ML20117L285
| ML20117L285 | |
| Person / Time | |
|---|---|
| Issue date: | 04/30/1985 |
| From: | NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| References | |
| NUREG-0090, NUREG-0090-V07-N03, NUREG-90, NUREG-90-V7-N3, NUDOCS 8505160182 | |
| Download: ML20117L285 (70) | |
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Vol. 7, No. 3 Report to Congress on Abnormal Occurrences July - September 1984 U.S. Nuclear Regulatory Commission Office for Analysis and Evaluation of Operational Data pancoq y '; ~) v> (
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l Available from N RC/GPO Sales Program Superintendent of Documerts Government Printial Of fice Washington, D. C. 20402 A ye5r's subscription consists of 4 issues for this publication.
Single copies of this publication are available from National Technical info mation Service, Springfield, VA 22161
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Micro"iche of single copies are l
available from NRC/GPO Sales Program Washington, D. C. 20555 l
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NUREG-0090 Vol. 7, No. 3 Repdrt to Congress on Abnormal Occurrences July - September 1984 Data Published: April 1985 Offica for Analysis and Evaluation of Operational Data U.S. Nuclear Regulatory Commission Wmhington, D.C. 20565 l
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Previous Reports in Series NUREG 75/090, January-June 1975, NUREG-0090, Vol.3, No.1, January-fiarch 1980, published October 1975 published September 1980 NUREG-0090-1, July-September 1975, NUREG-0090, Vol.3, No.2, April-June 1980, published March 1976 published November 1980 NUREG-0090-2, October-December 1975, NUREG-0090, Vol.3, No.3, July-September 1980, published March 1976 published February 1981 NUREG-0090-3, January-March 1976, NUREG-0090, Vol.3, No.4, October-Dect.mber 198 published July 1976 published May 1981 NUREG-0090-4, April-June 1976, NUREG-0090, Vol.4, No.1, January-March 1981, published March 1977 published July 1981 NUREG-0090-5, July-September 1976, NUREG-0090, Vol.4, No.2, April-June 1981, published March 1977 published October 1981 riUREG-0090-6, October-December 1976, NUREG-0090, Vol.4, No.3, July-September 1981, published June 1977 published January 1982 NUREG-0090-7, January-March 1977, NUREG-0090, Vol.4, No.4, October-December 19f published June 1977 published May 1982 NUREG-0090-8, April-June 1977, NUREG-0090, Vol.5, No.1, January-March 1982 published September 1977 published August 1982 NUREG-0090-9, July-September 1977, NUREG-0090, Vol.5, No.2, April-June 1982, published November 1977 published December 1982 NUREG-0090-10, October-December 1977, NUREG-0090, Vol.5, No.3, July-September 1982 published March 1978 published January 1983 NUREG-0090, Vol.1, No.1, January-March 1978, NUREG-0090, Vol.5, No.4, October-December 19 published June 1978 published May 1983 NUREG-0090, Vol.1, No.2, April-June 1978, NUREG-0090, Vol.6, No.1, January-March 1983, published September 1978 published September 1983 NUREG-0090, Vol.1, No.3, July-September 1978, NUREG-0090, Vol.6, No.2, April-June 1983, published December 1978 published November 1983 NUREG-0090, Vol.1,- No.4, October-December 1978, NUREG-0090, Vol.6, No.3, July-September 1983 published March 1979 published April 1984 NUREG-0090, Vol.2, No.1, January-March 1979, NUREG-0090, Vol.6, No.4, October-December 19 published July 1979 published May 1984 i
NUREG-0090, Vol.2, No.2, April-June 1979, NUREG-0090, Vol.7, No.1, January-March 1984, published November 1979 published July 1984 I
NUREG-0090, Vol.2, No.3, July-September 1979, NUREG-0090, Vol.7, No.2, July-September 1984
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published February 1980 published October 1984 NUREG-0090, Vol.2, No.4, October-December 1979, published April 1980
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ABSTRACT Section 208 of the Energy Reorganization Act of 1974 identifies an abnormal occurrence as an unscheduled incident or event which the Nuclear Regulatory Commission determines to be significant from the standpoint of public health or safety and requires a quarterly report of such events to be made to Congress.
This report covers the period from July 1 to September 30, 1984.
The report states that for this report period, there were four abnormal occur-rences at'the nuclear power plants licensed to operate. These involved de-graded isolation valves in emergency core cooling systems, degraded shutdown systems, a loss of offsite and onsite AC electrical power, and a refueling cavity water seal failure, respectively.
There was one abnormal occurrence at a fuel cycle facility; the event involved degraded material access area bar-riers.
There were four abnormal occurrences at the other NRC licensees. One involved contaminated radiopharmaceuticals used in several diagnostic adminis-trations.
Two involved therapeutic medical misadministrations.
The other involved significant internal exposure to iodine-125 to a hospital employee.
There was one abnormal occurrence reported by an Agreement State;.the event involved contaminated radiopharmaceuticals used in several diagnostic adminis-i trations.
The report also con'.ains information updating some previously reported abnor-mal occurrences.
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CONTENTS Page ABSTRACT...............................
iii PREFACE................................
vii INTRODUCTION...........................
vii THE REGULATORY SYSTEM......................
vii
-REPORTABLE OCCURRENCES......................
viii' AGREEMENT STATES.........................
x FOREIGN INFORMATON..
x REPORT TO CONGRESS ON ABNORMAL OCCURRENCES, JULY-SEPTEMBER 1984...
1 NUCLEAR POWER PLANTS.......................
1 84-8 Degraded Isolation Valves in Emergency Core Cooling Systems.................
1 84-9 Degraded Shutdown Systems..............
10 84-10 Loss of Offsite and Onsite AC Electrical Power..
14 84-11 Refueling Cavity' Water Seal Failure.........
20 FUEL CYCLE FACILITIES (Other than Nuclear Power Plants).....
23 84-12 Degraded Material Access Area Barriers........
24 OTHER NRC LICENSEES (Industrial Radiographers, Medical Institutions, Industrial Users, Etc.).............
25 84-13 Contaminated Radiopharmaceuticals Usad in
-Diagnostic Administrations..............
25 84-14 Therapeutic Medical Misadministration........
28 84-15 Significant Internal Exposure to Iodine-125.....
29 84-16 Therapeutic Medical Misadministration........
31 AGREEMENT STATE LICENSEES....................
32 AS84-2 Contaminated Radiopharmaceuticals Used in Diagnostic Administrations.............
32 REFERENCES............
35 APPENDIX A - ABNORMAL OCCURRENCE CRITERIA...............
39 APPENDIX B - UPDATE OF PREVIOUSLY REPORTED ABNORMAL OCCURRENCES....
43 NUCLEAR POWER PLANTS.......................
43 76-11 Steam Generator Problems...............
43 79-3 Nuclear Accident at Three Mile Island........
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i CONTENTS (Continued)
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81-8 Seismic. Design Errors at Diablo Canyon Nuclear Pcwer Plant.
46' 83-15 Emergency Diesel Generator Problems.........
.48 AGREEMENT STATE LICEllSEES....................
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AS83-9 Exposures to Americium-241.............
50 APPENDIX C - OTHER EVENTS OF INTEREST.................
51 REFERENCES (FOR APPENDICES)......................
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PREFACE INTRODUCTION
'The Nuclear Regulatory Commission reports to the Congress each quarter under
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provisions of Section=208 of:the Energy Reorganization Act of 1974 on any abnormalfoccurrences involving facilities and activities regulated by the NRC.
An abnormal' occurrence is defined in Section 208 as an unscheduled incident or event which the Commission determines is significant from the standpoint of public health or safety.
' Events are currently identified as abnormal occurrences for this report.by the NRC using the criteria delineated in Appendix A.
These criteria were promul-gated;in an NRC policy statement which was published in the Federal Register on February 24, 1977.(Vol. 42, No. 37, pages 10950-10952).
In order to provide wide. dissemination of information to the public, a Federal Register notice is issued on each abnormal occurrence with copies distributed to the NRC Public Document Room and all local public document rooms.
At a minimum, each such
-notice contains the date and place of the occurrence and describes-its nature and probable consequences.
The NRC has reviewed Licensee Event Reports, licensing and enforcement actions (e.g., notices of violations, civil penalties, license modifications, etc.),.
generic issues, significant inventory differences involving special nuclear material, and other categories of information available to the NRC.
The NRC
'has determined that only those events, including those submitted by the Agree-ment States, described in this report meet the criteria for abnormal occur-rence reporting.
This report covers the period from July 1 to September 30, 1984.
Information reported on each event includes:
date and place nature and probable consequences; cause or:causes; and actions taken to prevent recur-rence.
.THE REGULATORY SYSTEM
. The system of licensing and regulation by which NRC carries out its responsi-i.
bilities is implemented through rules and regulations in Title 10 of the Code i
.of Federal Regulations.
To accomplish its objectives, NRC regularly conducts licensing proceedings, inspection and enforcement activities, evaluation of
. operating experience and confirmatory research, while maintaining programs for establishing standards and issuing technical reviews and studies.
