (FCV-510) were not successful.
As the levels in steam generator 1-1, and now 1-2, continued to rise, the operators attempted to further reduce flow.
This action increased flow to steam generators 1-3 and 1-4 due to the main feedwater pump speed control being in mdnual.
Since the feedwater regulating valve for steam generator 1-3 was left in automatic, it closed further with the increasing steam ganerator level.
The resultant flow to ste."
generator 1-4, with its feedwater regulating valve in manual, caused a rapid rise in its level before the operators could manually close the valve.
At 9:00 a.m., while operators were attempting to reduce feedwater flow to steam generator 1-4 its level continued to increase to the high level (P-14) setpoint, causing the Unit 1 turbine generator to trip with a subsequent reactor trip.
A P-14 high level setpoint in steam generator 1-1 occurred shortly after this.
All safety systems responded as designed, and the unit was stabilized in hot standby.
The immediate cause of this event was the inability of licensed operators to maintain proper steam generator water level.
Root causes included:
(1) A calibration drift of the electrical current to pressure converter (I/P) for steam generator 1-1 feedwater regulating valve (FCV-510), preventing the valve from being fully closed; and (2) The sensitive nature of the steam generator water level control system at lower power levels.
Corrective actions included the following:
(1) The I/P converter to FCV-510 was recalibrates and returned to service; (2) Due to recurring feedwater control problems, an Engineering and Operations Task Force has been formed to investigate steam generator water level con-trol system performance problems; and (3) All control room operators involved in the subsequent startup reviewed the event data prior to startup to increase their awareness of potential feed-water pump speed control problems.
As with other LERs, this LER will be made a part of the licensed operator requalification training program.
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2.4 Fire Caused by Oil Leak From Diesel Engine Oil Injection Line Palo Verde Unit 2; Docket 50-529; RER-QSE 87-11; Combustion Engineering PWR On February 8, 1987 at 8:31 p.m., fire alarms for the Unit 2A diesel generator engine were received in the control room.
Test 73ST-2DG-01 (Integrated Safe-guards Testing) was being performed on the Unit 2A diesel generator.
The con-trol room operators dispatched an Auxiliary Operator to investigate the cause of the alarms.
The Auxiliary Operator reported an engine fire near the 4R and SR cylinders.
The Unit 2A diesel engine was tripped and the Fire Protection Department was notified.
The fire was extinguished at about 8:52 p.m. by manual hosing down with water.
The Shift Supervisor immediately secured the area for safety considerations and root cause analysis.
Investigations to determine the extent of obvious damage and possible root causes were conducted on February 9.
The following observations were made:
(1) The 3R, 4R, SR, and 6R valve covers sustained various degrees of fire damage.
The 4R alumintm alloy valve cover showed the most damage and portions were melted away.
Valve cover SR was melted to a lesser degree than 4R.
Valve covers 3R and 6R were charred but no permanent damage was noted.
(2) The exhaust manifold showed charring at the 3R, 4R, SR, and 6R areas.
(3) The lube oil header box showed charring and some deformation at the 4R, SR, and 6R areas.
(4) Jun~ 4on Box No. 3 for pneumatic trips was charred and some instrument roc valve handles were burned.
(5) The 3R, 4R, and SR fuel injection pumps showed varying amounts of fire damage.
(6) The 4R and SR fuel injectors showed fire damage.
(7) The crankcase, crankshaft inspection ports, instrument tubing, jacket water header, and explosion doors showed evidence of sooting and charring.
l (8) The SR fuel injection tube was found disengaged from the connector at the fuel injector.
The ferrule was still in the injector, i
The fire was determined to be caused by the disengaged fuel injection tube at I
the SR injector.
This fuel injection tube assembly was purchased from Cooper Energy Services as a replacement part and was recently installed.
After the tube became tilsengaged from the injector fitting, pulsating fuel sprayed onto the 4R and SR valve covers and other nearby engine components.
The fuel even-tually contacted the exhaust manifold and combustion occurred.
Diesel fuel from the SR injector pump continued to feed the fire until the engine was stopped.
This fire is considered by the licensee and the vendor, Cooper Energy Services (C.E.S), to be an external engine fire with external engine damage 18
1 i
During the investigation, the licensee determined that the nuts supplied with all the fuel tube assemblies (original equipment and replacements) were not manufactured to SAE J521b specifications.
The nuts supplied to the licensee do not have the proper 45-degree chamfer as specified in SAE J521b.