The NRC's role in regulating represents a complete cycle, with the NRC establishing
. standards and rules; issuing licenses and permits; inspecting for compliance;
. enforcing license requirements; and carrying on continuing evaluations, studies and research projects to improve both the regulatory process and the f
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. protection of the public. health and safety.
Public participation is an ele-ment of the regulatory process.
p In the. licensing and. regulation.of nuclear power plants, the NRC follows the philosophy that the health and safety of the public are best assured through the establishment of multiple levels of protection.
These multiple levels can be achieved and maintained through regulations which specify requirements 2
j which will assure the safe use of nuclear materials.
The regulations include i
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. design and quality assurance criteria appropriate for the various activities licensed by NRC. An inspection and enforcement program helps assure com-pliance with the regulations, j.
Most NRC licensee employees who work with or in the vicinity of radioactive
' materials are required to utilize personnel monitoring devices such as film badges or TLD (thermoluminescent dosimeter) badges.~ These badges are' pro-cessed. periodically and the exposure results normally serve as the official 1
'and legal record of the extent of personnel exposure to radiation during the period.the badge was worn.
If an-individual's past exposure history is known I
and has been sufficiently low, NRC regulations permit an individual in a j.-
restricted area,to receive up to three rems of whole body exposure in'a calendar quarter.
Higher values are perniitted to the extremities or skin of
'the whole body.
For unrestricted areas, permissible levels of radiation are
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considerably smaller.
Permissible doses for restricted areas and unrestricted-areas are stated in 10 CFR Part 20.
In any case, the NRC's policy is to maintain radiation exposures to-levels as low as reasonably achievable.
REPORTABLE OCCURRENCES i
Actual operating experience is an essential input to the regulatory process for assuring.that licensed activities are conducted safely.
Reporting require-ments exist which require;that licensees report certain incidents or events to the NRC..This reporting helps to identify deficiencies early and to assure that corrective actions are taken to prevent recurrence.
For nuclear power plants, dedicated groups have been formed both by the'NRC and by the nuclear-power industry for the detailed review of operating experience to help identify safety concerns early.-to improve dissemination of such information, and to feed back the experience into licensing, regulations, and operations.
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In addition, the NRC and the nuclear power industry have ongoing efforts to improve the operational data system which include not only the type, and-quality, of reports required to be submitted, but also the methods used to analyze.the data.
Two primary sources of operational data are reports sub-mitted by the licensees under the Licensee Event Report (LER) system, and under the Nuclear Plant Reliability Data'(NPRD) system. The former system is under the' control of the NRC while the latter system is a voluntary, industry-supported system operated by the Institute of Nuclear Power Operations (INPO),
a nuclear utility organization.
1 Some form of LER reporting system has been in existence since the first nuclear power plant was licensed.
Reporting requirements were delineated in the Code of Federal Regulations (10 CFR), in the licensee's technical specifi-cations, and/or in license provisions.
In order to more effectively collect, viii
collate, store, retrieve, and evaluate the informaticn concerning reportable events, the Atomic Energy Commission (the predecessor of the NRC) established in 1973 a computer-based data file, with data extracted from licensee reports dating from 1969.
Periodically, changes were made to improve both the effec-tiveness of data processing and the quality of reports required to be sub-mitted by the licensees.
Effective January 1, 1984, major changes were made to the requirements to report to the NRC. A revised Licensee Event Report System (10 CFR S 50.73) was established by Commission rulemaking which modified and codified the former LER system.
The purpose was to standardize the reporting requirements
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for all nuclear power plant licensees and eliminate reporting of events which were of low individual significance, while requiring more thorough documen-tation and analyses by the licensees of any events required to be reported.
All such reports are to be submitted within 30 days of discovery.
The revised system also permits licensees to use the LER procedures for various other reports required under specific sections of 10 CFR Part 20 and Part 50.
The amendment to the Commission's regulations was published in the Federal Register (48 FR 33850) on July 26, 1983, and is described in NUREG-1022, " Licensee Event Report System," and Supplement 1 to NUREG-1022.
Also effective January 1, 1984, the NRC amended its immediate notification requirements of significant events at operating nuclear power reactors (10 CFR S 50.72).
This was published in the Federal Register (48 FR 39039) on August 29, 1983, with corrections (48 FR 40882) published on September 12, 1983.
Among the changes made were the use of termino 16gy, phrasing, and reporting thresholds that are similar to those of 10 CFR S 50.73.
Therefore, most events reported under 10 CFR S 50.72 will also require an in-depth follow-up report under 10 CFR S 50.73.
The NPRD system is a voluntary program for the reporting of reliability data by nuclear power plant licensees.
Both engineering and failure data are to be submitted by licensees for specified plant components and systems.
In the past, industry participation in the NPRD system was limited and, as a result,
-the Commission considered it may be necessary to make participation mandatory in order to make the system a viable tool in analyzing operating experience.
However, on June 8, 1981, INP0 announced that because of its role as an active user of NPRD system data, it would assume responsibility for management and funding of the NPRD system.
INPO reports that significant improvements in licensee participation are being made.
The Commission considers the NPRD system to be a vital adjunct to the LER system for the collection, review, and feedback of operational experience; therefore, the Commission periodically l
monitors the progress made on improving the NPRD system.
Information concerning reportable occurrences at facilities licensed or other-wise regulated by the NRC is routinely disseminated by the NRC to the nuclear industry, the public, and other interested groups as these events occur.
Dissemination includes special notifications to licensees and other affected or interested groups, and public announcements.
In addition, information on reportable events is routinely sent to the NRC's more than 100 local public document rooms throughout the United States and to the NRC Public Document Room in Washington, D.C.
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The Congress is routinely kept informsd of reportable events occurring at licensed facilities.
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AGREEMENT STATES I
I Section 274 of the Atomic Energy Act, as amended, authorizes the Commission to enter into agreements with States whereby the Commission relinquishes and the States assume regulatory authority over byproduct, source and special nuclear materials (in quantities not capable of sustaining a chain reaction).
Comparable and compatible programs are the basis for agreements.
Presently, information on reportable occurrences in Agreement State licensed activities is publicly availaMt: at the State level.
Certain information is also provided to the NRC.under 2xchange of information provisions in the agreements.
NRC prepares a se:niannual summary of this and other information in a document entitled, " Licensing Statistics and Other Data," which is pub-licly available.
In early 1977, the Commission determined that abnormal occurrences happening at facilities of Agreement 5 tate licensees should be included in the quarterly
report to Congress.
The abnormal occurrence criteria included in Appendik A s
is applied uniformly to events at NRC and Agreement State licensee facilities.
Procedures have been developed and implemented and abnormal occurrences re-ported by the Agreement States to the NRC are included in these quarterly reports to Congress.
FOREIGN INFORMATION 4
The NRC participates in an exchange of information with various foreign govern-ments which have nuclear facilities. This foreign information is reviewed and considered in the NRC's assessment of operating experience and in its research and regulatory activities.
Reference to foreign information may occasionally be made in these quarterly abnormal occurrence reports to Congress; however, only domestic abnormal occurrences are reported.
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REPORT TO CONGRESS ON ABNORMAL OCCURRENCE 5 a:
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i NUCLEAR POWER PLANTS i
The NRC is-rev h ing events reported at the nuclear power plants licensed to 2
operate duringsthe third calendar quarter of 1984.
As of the date of this l
~ report, the NRC had determined that the following were abnormal occurrences.
-a 84-8 Degraded Isolation _' Valves in Emergency Core Cooling Systems
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The following information pertaining to this event is also being reported
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concurrently in the Federal Register.
Appendix A (see Example 12 of "For All Licensees") notes that recurring incidents which create major safety concern 9
can be considered an~ abnormal occurrence.
Date and Place - Several events have occurred which involved open valves, includ-3 ing check valves (valves designed to allow water to flow only in one direction),
e located 'in the emergency core cooling systems of various General Electric de-j signed, boiling water reactors.
Some of the events resulted in the high pres-i sure reactor coolant system overpressurizing piping in either the low pressure
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icoolant injection (LPCI) system (the low pressure mode of the residual heat
' removal, RHR, system), the high pressure coolant injection (HPCI) system (the
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low pressure suction portion), or the low pressure core spray system, all systems g
being designed to mitigate the consequences of a loss of coolant accident (LOCA).
g These events are considered to be significant because they substantially reduced g
safety margins for preventing an interface LOCA.
For some reactor designs, the possible interface LOCA could bypass containment, with radioactive material discharged to the environment.
One event resulted in a partial draining of the reactor vessel.
Most of the events were due to personnel errors, and therefore could have been prevented.
The date and place of each of the events are as follows:
Plant Date Licensee Plant Location j
Veemont Yankee 12/12/75 Vermont Yankee Nuclear Power Windham County, V1 Cooper Station 1/21/77 Nebraska Public Power Dist.