Although not the root cause of the Unit 2 diesel engine failure, the ferrule manufac-turer (Weatherhead, DANA Corporation) states that the 45-degree chamfer is required for a reliable assembly.
The root cause for the fuel injection tube disengagement has been determined to he incorrect implementation of established manufacturing procedures for fuel injection tuber at the vendor's facility.
The fuel injection tube assembly consists of a piece of 1/2-inch 0 D. steel tubing with a 3/16-inch wall thickness, two flareless tube ferrules, and two tube nuts.
The licensee purchased the replacement assemblies with the ferrules set on the tube by C.E.S.
C.E.S. has determined that one of its employees has not been following the pro-cedure that C.E.S. established for setting the ferrules.
The " technique" that the employee used to set the ferrules resulted in fuel tube assemblies that had inferior pull off strength compared to assemblies set by C.E.S. procedure.
C.E.S. states that the employee has been fabricating replacement fuel injec-tion tubing assemblies and was not involved in the fabrication of the lines originally supplied.
f The fire-damaged components from the Unit 2A diesel have been repaired or L
replaced as required.
After the engine was repaired, it was restarted and has l
successfully completed 73ST-2DG01 (Integrated Safeguards Test).
The suspect fuel injection tube assemblies in all three units are being replaced as described.
Also, the suspect spare assembles from the licensee parts ware-house will be reworked to ensure proper ferrule engagement on the tube prior to release from the warehouse.
The licensee has also decided to repair the diesel engine tubing nuts to ensure conformance with the SAE chamfer requirement.
The repair of the nuts will be completed prior to hot shutdown entry in each unit.
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o 3.0 ABSTRACTS / LISTINGS OF OTHER NRC OPERATING EXPERIENCE DOCUMENTS 3.1 Abnormal Occurrence Reports (NUREG-0090) Issued in January-February 1987 i
An abnormal occurrence is defined in Section 208 of the Energy Reorganization Act of 1974 ar an unscheduled incident or event which the NRC determines is l
significant from the standpoint of public health or safety.
Under the provisions l
of Section 208, the Office for Analysis and Evaluation of Operational Data reports I
abnormal occurrences to the public by publishing notices in the Federal Register, and issues quarterly reports of these occurrences to Congress in the NUREG-0090 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.
Date Issued Report 1/87 REPORT TO CONGRESS ON ABNORMAL OCCURRENCES, APRIL-JUNE I
1986, VOL. 9, NO. 2 There were nine abnormal occurrences during the period.
Two occurred at NRC-licensed nuclear power plants, five occurred at other NRC licensees (industrial radiographer, medical institu-tions, industrial users, etc.), and two occurred at Agreement State licensees.
The occurrences at the plants involved:
(1) an out of sequence control rod withdrawal at Peach Bottom Unit 3, and (2) a boiling water reactor emergency core cooling system design deficiency discovered at Pilgrim.
The occurrences at other licensees involved:
(1) willful fail-ure to report a diagnostic medical misadministration at Mercy Hospital, Wilkes-Barre, Pennsylvania; (2) therapeutic medical misadministration at Maryview Hospital, Portsmouth, Virginia; (3) willful failure to report diagnostic medical misadministra-tions at Bloomington Hospital, Bloomington, Indiana; (4) diag-nostic medical misadministration at the Robert Packer Hospital and Guthrie Clinic, Sayre, Pennsylvania; and (5) diagnostic medical misadministration at the Tripler Army Medical Center, Tripler AMC, Hawaii.
The occurrences at the Agreement State licensees included:
(1) uncontrolled release of krypton-85 to an unrestricted area at Micro-Rei Division, Medtronic, Inc., Tempe, Arizona; and (2) contaminated radiopharma autical used in diagnostic administra-tions at Scripps Memorial Hospital, Encinitas, California.
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I Date Issued Report Also, the report updated information from nuclear power plants on:
(1) the nuclear accident at Three Mile Island (79-3), first reported in Vol. 2, No.1, January-March 1979; (2) decay heat removal problems (80-5), first reported in Vol. 3, No. 2, April-June 1980; (3) premature criticality during startup (85-1),
first reported in Vol. 8, No.1, January-March 1985; (4) loss of main and auxiliary feedwater systems (85-7), first reported in Vol. 8, No. 2, April-June 1985; (5) management deficiencies at Tennessee Valley Authority (85-14), first reported in Vol. 8, No. 3, July-September 1985; (6) management deficiencies at Fermi Nuclear Power Station (85-20), reported in Vol. 8, No. 4, October-December 1985; (7) loss of power and water hammer event (86-1), first reported in Vol. 9, No.1, January-March 1986; and (8) loss of integrated control system power and overcooling transient (86-2), first reported in Vol. 9, No. 1, January-March 1986.
Updated information for fuel cycle facilities and other NRC licensees included:
(1) rupture of uranium hexafluoride cylinder and release of gases (86-3), first reported in Vol. 9, No. 1, January-March 1986; and (2) contaminated radiopharmaceu-ticals used in diagnostic administrations (84-13), first re-ported in Vol. 7, No. 3, July-September 1984.
j In addition, items of interest that did not meet abnormal occurrence criteria but may b.e considered significant by the public involved:
(1) reactor vessel indications at Oconee Unit 1, (2) NRC Augmented Inspection Team sent to Pilgrim, (3) con-struction problems at Comanche Peak, (4) sabotage of offsite l
power lines to Palo Verde, (5) NRC Augmented Inspection Team sent to Palisades, (6) fire in charcoal filter tanks at Perry Unit 1, and G) water level instrumentation problem at Lacrosse.
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3.2 Bulletins and Information Notices Issued in January-February 1982 The Office of Inspection and Enforcement
- periodically issues bulletins and-information notices to licensees and holders of construction permits.
During.
the period, 13'information notices and one information notice supplement were issued.
Bulletins are used primarily to communicate with the industry on matters of generic importance or serious safety significance (i.e., if an event at one reactor raises the possibility of a serious generic problem, an NRC bulletin nay be issued _ requesting licensees to take specific actions, and requiring them to submit a written report describing actions taken and other information NRC should have to assess the.need for further actions).. A prompt response by affected licensees is required, and failure to respond appropriately may result in an enforcement action.
When appropriate, prior to issuing a bulletin, the NRC may seek comments on the matter from the industry (Atomic Industrial Forum, Institute of Nuclear Power Operations, nuclear steam suppliers, vendors, etc.),
a technique which has proven effective in bringing faster and better responses from> licensees.
Bulletins generally require one-time action and reporting.
They are'not intended as substitutes for revised license conditions or new requirements.
Information Notices are rapid transmittals of information which may not have been completely analyzed by the 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.
Information Date l
Notice Issued Subject 86-106 2/13/87 FEEDWATER LINE BREAK (Issued to all power Sup. I reactor facilities holding an operating license or construction permit) 87-01 1/6/87
' RESIDUAL HEAT REMOVAL VALVE MISALIGNMENT CAUSES DEGRADATION OF EMERGENCY CORE COOLING SYSTEM IN PWRs (Issued to all PWR facilities holding an operating license or construction permit) 87-02 1/15/87 INADEQUATE SEISMIC QUALIFICATION OF DIAPHRAGM VALVES 1
BY MATHEMATICAL MODELING AND ANALYSIS (Issued to all j
power reactor facilities holding an operating license or construction permit) 87-03 1/15/87 SEGREGATION OF HAZARDOUS AND LOW-LEVEL RADI0 ACTIVE WASTE (Issued to all NRC licenseed)
- Following a major NRC reorganization in April 1987, this office is no longer in existence.
Bulletins and information notices continue to be produced by the Office of Nuclear Reactor Regulation.
1 23
Information Date Notice Issued Subject 87-04 1/16/87 DIESEL GENERATOR FAILS TEST BECAUSE OF DEGRADED FUEL (Issued to all power reactor facilities helding an operating license or construction permit) 87-05 2/2/87 MISWIRING IN A WESTINGHOUSE R0D CONTROL SYSTEM (Issued to all Westinghouse power reactor facilities holding an operating license or construction permit) 87-06 1/30/87 LOSS OF SUCTION TO LOW-PRESSURE SERVICE WATER SYSTEM PUMPS RESULTING FROM LOSS OF SIPHON (Issued to all power reactor facilities holding an operating license or construction permit) 87-07 2/3/87 QUALITY CONTROL OF ONSITE DEWATERING / SOLIDIFICATION OPERATIONS BY OUTSIDE CONTRACTORS (Issued to all power reactor facilities holding an operating license or construction permit) 87-08 2/4/87 DEGRADED MOTOR LEADS IN LIMITORQUE CD MOTOR OPERATORS (Issued to all power reactor facilities holding an operating license or construction permit) 87-09 2/5/87 EMERGENCY DIESEL GENERATOR ROOM COOLING DESIGN DEFICIENCY (Issued to all power reactor facilities holding an operating license or construction permit) 87-10 2/11/87 POTENTIAL FOR WATER HAMMER DURING RESTART OF RESIDUAL HEAT REMOVAL PUMPS (Issued to all BWR facilities holding an operating license or construction permit) 87-11 2/13/87 ENCLOSURE OF VITAL EQUIPMENT WITHIN DESIGNATED VITAL AREAS (Issued to all power reactor facilities holding an operating license or construction permit) 87-12 2/13/87 POTENTIAL PROBLEMS WITH METAL CLAD CIRCUIT BREAKERS, GENERAL ELECTRIC TYPE AKF-2-25 (Issued to all power reactor facilities holding an operating license or construction permit) 87-13 2/24/87 POTENTIAL FOR HIGH RADIATION FIELDS FOLLOWING LOSS OF WATER FROM FUEL POOL (Issued to all power reactor facilities holding an operating license or construc-tion permit except Fort St. Vrain) i 24
l J
3.3 Case Studies and Engineering Evaluations Issued in January-February 1987 l
The Office for A1alysis and Evaluation of Operational Data (AE0D) has as a primary 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 safety interest for further review as either an engineering evaluation or a case study.