Nemaha County, NE LaSalle Unit 1 9/14/83 Commonwealth Edison LaSalle County, IL Pilgrim 9/29/83 Boston Edison Plymouth County, MA Hatch Unit 2 10/28/83 Georgia Power Appling County, GA Browns Ferry 8/14/84 Tennessee Valley Authority Limestone County, AL Unit 1 Nature and Probable Consequences Vermont Yankee
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While performing monthly LPCI pump and motor-operated valve operability sur-veillance testing with the plant operating at 99% power, LPCI injection valve 1
V-10-25A failed to respond to an open signal generated from its remote control switch.
In order to determine if the failure was caused by an excess differ-ential pressure across the valve seat, or a specific mechanical / electrical malfunction, V-10-25A was manually cracked open.
Then the valve was success-fully cycled fully open and closed.
Immediately following the cycling of V-10-25A, a steam water mixture was observed to discharge from three RHR system relief valves and the RHR heat exchanger tube sheet to shell flange area, indicating an overpressurized condition.
Applicable subsystems of the RHR system were declared inoperable.
Redundant systems were proven available.
Following successful pressure and operability testing of the subsystems which had been declared inoperable, the subsystems were declared operable.
Plant operation continued in a degraded mode, as per-mitted by the technical specification limiting conditions for operation, while the event cause was determined, repairs were made, and the subsystems tested.
g As discussed later, the "A" LPCI loop was found to have been momentarily pres-6 surized in excess of system design pressure.
Cooper Station During performance of high pressure coolant injection (HPCI) - turbine trip and initiation logic functional test, with the plant operating at about 97%
power, the HPCI testable check valve failed to seat (i.e., be fully closed) which allowed feedwater to flow backwards through the HPCI injection line into the HPCI suction piping. The isolation valve in series with the check valve was closed and the licensee declared HPCI to be inoperable.
Appropriate surveillance tests were completed.
The HPCI piping was inspected
'and HPCI operated through the test loop.
A technical specification amendment was requested, and approved by the NRC, to extend plant operation with HPCI inoperable for another seven days.
HPCI could be operated in a manual mode, but the extent of flow through the check valve was not known.
The reactor was shut down on February 3, 1977, for evaluation of the problem and corrective actions.
Inspection showed that a broken sample probe was loosely wedged under the edge of the check valve disc, which prevented full check valve closure but had no affect on full opening of the valve. The probe was removed and the check valve inspected, reassembled and satisfactorily tested.
A leak check on the valve was also satisfactorily completed.
HPCI was then returned to an oper-l able status.
l LaSalle Unit 1 The plant was in cold shutdown for an extended maintenance outage.
Plant l
operators were conducting a routine surveillance test of the RHR system relay l
logic.
As part of the test, an RHR system lineup was established for the "B" l
loop which opened both containment spray valves and the suppression pool spray I
valve.
The test procedure then called for opening the "B" loop RHR injection valve, which left only the injection check valve to isolate the RHR system from the reactor cooling system.
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At this point, a rapid decrease in the reactor water level was observed.
Water in the reactor vessel drained from the reactor vessel for about three minutes until it was terminated by a combination of operator action and an automatic containment isolation triggered by the low reactor vessel water level. However, the reactor core was covered at all times.
The water level dropped 50 inches during the event, but remained 161.5 inches above the top of the reactor core.
Normal reactor water level was restored about 45 minutes after the event using the control rod drive pumps.
Subsequent investigation determined that the 'njection check valve was stuck i
in the open position instead of being in its normally closed position.
The water (between 5,000 and 10,000 gallons) drained through the injection check valve and into the suppression pool through the open suppression pool recir-culation valve and into the containment through the open containment spray valves.
Pilgrim With the plant operating at about 96% power, the licensee was performing functional testing of the HPCI system logic when a 1PCI high suction pressure alarm and HPCI area smoke detector alarm were received in the control room.
Investigation showed that a feedwater pressure transient occurred and involved the HPCI suction piping. The low pressure section of the piping was briefly overpressurized due to backflow of feedwater into the piping.
Investigation showed that miscommunication between two station personnel, while conducting more than one surveillance test at the same time, resulted in both HPCI pump discharge valves being inadvertently opened.
This left only the testable injection check valve to isolate the HPCI from the RCS.
- However, the movable internals of the latter valve were bound by rust which apparently held the valve partially open during normal operation.
This allowed feedwater pressure to overpressurize the low pressure piping through the open discharge valves.
The check valve was repaired and tested.
Analysis, and a system inspection, indicated no damage to piping or supports. Therefore, the licensee concluded that the HPCI piping and supports were operable.
Hatch Unit 2 With the plant in cold shutdown, operations personnel found that an isolation check valve was open, and would not close, during performance of a valve operability testing procedure.' The valve is located in the "B" train of the RHR system and is equipped with an air actuator for periodic testing purposes.
The valve was being held open by its air actuator which was incorrectly con-nected.
A subsequent investigation by plant personnel verified that the check valve had been open for approximately four months while the plant operated at close to full power.
The valve is a swing-type testable check Jalve with an air actuator controlled by a four-way solenoid pilot valve. The rotary type air actuator is used to perform in-service testing of the valve when the plant is in a cold shutdown 3
condition. The valve, and its actuator and solenoid valve, are installed on the 24-inch LPCI line inside the primary containment structure.
The valve serves as one of the two isolations between the high pressure RCS and the low pressure RHR system. The second isolation valve is located immediately outside containment and is a normally closed, motor-operated injection gate valve. This gate valve is designed to open automatically when the RCS pres-sure drops below the low pressure permissible setpoint.
The gate valve is interlocked with a third valve in a manner which prevents both valves being opened if excessive RCS pressure is present.
Even though no overpressurization of low pressure piping actually occurred, the event is significant since the check valve had been held open for such a long period of time. During the period, a postulated failure or inadvertent opening of the gate valve could allow discharge of high pressure reactor coolant into the low pressure RHR system.
The consequences of such an event are uncertain, depending upon the continued integrity of possibly overpressurized RHR system piping and the actuation of the RHR system relief valve which discharges to the clean radioactive waste system.
At worst, a pipe break (LOCA) outside containment could have occurred, t
releasing radioactive material to the environment.
The event resulted from a series of errors.
On June 7, 1983, during main-tenance on the valve actuator, the two air supply lines were installed back-wards. The air supply line to the right-hand cylinder of the actuator was incorrectly connected to the left-hand cylinder, and vice versa.
Failure to use a vendor maintenance manual appears to have contributed to this error.
Inadequate post-maintenance functional testing of tho valve allowed the initial error to go undetected. The check valve position is indicated in the control room.
It is not known with certainty why this did not lead to early detection.
However, it appears likely that, after maintenance, the indication was readjusted to show a closed position in the belief that the check valve must actually be closed.
When this condition was discovered, plant personnel took immediate action to correctly connect the air supply lines to the check valve air actuator. The valve returned to the normal closed position, was satisfactorily functionally tested, and subsequently returned to service on October 28, 1983.
i Browns Ferry Unit 1 With the plant operating at about 100% power, a core spray (CS) logic func-tional test was being performed.
For this test, the outboard injection valve remains in its normally open position, and the inboard injection valve is supposed to be closed.
Since the test would simulate automatic core spray actuation (which wculd normally open the inboard valve), procedures specify that the valve breaker to this valve should be opened so that the valve remains closed during the test.
However, a licensed operator failed to open the breaker; therefore, the valve opened during the test.
With both the inboard and outboard injection valves open, isolation of the high pressure RCS to the CS system is provided by a testable check valve.
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However, as later investigation indicated, improper maintenance previously 1
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performed on the check valve caused it to be held open while indicating closed.
This came about as a result of an incorrect plunger being installed in the solenoid pilot valve of the actuator leading to a pneumatic pressure reversal holding the check valve open.
The check valve position indicators were also reversed by personnel in the belief that the valve was not mispositioned.
Therefore, the high pressure RCS (about 1050 psi) was open directly to the low pressure CS system (designed for 500 psi).
During the test, the control room operator did not notice a system pressure change, and the CS system high pressure annunciator, located outboard of the outboard isolation valve, did not alarm.
Several minutes into the test, a roving fire watch noticed smoke near the loop 1 CS piping and phoned in a fire alarm (the smoke was caused by the pipe paint overheating when hot reactor coolant backflowed into the CS piping).
The fire brigade entered the reactor building and correctly assessed the reason for the pipe paint smoking.
The CS system's one inch relief valve, set at approximately 400 psig, had lifted.
The assistant shift engineer phoned the Unit 1 operator and instructed him to close the inboard isolation valve to isolate the system.
This action ter-minated the overpressurization event which lasted approximately 13 minutes.
Steam and/or water was seen coming from the CS pump "A" seal and several fire brigade members were slightly contaminated due to this water.
The CS loop 1 was isolated, placing the plant in a seven day limiting condition for operation, and investigation of the event began.
The plant was shut down on August 21, 1984 to complete the investigation.
Licensee engineering and maintenance staffs examined all components and piping and found no damage.
The maximum temperature experienced by the piping was estimated to be below 400 F.
The CS pump "A" seal was removed and no damage was observed.
The apparent seal leakage was attributed to backflow through the seal leakoff which drains to the clean radwaste drain system (the CS system relief valve also discharges to the clean radwaste drain system).
Examination of similar installations on the CS system, RHR system, HPCI system, and reactor core isolation cooling system on all three Browns Ferry units did not reveal any similar problems.
The licensee's engineering evaluation of the affected piping and supports on Unit 1 indicated that the transient did not affect system integrity for con-tinued use.
Cause or Causes - Most of the events were caused primarily by personnel errors.
The discussion above briefly mentioned causes for some of the events.
The causes for all of the events are discussed further below.
Vermont Yankee Injection valve V-10-27A had been closed from the control room, prior to opening injection valve V-10-25A, but it failed to shut fully.
This fact was unknown to the control room operators due to a full-closed indication on the V-10-27A valve's control room indicator lights. This valve was later found to be one inch open.
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y It was also found that-testable check valve V-10-46A was leaking past its seat causing an excessive differential pressure across valve V-10-25A.
Since neither valve V-10-46A nor V-10-27A were fully closed, opening valve V-10-25A caused a flow path to exist from the reactor vessel to the "A" LPCI, thereby pressurizing the loop in excess of its 450 psig system design pressure!
Cooper Station A 14 inch length of sample probe was-found loosely wedged under the edge of the check valve disc. This prevented the check valve from fully closing.
The broken probe came from a sample point on a 24" feedwater line, upstream of the HPCI junction.
Although the sample probe prevented full closure of the testable check valve, j
-the valve would have fully opened and would have passed full HPCI flow to the feedwater line in the event it would have been required. The sample probe would have remained in a no or low flow area of the valve body and would not have entered the flow stream to the feedwater line.
LaSalle Unit 1 The licensee determined that the gears on a pneumatic valve opener were not properly aligned following maintenance on the actuator. The actuator was
-therefore holding the valve in a partially open position.
The valve posi-tion indicator was subsequently aligned assuming that the valve was fully.
closed. Therefore at the time of the test, the valve indicator showed that
.the check valve was closed, while in fact it was partially open.
Following the event, a second. factor was identified during a local leak rate test performed after the valve was properly aligned.
In this test, the check valve did not perform properly.
An inspection of the valve found the packing gland on the valve shaft to be too tight, thus preventing the valve from fully closing. A different operating crew had previously performed this same surveil-lance on another RHR loop.
Prior to performing the test, the crew had identified
.a potential leakage path through the check valve and instituted a temporary change in the procedure to close the manual isolation valve on the loop being tested. This change, however, was not made applicable to subsequent tests.
Pilgrim As previcusly discussed, the testable injection valve was held open since its l
internals were bound by rust.
Then, personnel error while performing more
_ than one surveillance test allowed both discharge valves to be open at the same time. This resulted in a direct path for the feedwater pressure to t
overpressurize the' low pressure HPCI suction piping.
Hatch Unit 2 Improper maintenance on the valve actuator resulted in the two air suply lines being installed backwards.
The causes involved the performance of work without documented instructions, procedures, or drawings appropriate to the circumstances, i.e., (1) no vendor manual was used during maintenance, (2) 6
proper functional testing was not specified, and (3) other non-documented maintenance was performed.
Browns Ferry Unit 1 The causes for this event involved the following deficiencies:
1.
Maintenance personnel overhauling the check valve solenoid had installed a wrong component which altered the function such that the valve opened when it should have closed, and vice versa.
2.
Maintenance personnel altered the valve position indicating circuitry for the check valve such that the position indicator showed closed when the valve was actually open.
3.
An operator failed to accomplish the procedural step that would open the inboard injection valve circuit breaker.
The procedural step to open the circuit breaker contained two separate actions in one step, and no inde-pendent verification was required for these actions.
4.
Maintenance instructions did not contain adequate post-maintenance instruc-tions to ensure proper mechanical or electrical valve assembly.
- Also, post-maintenance testing did not verify proper operation of the check valve or indication.
Actions Taken to Prevent Recurrence Vermont Yankee Licensee - The defective components were repaired.
The affected loop piping was inspected and tested and the system returned to operation.
The system was later modified to preclude recurrence.
NRC - The NRC monitored the licensee's response to the event.
Cooper Station Licensee - The probe was removed and the valve was inspected and satisfactorily leak tested.
The exterior part of the failed probe was removed from its weld-o-let to confirm location of the failed probe.
The weld-o-let was then plugged because the sample point was not needed.
The HPCI system was returned to an operable status.
NRC - The NRC monitored the licensee's response to this event.
LaSalle Unit 1 Licensee - The similar testable check valves were inspected by the licensee to assure that their actuator gears were properly aligned and that the valve position indicators were accurate.
No problems were identified.
Maintenance logs were also examined for the valves to determine if any had had valve packing gland adjustments.
Two valves which had had no local leak rate tests performed after packing maintenance were successfully tested.
l l
7
The licensee revised its procedures to require that a manual valve be closed 1
during the RHR loop test.
Changes in maintenance procedures for the valve actuators were also being considered to preclude a recurrence of the alignment error.
The licensee has also revised its maintenance procedures to require I
that local leak rate tests be performed on valves after packing maintenance.
NRC - The resident inspectors monitored the licensee's response to this event.
Tiie' event was also discussed at an NRC Enforcement Conference, becoming a factor in the licensee deciding to add another person to its operating shift to monitor shift activities.
Pilgrim Licensee - By analysis and inspections, the licensee concluded that there was no damage to piping or supports.
The testable check valve was scheduled for replacement during a station-wide valve betterment program.
Instructions for verbal communications among station personnel were implemented.
NRC - The NRC monitored the licensee's response to this event.
Resident and region-based inspectors inspected the valve test and surveillance programs, and the valve betterment program and its implementation, during the 1984 outage.
Hatch Unit 2 Licensee - Involved plant personnel were counseled on the importance of per-forming equipment maintenance correctly.
Plant personnel were reminded of the need to perform maintenance in accordance with the appropriate valve main-i-
tenance manual and to perform thorough post-maintenance testing before re-turning a valve to service.
For the long term, the licensee is considering adopting an alternative testing method for the LPCI isolation check valves.
This alternative test method, which is in accordance with ASME Section XI, i
IW-3520, allows in-service testing of the isolation check valves to be per-formed by passing shutdown cooling flow through the valve during each cold shutdown.
On January 30, 1984, a management overview committee was established to en-sure, prior to performance of maintenance, that all' safety-related maintenance requests included proper work instructions and adequate post-maintenance functional testing requirements.
f NRC - NRC Region II inspectors performed a special inspection on November 21 -
l December 16, 1983, regarding the circumstances associated with the event. A violation was identified involving the lack of proper functional testing, the failure to prescribe that maintenance be performed in accordance with the appropriate vendor manual, and the performance of other, non-documented main-tenance, on the check valve.
The NRC's Office for Analysis and Evaluation of Operational Data (AE00) performed an engineering evaluation of the Hatch 2 event. The report, issued on June 1, 1984 (Ref. 1), pointed out the safety significance of a possible interfacing LOCA betwnan the high pressure RCS and the low pressure RHR system.
The report also mentioned the similarities of the Pilgrim event regarding possible consequences.
s 8
Based on the AE0D recommendations, the NRC's Office of Inspection and Enforce-ment began to prepare an Information Notice which is discussed later.
Browns Ferry Unit 1 Licensee - The licensee stated that the following actions have been taken:
1.
Procedures have been revised to be more descriptive in valve and actuator maintenance and return to service checks.
The licensee will now procure the solenoid as a complete assembly and will not overhaul the solenoid on site.
2.
Operator training on this event has been conducted witn particular atten-tion to valve circuit breaker manipulation.
3.
The surveillance instruction has been revised to be more specific on the circuit breaker wording.
NRC - The following NRC actions were performed:
1.
The onsite resident inspectors reviewed this event shortly after its occurrence.
2.
An enforcement conference was held with senior licensee management on September 26, 1984.
3.
Based on violations related to this event, together with several violations related to inadequate implementation of the licensee's quality as_surance program, on January 28, 1985, the NRC issued a Notice of' Violation and Proposed Imposition of Civil Penalties in the amount of $100,000 (Ref. 2). The licensee paid the civil penalties.
4.
The NRC will thoroughly review all licensee corrective actions.
5.
The NRC is considering the event as a potentially new generic issue.
In addition, NRC Inspection and Enforcement Information Notice No. 84-74 was issued on September 28, 1984 (Ref. 3) to all nuclear power reactor facilities holding an operating license or a construction permit.
The notice described the Pilgrim, Hatch Unit 2, and Browns Ferry Unit 1 events, pointed out the possible serious consequences, and offered suggestions to licensees regarding avoiding degradations of valves which provide isolation barriers between the high pressure RCS and low pressure systems.