An engineering evaluation is usually an immediate, general assessment to determine wnether or not a more detailed protracted case study is needed.
The results are generally short reports, and the effort involved usually is a few staff weeks of investigative time.
Case studies are in-depth investigations of apparently significant events or situations.
They involve several staff months 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 requirements of the responsible NRC program office.
Engineering Date Evaluation Issued Subject N701 1/14/87 DIAGNOSTIC MISADMINISTRATION INVOLVING THE ADMIN-ISTRATION OF MILLICURIE AMOUNTS OF 100INE-131 This report documents a review and evaluation of 14 diagnostic misadministration, each of which involved the administration of a 1-10 millicurie dosage of iodir.e-131 to a patient, where the prescribed radio-pharmaceutical was either iodine-131 (6-300 micro-curies), iodine-123 (150-400 microcuries), technetium-99m (0.1-10 millicuries), or technetium-99m methylene-diphosphonate (20 millicuries).
These misadministration were rcported to NRC between January 1982 and June 1986.
From our evaluation of these events, we found that while 10 of the 14 misadministration occurred as a result of either the referring physician's orders being misinterpreted by or miscommunicated to the technolo-gist, or the technologist not knowing the correct dosage to administer for the prescribed thyroid scan, the underlying cause of 11 of the 14 (79%) misadmin-istrations was that licensees did not exercise adequate control over the administration of millicurie amounts of iodine-131 to patients.
That is, most of the mis-administrations could have been prevented, despite the 25
l Engineering Date Evaluation Issued Subject N701 (Cont'd) errors of misinterpretation or miscommunication, if the prescription for the iodine-131 dosage had been verified before the iodine-131 was administered to the patient.
The overall data highlight the need for better quality assurance practices to ensure the accuracy of radio-pharmaceutical dosages of iodine-131 that, although administered for diagnostic purposes, fall in the dosage range normally used for therapy.
A case study issued by AE00 in December 1985, AE00/
C505, " Therapy Misadministration Reported to the NRC Pursuant to 10 CFR 35.42," documented an analysis of 16 teletherapy and two brachytherapy misadministra-tions.
A significant finding of the case study was that, although professional medicel groups involved with radiotherapy and related government agencies encourage quality assurance programs in radiotherapy facilities, no government agency or nongovernmental accrediting body requires that radiotherapy facilities have quality assurance programs that conform to the programs recommended by professional medical groups.
Thus, many facilities may not have quality assurance programs that are consistent with recommendations of medical professional groups involved with radiation therapy. This finding likely applies equally to NRC licensed facilities which may adminster millicurie amounts of iodine-131 for diagnostic and therapeutic purposes.
Following completion of this engineering evaluation study, AE00 received three additional reports of diagnostic misadministration involving the adminis-tration of millicurie amounts of iodine-131 to patients.
The cause of these misadministration was the misin-terpretation by or miscommunication to the technologist of the referring physician's order.
These events fur-ther support the evaluation's findings, conclusions, and suggestions that:
(1) The Office of Inspection and Enforcement send an update to Information Notice IN-85-61, "Misadminis-trations to Patients Undergoing Thyroid Scans,"
to the affected licensees informing them of the more recent misadministration events involving iodine-131.