The LaSalle Unit 1 event was included in NRC Inspection and Enforcement Information Notice No. 84-81 which was issued on November 16, 1984, to all boiling water reactor facilities holding an operating license or construction permit (Ref. 4).
In addition, the NRC's AE09 office is performing a more detailed study on this subject.
Unless new significant information becomes available, this item is considered closed for purposes of this report.
9 9 Degraded Shutdown Systems The following information pertaining to this event is also being reported concurrently in the Federal Register.
Appendix A (see general criterion 2) of this report notes that major degradation of essential safety-related equipment can be considered an abnormal occurrence.
As discussed below, the event is still under review regarding the causes of j
the event and the corrective actions to be taken.
When this information becomes known, it will be reported in a succeeding issue (s) of these quarterly-reports to Congress.
Date and Place - On June 23, 1984, 6 out of the total 37 control rod pairs at Fort St. - Vrain failed to insert upon receipt of an automatic scram signal from the plant protective system.
At the time of the event, the plant was operating at 23% power.
A somewhat similar event had occurred previously on February 22, 1982, when two control rod pairs failed to insert automatically during a manual scram (i.e., a scram initiated by the operator); however, for this event, the reactor was already in a subcritical condition during routine startup operations.
'During July 1984, the licensee reported that numerous control rod position instrumentation anomalies had occurred.
On November 5, 1984, with the plant still shut down since the June 23, 1984, event, a portion of the plant's redundant rapid shutdown system was tested and failed to operate properly.
Fort St. Vrain is a high-temperature, gas-cooled reactor (HTGR) operated by Public Service Company of Colorado (the licensee); the plant is located in Weld County, Colorado.
Nature and Probable Consequences - Control rod drive mechanisms (CROMs) are used to withdraw and insert the reactor's control rods, which constitutes the reactor's primary shutdown system.
Each CRDM controls two separate boron-bearing control rods.
There is a CRDM located in each of 37 refueling penetra-
'tions. in the top head of the prestressed concrete reactor vessel (PCRV).
The principal components of each CRDM include a drive motor, a motor brake, a duplex cable drum, reduction gearing, limit switches, and two flexible steel, h-inch-diameter suspension cables.
The control rod drives are basically electrically driven winches that raise or lower the control rods-by means of j
the suspension cables.
Each CRDM cable drum winds or unwinds its two control rod suspension cables simultaneously in separate winding grooves.
The drive j
motor is directly coupled to the drum via the reduction gearing. Therefore, when the motor brake is energized, it retains the control rod pair at a set j
position.
During a' scram, the brake is de-energized and control rods fall into the core due to gravitational force.
The free-fall speed is controlled by a velocity limiting system, which is a motor circuit capacitor array _that causes the drive motor to function as an induction generator as it spins during the scram.
Bearings, cables, and gears in the drive assembly are all treated with dry film-lubricants that have a molybdenum disulfide base.
10
I The reactor also has a reserve shutdown system for emergency un shi'ch was designed to provide an independent, alternate means of achieving shutdown conditions.
Neutron absorbing material, in the form of small (approximately is-inch-diameter) boronated graphite balls, is stored in a hopper in each re-fueling penetration from which it can be released, if required, by the opera-tor and allowed to fall into channels in the core. There are two hopper subsystems (one with seven hoppers and the other with 30 hoppers) each of which can be independently initiated by manual control.
If the balls from all 37 hoppers are released into the core, this will provide sufficient negative reactivity to shut the reactor down to refueling tempera-ture from any reactor operating condition without any movement of the control rods.
This condition can be met with two hoppers inoperative.
On June 22, 1984, the plant was being shut down from about 40% power in a controlled manner because of high moisture content in the helium coolant.
As the reactor power was being reduced, ice formation in the nitrogen-cooled, low-temperature adsorber of the on-line helium purification train resulted in a loss of normal helium letdown flow.
However, helium continued to enter the PCRV by way of normal inleakage through the helium circulator seals.
Conse-quently, at about 12:30 a.m. (MDT) June 23, 1984, with reactor power at 23%,
the reactor tripped on a high pressure signal resulting from an incongruous combination of the increasing helium inventory and the automatic down program-ming of the high pressure trip setpoint as reactor power was being reduced.
Although the reactor was verified to be subcritical following the automatic scram, it was noted that 6 of the 37 control rod pairs had failed to automati-cally insert.
These rods were then manually driven to the full-in position during the following 20-minute interval.
Subsequent analysis by the licensee showed that even with the 6 control rod pairs not inserted, there was suffi-cient shutdown margin.
On its own merit, the June 23, 1984 event is a safety concern.
The failure of six control rods to automatically insert upon receipt of a valid scram demam signal is a common-mode failure that constitutes a partial ATWS event (i.e.,
Anticipated Transient Without Scram).
Independent of any backup shutdown system, the control rod system should have an " extremely high probability" of shutting down the reactor in the event of an anticipated operational occurrence.
When viewed in the context of related other occurrences at this facility, the June 23, 1984 event takes on additional safety significance.
In an earlier event, two of the same control rods failed to insert during testing.
In a later event, a portion of the backup shutdown system failed during testing.
Further, anomalies have occurred in the instrumentation, which have led to uncertainties as to the positions of the control rods.
These other related occurrences are described below.
On February 22, 1982, the reactor was subcritical and routine startup operations were in progress.
Due to high moisture conditions and loss of helium purge flow, operators initiated a manual scram of all control rods in order to comply with the plant technical specifications.
The reactor operator observed that two of the rod pairs failed to insert.
(These same rod pairs also failed to insert subsequently during the June 23, 1984 event.) These rods were then manually driven in.
The CRDMs for all control rod pairs were manually exercised 11
until sticking tendencies were no longer apparent.
The licensee speculated
_i that-the probable cause for the binding or sticking was corrosion or debris in the CRDMs.
Exercising was continued on a daily basis during plant shut-down operations and on a nonthly basis during power operation.
No other main-tenance or inspection was conducted.
On November 5',-1984, the reactor was still shut down and testing of the backup shutdown system was'in progress. The first hopper apparently operated satis-factorily.
However, when the second hopper was tested, it failed in that only about half of the borated balls were released.
This failure has generated a new safety concern regarding the reliability of the backup shutdown system, which will require resolution prior to the plant being allowed to resume operations.
During July 1984, the licensee reported to the NRC that numerous control rod
, position instrumentation anomalies had occurred for various control rods.
With all-rods supposedly fully inserted, eleven anomalies included:
analog indication of partial rod withdrawal, rod out-limit lights being on, disagree-ment between analog position indication and digital position indication, simultaneous rod out-limit and rod in-limit indications on the same rod, no rod position indications at all for a rod, and a " slack cable" indication.
The staff review of this matter concluded that the anomalous indications were most likely caused by exposure to hot helium containing excessive moisture followed by a reactor depressurization.
In some cases, erroneous readings were caused by physical damage due to reactor operators manually driving the rodt beyond the in-limit position.
The staff concluded that the installed rod position instrumentation is inadequate to reliably determine control rod positions under post-trip adverse conditions.
During CRDM refurbishment efforts, the licensee experienced a significant setback on August 30, 1984.
After a CRDM was hoisted out of the PCRV into the auxiliary transfer cask, it was found that the cask shutter valve could not be closed.
An examination disclosed that one of the two control rod strings associated with the CRDM was not fully retracted into the cask and thereby prevented the closure of both the shutter and the reactor isolation valve.
During July 1984, the instrumentation for this CRDM indicated a " slack-cable."
This' indication could be caused by:
a broken cable, a stuck control rod, or a malfunction of the " slack-cable" instrumentation. While the indication was believed to be most likely invalid and due to misadjustment during a recently l
completed CRDM refurbishment activity, the licensee failed to plan and provide for the possibility that indication was valid.
This CRDM was placed in the licensee's hot service facility for further examination, and it was observed that one of the two suspension cables was snarled in the CRDM.
The cable was-chewed by the drive mechanism, partially unraveled, and broken into several pieces.
This problem is being pursued by the licensee, including whether it
.may be related to the June 23, 1984, event.
An additional problem regarding the shutdown systems developed on November 5, 1984. The licensee was testing the operation of two hoppers of the reserve shutdown system.
The first hopper apparently operated satisfactorily; however, when the second one was tested, it failed to release all of its contained boronated graphite balls.
Therefore, there was concern regarding the reli-ability of this backup shutdown system; this too would require resolution before plant operation could resume.
12
Cause or Causes - As of early November 1984, the root causes for the failures of the shutdown systems have not been definitively identified.
In regard to the control rod system, the repeated situations of high helium moisture and loss of purge flow to the CRDMs cannot be ignored.
Possible root causes, or contributing causes, include:
bearing wear debris from within the CRDM drive motors, elevated CRDM ambient temperatures, and excessive moisture.
The causes remain under investigation.
Actions Taken to Prevent Recurrence - Corrective actions remain under review by both the licensee and the NRC.
The actions taken as of early November 1984 are described below.
Licensee - The licensee is committed to maintain the plant in a shutdown condition until the cause of the failures are identified, corrective measures are completed, and NRC authorizes return to power operations.
Actions taken include (a) a visual examination and partial refurbishment of about six CRDMs and (b) the development and implementation of a new in-situ testing method that has been used to ascertain overall control rod drive train performance.
In regard to the CRDMs, visual examinations have revealed evi-dence of moisture condensation, minor oxidation of steel components, and small quantities of unidentified particulate matter.
There has been as yet no definitive reason identified for control mechanism binding, but it is believed possible that it is associated with small amounts of debris in the drive motor bearings, alone or in conjunction with elevated temperatures and a moist helium atmosphere.
The licensee is developing a test method which measures the back-electromagnetic force (EMF) generated by the rotation of the control rod drive motor as the rod is falling during a scram.
Back-EMF recordings might serve as an indicator of rod operability by measuring the dynamic f-ic-tional resistance within the gear train and the drive motor.
To date, the licensee has perfcrmed back-EMF testing on 36 CRDMs and has detected anomalous voltage-signature characteristics associated with CRDMs that are known or sus-pected to have degraded performance.
NRC - The June 23, 1984, event was the subject of a special inspection at the plant by NRC Region IV personnel.
This inspection report was issued on September 11, 1984 (Ref. 5).
In addition, at the request of the cector, NRC Office of Nuclear Reactor Regulation, an assessment of the 1 Mensee's overall operation was conducted.
The assessment team found significant weakness in every area of the operation that was audited. The report on this assessment includes both short-term and long-term recommendations.
The overall conclusion of the assessment team was that the Fort St. Vrain facility should not be allowed to restart until all weaknesses are addressed.
The assessment report, which was sent to the licensee on October 16, 1984 (Ref. 6), is preliminary in that various options to solve the staff's findings are available to the licensee and need to be discussed with the NRC prior to final resolution.
Further reports will be made as appropriate.
13
L 84 Loss of Offsite and Onsite AC Electrical Power l
Preliminary information pertaining to this event was reported in the Federal Register (Ref. 7). Appendix A (see general criterion 2) of this report notes that major. degradation of essential safety-related equipment can be considered I
.an abnormal' occurrence.
Date and Place - On July 26, 1984, Susquehanna Steam Electric Station Unit 2 experienced an event involving a temporary -loss of all AC power including L
' failure.of the emergency diesel generators (EDGs) to supply power to the l
engineered safety system (ESS) busses. Susquehanna Units 1 and 2 are boiling l
Water reactor nuclear power plants operated by Pennsylvania Power and Light L
Company (the licensee) and located in Luzerne County, Pennsylvania.
Unit 2 had received a full power operating license on June 27, 1984. With the unit Joperating at 30% power, the licensee was conducting planned startup testing at the time of the event.
Unit 1 operated at 100% power throughout the event at Unit 2.
Nature and Probable Consequences - A loss of-offsite power is an event which may occur one or more times during the life of a nuclear power plant; all plants are designed to respond to such events.
The purpose of the startup J
test (" Loss of Turbine Generator and Offsite Power") was to demonstrate that the dynamic. response of Unit 2 was in accordance with design.
Initial condi-tions'of the test required Unit 2 to be at approximately 30% power and its electrical distribution system to be separated and isolated from the Unit 1 system.
The test would be initiated by opening the Unit 2 turbine generator output breakers and simultaneously opening the Unit 2 output breaker from the startup transformer, simulating a turbira generator trip (load reject) and loss of offsite power, respectively. Thirty minutes after the test initiation, the
-test would be. terminated.
The test results would then determine whether test acceptance criteria are satisfied; i.e., (1) all safety systems such as the reactor protection' system (RPS), EDGs, reactor core isolation cooling (RCIC) system and high pressure coolant injection (HPCI) system, must function prop-erly without manual assistance, and (2) HPCI and/or RCIC action, if necessary, shall keep reactor water level above the initiation level of the core spray system, low pressure coolant injection (LPCI) system, and automatic depressur-ization system (ADS).
The actual test did not proceed ~as intended, as discussed
~1ater.
Separation and isolation of electrical supplies for this test required (1) feed-ing.all Unit 1 4160V ESS busses from the Unit 1 startup transformer, (2)' feeding all Unit 2 4160V ESS busses from the Unit 2 startup transformer, (3) racking out all feeder breakers from the Unit 1 startup transformer to the Unit 2 4160V ESS busses, (4) racking out the 13.8 kV tie breaker beween Unit 1 and Unit 2 auxiliary busses, and (5) placing all common loads on Unit 1 supplies.
This electrical configuration and other test prerequisites were established by 1:05' a.m. on July 26, 1984.
The startup test was initiated at 1:37 a.m. by opening the Unit 2 main generator output. breakers and the Unit 2 startup transformer feeder breaker to the Unit 2
'startup bus. This resulted in a reactor scram due to turbine control valve L
fast closure on the simulated lo a reject, deenergization of the 13.8 kV L
-busses and deenergization of the four Unit 2 4160V ESS busses.
The turbine I.
14
I bypass valves properly opened automatically to limit the initial pressure transient and the loss of power to the RPS motor generated sets properly initiated primary and secondary containment isolations.
The above sequence was as expected; however, the operator at the electrical distribution panel noted that none of the four EDGs started and that the feeder breakers from the two Unit 2 ESS transformers to the fu 4160V ESS busses remained closed.
These breakers should have automatically opened and the diesels should have started upon ESS bus denergization due to the deenergized startup transformer.
As a result of the diesels not starting, and providing emergency AC power, all AC power for Unit 2 was lost.
As discussed later, this total loss of AC power resulted in most instrumentation in the control room failing downscale which conplicated operator response to the event.
Also as di. cussed later, simultaneously with the total loss of AC power, the plant was further degraded due to the lack of DC power to the ESS bus logic circuitry for all four electrical divisions.
The operators were unaware of this lack of DC power since the plant design did not provide control room annunciation of this condition.
The consequences of the deenergized ESS bus logic circuitry resulted in loss of the following functions:
(1) automatic transfer capability of ESS busses to alternate power sources, (2) automatic diesel generator start on loss of bus sources, (3) ability to re-energize 4160V ESS busses from an offsite source from the control room, (4) automatic bus load shedding, (5) degraded grid and undervoltage protection, (6) 4160V bus feeder breaker overcurrent or differential current protection, and (7) core spray or residual heat removal (RHR) pump automatic or manual start capability even with bus power available; hence the low pressure emergency core cooling systems (ECCSs) were disabled.
Upon noting that the EtiGs did not start, the operator opened the feeder breakers from the two Unit 2 ESS transformers to the four 4160V ESS busses.
When the EDGs still did not start, the operator manually started all four diesels.
EDG D tripped on overvoltage and 8 tripped on overvoltage and underfrequency.
EDG C stabilized at an idle.
EDG A exhibited large frequency oscillations and was manually tripped by the operator.
The operator tried to manually close the EDG C breaker onto the associated ESS bus, but the breaker did not. lose (probable operator error). The operator next attempted to close the Unit 2 startup bus feeders to the two Unit 2 ESS transformers, but the feeder breakers would not close due to the deenergized condition at the startup bus.
The operator then reenergized,the startup bus by closing the Unit 2 startup trans-former feeder breaker to the startup bus and reenergized the two Unit 2 ESS transformers.
The operator next attempted to close the Unit 2 ESS transformers feeder breakers to the 4160V ESS busses, but the feeder breakers would not close.
The Unit Supervisor then instructed a Nuclear Plant Operator in the Unit 2 reactor building to rack in the feeder breakers from the Unit 1 startup transformer to the four Unit 2 4160V ESS busses.
As the Unit 1 feeder breakers to the Unit 2 4160V ESS busses were racked in, the preferred Unit 1 and 2 ESS transformer feeder breaker to each 4160V ESS bus closed, re-energizing the bus, and the EDGs B, D, and A automatically started at 1:48 a.m.,1:50 a.m., and 1:54 a.m., respectively.
At 1:50 a.m.,
the licensee declared an Unusual Event (the least severe category in the NRC's emergency classification system).
Power was restored to the first bus within 11 minutes and the last bus 17 minutes into the event.
When power was re-stored to all four Unit 2 ESS busses, EDGs A, B, and D had High Priority 15
alarms and were remote-manually shut down.
The operator in the EDG building reset the High Priority alarm on EDG A, but could not reset the High Priority alarm on EDGs B and D (operator error).
During the loss of all AC power to Unit 2, most instrumentation in the control room failed downscale. 'However, DC powered instrumentation was available to the operators, including two narrow range instruments (0-60 inches) for moni-toring reactor water level and the HPCI and RCIC supply pressure indicators for monitoring reactor pressure.
The full core display provided erroneous indication that all rods had not inserted into the core, which initially confused the operators, but operators determined the reactor was shut down because the source range monitor instrumentation indication and reactor pressure trends supported that conclusion.
(Subsequently, after power was restored, a computer printout verified that all rods were inserted.) The control room cperators had no indi-cation of suppression pool temperature and no indication of reactor water level, below narrow range instrument zero.