26
Engineering Date Evaluation Issued Subject N701 (Cont'd)
(2) The Office of Nuclear Material Safety and Safe-guards assess proposed regulatory changes to 10 CFR 35 to determine whether the requirements for quality assurance procedures for radiotherapy facilities should be expanded to include a require-ment for quality assurance procedures for the administration of radiopharmaceuticals for therapy, or for diagnosis in which the dosage of the radiopharmaceutical administered is in the therapy dosage range for the radiopharmaceutical.
E701 1/21/87 POTENTIAL CONTAINMENT AIRLOCK WINDOW FAILURE DUE TO RADIATION On April 16, 1986, the licensee for the D.C. Cook plant notified the NRC that vendor-supplied informa-tion on testing of windows for containment airlocks showed that the glass shattered when subjected to a beta dose of 2.5 megarads in 10 seconds.
Each unit contains two airlocks and each airlock has an inner and outer window.
Because of the uncertainty asso-ciated with the applicability of the test results to D.C. Cook, the licensee decided to install 3/8-inch thick cover plates over the inner windows in both units to eliminate the potential beta radiation of windows.
The potential safety significance of the failure of the windows is the loss of containment isolation (6-inch hole) following a design basis accident.
Such a loss would.esult in increased offsite doses which directly aff ict the public, or would result in an adverse impact on plant accident recovery and mitigation activities.
Because the precise failure mechanism remains unknown, there is uncertainty that the window would function adequately at the less severe beta dose rates anticipated for design basis accidents.
Therefore, this evaluation suggests that the Office of Nuclear Reactor Regulation rereview the acceptability of airlock windows with respect to design basis accidents.
This investigation also noted that there is information that may indicate potential reduction of the fracture strength of the windows at high integrated gamma doses.
Although the reduction does not affect containment integrity in the vicinity of design pressures, it may have implications for severe accident scenarios which produce containment pressures significantly higher than the design pressures.
Therefore, it is suggested that airlock windows be reviewed as part of the Severe Ac-cident Program.
(Eliminating the window has not been 27
Engineering Date Evaluation Issued Subject E701 (Cont'd) suggested since there may be other data sources avail-able to assuage the uncertainty associated with this issue.)
i I
i l
l
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28
l 3.4 Generic Letters Issued in January-February 1987 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-cants, and/or equipment suppliers regarding matters of safety, safeguards, or environmental significance.
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 re-garding the continued' safe operation of facilities.
They have been a significant means'of communicating with licensees on a number of important issues, the resolutions of which have contributed to improved quality of design and operation.
Generic Date Letter Issued Title 87-01 1/8/87 PUBLIC AVAILABILITY OF THE NRC OPERATOR LICENSING EXAMINATION QUESTION BANK (Issued to all power reactor licensees and applicants for an operating license) 87-02 2/19/87 VERIFICATION OF SEISMIC ADEQUACY OF MECHANICAL AND ELECTRICAL EQUIPMENT IN OPERATING REACTORS llSI A-46) (Issued to all holders of operating licenses not reviewed to current licensing cri-teria on seismic qualification of equipment)
L 87-03 2/26/87 VERIFICATION OF SEISMIC ADEQUACY OF MECHANICAL AND ELECTRICAL EQUIPMENT IN OPERATING REACTORS (USI A-46) (Issued to all licensees not subject to USI A-46 requirements) i 1
29
- 3. 5 Operating Reactor Event Memoranda Issued in January-February 1987 The Director, Division of Licensing, Office of Nuclear Reactor Regulation (NRR),
disseminates information to the directors of the other divisions and program offices within NRR via the operating reactor event memorandum (OREM) system.
The OREM documents a statement of the problem, background information, the safety significance, and short and long term actions (taken and planned).
Copies of OREMs are also sent to the Offices for Analysis and Evaluation of Operational Data, and of Inspection and Enforcement for their information.
No OREMs were issued during January-February 1987.
30
3.6 NRC Documentation Compilations The Office of Administration issues two publications that list documents made publicly availabiv.
The quarterly Regulatory and Technical Reports (NUREG-0304) compiles bibliographic data and abstracts for the formal regulatory and tech-nical 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 gen-erated by the NRC.
This information includes (1) docketed material associated with civilian nuclear power plants and other users of radio-active 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.
5 The monthly License 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 document.
The LER summaries in this report are arranged alphabetically by facility name and then chronologi-cally by event date for each facility.
Component, system, keyword, and compo-nent vendor indexes follow the summaries.
Copies and subscriptions of these three documents are available from the Superintendent of Documents, U.S. Government Printing Office, P.O. Box 37082, Washington, DC 20013-7982.
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