Personnel stationed at the local instru-mentation racks as part of the startup test provided information to the control room when reactor water level dropped below this zero reading.
During the' event, one safety relief valve controlled reactor pressure and removed decay heat by lifting eight times. At 2:18 a.m., RCIC was manually initiated at -28" reactor water level on the wide range instrument (a level above the automatic' initiation level of -31") to restore reactor vessel level.
At 2:30 a.m., the licensee terminated the Unusual Event declaration.
There was no direct impact on public health or safety by the event.
Even though some safety-related equipment designed to mitigate the consequences of design basis accidents, in the unlikely event that one occurred, was disabled, the HPCI and RCIC systems were available to provide makeup water to protect the core until power was restored.
During the event, no makeup water was being added to the reactor vessel.
However, had the water level decreased sufficiently, HPCI and RCIC would have automatically-initiated to restore water level, since power from the vital power system was available to them.
As discussed previously, RCIC was manually initiated before the automatic initiation level was reached.
Cause or Causes - The causes of this event are attributed to inadequate-imple-mentation of corrective action for previously identified problems, inadequate human engineering of the local control panels, ineffective independent verifi-I cation, imprecise procedures, inadequate operator training, and operator l
error.
The process utilized to rack out each of four Unit 1 startup transformer supplies to Unit 2 4160V ESS busses (one of the steps necessary before initi-ating the startup test) was incorrectly performed.
The normal practice for l
racking out a 4160V breaker is to ensure the breaker is in the open position, enter the breaker cubicle and open the DC knife switch supplying DC control power for the breaker, and then to rack out the breaker.
However, for these four breakers the operator was confronted with two DC knife switches and mistakenly opened the wrong switch, thereby removing DC power to the ESS bus l
logic circuitry for the bus rather than the DC control power to the breaker.
The operator repeated the above error on all four 4160V ESS busses.
As dis-cussed previously, one of the consequences of removing DC power to this ESS bus logic circuitry was to prevent EDG start on loss of bus sources, and to complicate recovery of alternate power sources.
16
I The Unit 1 startup transformer supply breakers to the Unit 2 4160V ESS busses are located in the 01 cubicle of each bus.
Each 01 cubicle has two knife switches whereas all other breakers in the 4160V ESS bus have only one knife switch.
The knife switch labels used in cubicles containing a single knife switch read " BREAKER CONTROL SWITCH AND TRIP CIRCUIT FUSES." This knife switch removes DC control power for the breaker.
The operators commonly refer to this knife switch as "DC control power".
The 01 cubicle breaker labels for the two knife switches read:
" BREAKER CONTROL SWITCH AND TRIP CIRCUIT FUSES" (for the knife switch that removes DC control power for the breaker) and "DC CONTROL" (for the knife switch that provides DC power to the ESS bus logic circuitry for the bus).
When the operator opened the first 4160V ESS 01 cubicle door, he called the control room, informed them he was at the breaker and requested confirtaation that they desired the breaker be racked out and DC con-trol power removed.
After receiving confirmation from the control room, the operator subsequently opened the knife switch labeled "DC CONTROL" and racked out the breaker.
An experienced startup test engineer was with the operator to verify the adequacy of his actions, but did not detect the error.
The same operator and startup test engineer repeated the same action at each of the 4160V ESS busses.
No alarm indication of these actions was available in the control room, al-though an examination of local indicator lights on the front of the cubicle door would have shown an abnormality, i.e., the bus feeder protection relay power light would have been extinguished.
Also, an examination of the breaker position lights in the control room as the knife switch was opened in the breaker cubicle could have alerted operators that the incorrect knife switch had been opened.
(0pening the knife switch 1abeled " BREAKER CONTROL SWITCH
~
AND TRIP CIRCUIT FUSES" should have deenergized all indicating lights associ-ated with the breaker.
This would not have occurred when the knife switch labeled "DC CONTROL" was opened.) This anomalous indication that could have alerted the control room of the error was subsequently lost when the breaker was racked out.
During the investigation of the event by the licensee and NRC, two previous events were identified involving improper operations of the "DC CONTROL" knife switch during the preoperational test program in June and October, 1983.
Following the second event, the licensee had conducted additional operator training. The operator who performed the breaker alignments on July 26, 1984, did not receive this particular training nor had he previously, according to his recollection, racked out a 4160V breaker in an 01 cubicle.
He was, however, an experienced operator who had performed numerous breaker rackouts.
The difficulties associated with the manual start of the EDGs and reset of the High Priority alarms were primarily due to inadequate procedures, inadequate operator training and operator error.
The trips of EDGs B and D both were the result of the frequency sensitivity of the overvoltage relays coupled with the manual voltage adjust having been set, per procedure, at too high a level.
The underfrequency trip of EDG B is believed to have been received as a result of the shutdown of EDG B following the overvoltage trip.
It should be noted that during an automatic initiation of the EDG, these two trip signals would be bypassed.
17
The cause of the frequency oscillations of EDG A which led to the operator to manually trip this EDG has not been determined.
Seven successful manual starts of EDG A were performed after the event with no observed frequency oscillations.
The inability to manually load EDG C onto the dead ESS bus is believed to have been caused by operator error, in that post-event analysis determined the capability to have been available, even under event conditions, and subsequent testing was performed to demonstrate this capability.
The difficulties associated with reset of the High Priority alarms on EDGs B and D were due to the operator not being aware that the design required that the protection relay seal-in reset button be operated prior to the system reset button.
In addition, operating procedures were not available locally at the EDG and, even if they were, existing procedures did not specify this par-ticular reset sequence. The proper reset sequence determination was made during the event by the licensee by review of the EDG control schematics and required approximately 35 minutes to complete and actually reset the alarms.
Some control room indicators were lost for longer than necessary due to lack of training and procedures on how to reset equipment after a loss of power.
Actions Taken to Prevent Recurrence Licensee - Immediately after the incident, the licensee initiated an investi-gation into the cause(s) and instituted immediate and long-term corrective actions.
Immediate corrective actions included:
revising labeling of kr.ife switches, adding caution labels for ESS logic circuitry knife switches, and painting the ESS bus logic circuitry knife switch handles red; providing training in the proper rackout cperation; revising procedures to include status of breaker position indicating light checks; performing seven successful starts on EDG A; revising procedures and providing training in EDG operation and alarm reset; successfully testing the EDG C's capability to close manually on a dead bus; examining all fuses in the DC control system for size and type; revising the reset procedure for the full core display and training operators in the methods to get rod position information; revising procedures to reset the suppression pool temperature monitoring system after a loss of power; and revising surveillance procedures to assure monthly 'urveillance procedures do not adversely affect F9G automatic start capability.
The long-term corrective actions include:
review and determination of adequacy of the station pr'ogram for independent verification; review of station standard electrical operating practices for acceptability; development of operating in-structions for each type breaker rackout, including light observance during the manual sequence; incorporation of proper terminology into training proce-dures; revision of procedures, drawings, and checkoff lists; review and eval-uation of the EDG testing program to determine adequacy; determination of adequacy of procedures for remote emergency start of EDGs; development of procedures for remote manual emergency start of EDGs; evaluation of over-voltage protection; determination of whether instrumentation available on loss of AC power is sufficient in number, location, and range for on-shift staff to safely handle a loss of AC power; performance of as-built verification of fuse size, type, and labeling on all 13.8 kV, 4160V, 480V load centers and DC pcwer circuits; review of all surveillance, preventive maintenance, startup test, and operating procedures that require entry into the 13.8 kV, 4160V, 480V, and 18
. _ =
f l
.DC cubicles for technical adequacy and adequacy of control; and evaluation of the present design for compliance with Regulatory Guide 1.47 with' respect to-annunciation of loss of DC control power.
The licensee's immediate co rective actions were completed prior to NRC per-mission to restart the plant. The licansee plans to identify to the NRC the status and/or schedule for completing the long-term items.
i The licensee assessed the event's impact and lessons learned on Unit 2 and applied the appropriate immediate and long term corrective actions to Unit 1 as well.
L j
NRC - NRC resident inspectors and a region-based specialist were in the con-trol room witnessing the conduct of this test.
They observed the event and the recovery. On July 26, 1984, a team of NRC technical specialists were sent to the site to investigate the circumstances of the event.
On July 26, 1984, a Confirmatory Action Letter was issued by the NRC Region I Administrator documenting his discussions with the licensee's Senior Vice President-Nuclear to bring Unit 2 to a cold shutdown condition and to not restart Unit 2 until a thorough investigation of the cause, its implication, and deficiencies thus identified are corrected, and the Regional Administrator or his designee has been briefed and has approved the Unit restart.
NRC issued a Confirmatory Order on July 27, 1984, confirming, effective immediately, the actions that were the subject of the Confirmatory Action Letter of July 26, 1984.
~
On July 30, 1984, the licensee briefed the NRC team on the results of the licensee's investigation, the implications, and the corrective actions taken and planned.
The NRC investigation results were consistent with the licensee's.
On July 31, 1984, the NRC witnessed the successful testing of EDG C's ability to manually load on a dead bus.
Subsequen'ly to these two actions, and follow-.
ing the conditions of the Order, the Regional Administrator approved restart of Unit 2 on July 31, 1984.
The NRC-investigation, while not fully documented at the time of this report, l-has identified several possible generic implic.ations from this event which may require further review. These include:
1.
Adequacy of annunciation and control room indications.
j 2.
Restart capability of emergency diesel generators under abnormal con-
~
ditions.
3.
Adequacy of human engineering aspects including labels, administrative controls, and independent verification requirements.
i An NRC inspection report was prepared and later sent to the licensee on i
September 18, 1984 (Ref. 8).
As noted in the forwarding letter to the licensee, l
certain activities appeared not to have been conducted in full compliance with l
NRC requirements.
NRC Region I personnel held an enforcement conference with I
licensee representatives on October 9, 1984.
On December 18, 1984, the NRC forwarded to the licensee a Notice of Violation and Proposed Imposition of i
a Civi1~ Penalty in the amount of $50,000 (Ref. 9).
The licensee has indicated j
that the civil penalty would not be contested.
I 19
On October 19, 1984, the NRC issued Inspection and Enforcement Information Notice No. 84-76 (Ref. 10) to inform all licensees, holding an operating license or construction permit, of the event.
Unless new significant information becomes available, this item is considered closed for purposes of.this report.
A A
A 84-11 Refueling Cavity Water Seal Failure The following information pertaining to this event is also being reported concurrently in the Federal Register.
Appendix A (see Example 10 of "For All Licensees") of this report notes that a major deficiency in design, construc-tion, or operation having safety implications requiring immediate remedial action can be considered an abnormal occurrence.
Date and Place - During a refueling outage on August 21, 1984, Connecticut Yankee Atomic Power Company (the licensee) notified the NRC that the reactor refueling cavity water seal had failed at the Haddam Neck Plant, draining the refueling poc water to the containment floor.
Haddam Neck utilizes a Westinghouse signed pressurized water reactor and is located in Middlesex County, Cor cut.
Nature and Probable Consequences - The plant was shut down for refueling on August 1, 1984.
After several days of surveillance testing, reactor disassembly began on August 12 in preparation for refueling.
Core cooling was maintained using the residual heat removal (RHR) system.
The cavity seal, which covers the 28-inch annulus between the reactor and the bottom of the reactor pressure vessel refueling cavity, was installed and tested on August 18 and the refueling pool was filled early on August 21.
i At 7:58 a.m. on August 21, the seal assembly failed, dumping water around the neutron shield tank surrounding the reactor vessel and into the containment sump below the vessel..This sump overflowed into the containment floor drains and onto the lower level of containment. Water also leaked out around the reactor coolant loop pene,, ration piping and wetted components inside the loop areas of containment.
During the first three minutes of the event, operators were responding to con-trol room alarms and indications including 480 volt grounds, high containment sump level, and decrea' sing reactor cavity level.
Flooding was reported in containment.
Upon identification of the loss of refueling cavity integrity, the operators took action to minimize the drainage to containment by realigning the RHR system to pump the cavity water'(and subsequently containment sump i
water) to the refueling water storage tank (RWST).
By 8:22 a.m.', the refueling cavity had emptied and the RHR system was' returned to a normal lineup.
Core cooling was maintained throughout the event and reactor coolant temperature did not change.
About 200,000 gallons of borated reactor coolant had drained j
to the containment floor.
The containment lower level filled to a depth of-18 ir.ches, and 40,000 gallons of coolant were returned to the RWST.
The licensee' notified NRC and State authorities of a declaration of an Unusual Event in accordance with the Emergency Plan at 8:25 a.m., August 21.
This Unusual' Event was terminated on August 23 after the water in the containment had been pumped out.
20
,,,._n--,-
i i
The licensee restricted containment access and replaced the reactor vessel head to minimize radiation exposure and protect the reactor core internals.
The licensee suspended refueling operations until a failure analysis and corrective actions were completed and until the NRC reviewed and approved the plant recovery program.
This program was approved by the NRC on October 2, 1984 (Ref. 11), and refueling operations resumed October 5, 1984.
Since the spent fuel transfer tube was isolated and all of the spent fuel assemblies were located in either the spent fuel pool (SFP) or the reactor vessel, no fuel was uncovered during this event.
Radioactivity in the ongoing releases of air from the reactor containment building increased, but remained well within allowable limits.
The only significant actual consequences were exposing equipment and structures in the containment to water damage, and extensive cleanup efforts.
However, there were serious potential safety consequences which could have occurred not only during this refueling but also could have occurred during the previous refueling operations when the same design of seal was used.
For example, the SFP gates would have been opened within an hour of the seal design failure and handling of spent fuel assemblies in the refueling cavity could have been in progress within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.
If refueling had been in progress, as many as four spent fuel assemblies could have been partially or fully uncovered as the reactor cavity drained.
In addition, the top three feet of all fuel assemblies in the SFP would have been uncovered if the pool had drained through the transfer tube.
Fuel assemblies recently removed from the reactor vessel would be even more radioactive (and generate considerably more decay heat) than spent elements stored for some time in the SFP.
In all cases, there was a potential for fuel rod damage from overheating with subsequent release of gaseous fission products from the damaged fuel rods.
In addition, loss of the water would reduce the radiation shielding for spent fuel.
This would have increased the radiation field in the refueling areas which could have precluded those operator actions necessary to prevent over-heating of fuel being moved to or stored in the SFP.
The top of the reactor vessel is at the bottom of the refueling cavity, with a l
28-inch annulus between the vessel and the bottom of the cavity.
This annulus is sealed using a 2-foot-wide stiffened annular plate with pneumatic seals (inflatable rubber bladders) around the inside and outside diameters. This l
seal assembly fits around the reactor vessel and is held in place by nine strongbacks resting on the reactor vessel flange on the inside and on the refueling cavity bearing plate on the outside. When the bladders are inflated, l
the bulging of the lower bladder section pulls a wedge-shaped upper seatirg i
surface of the bladders down onto the two 2-inch gaps.
This was intended to create and maintain a second tight seal.
The refueling cavity is then filled with borated reactor coolant to cool and shield the spent fuel elements moved during refueling.
This is a new seal assembly design first implerrented in January 1983 and used successfully on two occasions during the 1983 refueling outage.
l Cause or Causes - The event was caused by inadequate design of the bladders used in the seal assembly.
The bladders were neither specified nor suitably tested to withstand, with a suitable safety margin, the hydrostatic pressure expected to occur during normal use.
Post-event inspection of the seal assembly 21 i
i
revealed that the outer bladder had extruded between the steel plates for about one quarter of the seal circumference.
After subsequent testing, the licensee concluded that there was not sufficient margin in the seal design to prevent extresion of the bladder through the 2-inch gap.
The design verifica-tion by an independent engineer, the safety evaluation, and the review by the onsite and offsite review committees all failed to identify the inadequate seal design.
Actions Taken to Prevent Recurrence Licensee - The licensee immediately initiated a recovery program which included:
1.
NRC notification.
Industry notification was made via the Institute of Nuclear Power Operations (INP0) network.
2.
Containment dewatering / decontamination.
3.
Equipment damage assessment.
4.
Seal failure analysis.
5.
Seal modifications.
6.
Integrated event safety analysis.
7.
Procedure review.
The standing water in the containment, which was mildly contaminated (0.01 mci /ml),
was pumped to the RWST through the filter and ion exchanger of the refueling purification system.
Removal of this water was completed on August 23, 1984.
Two days of manual decontamination and cleanup followed.
On August 25, 1984, routine access to the containment lower level was restored.
The licensee conducted inspections of equipment and structures in the containment in order to assess the potential for equipment damage.
A comprehensive list of submerged or water-soaked equipment was developed.
Each item was repaired, flushed and/or evaluated to reaffirm the ability of each component to perform its design function. Major equipment affected included the reactor vessel, reactor coolant piping, nuclear instrument detectors, motor-operated valves, electrical cables and conduits, and containment sump pumps.
As stated previously, the licensee's failure analysis identified that there was insufficient design margin to prevent the bladders in the seal assembly from extruding through the 2-inch gap in the seal structure. To correct this design error, the licensee reinforced the upper portion (solid rubber) of the bladders by pressing 3/16-inch steel pins through the elastomer at 3-inch intervals around the circumference of the seals.
Subsequent testing confirmed that a safety factor of 4 with respect to extrusion of the bladder had been
. established by this modification.
In addition, the licensee installed a leak-limiting back-up cavity seal and a 5-foot-high cofferdam at the mouth of the refueling transfer canal.
In the event of another failure of a bladder, the back-up seal limits the leak rate i
22
such that operators have enough time to recognize and react to the event and return spent fuel in the any fuel. The bac,k ur 6a.yeactor cavity to a safe position prior to uncovering 4
l l also provides a measure of impact protection to the primary rubbeMeals. The cofferdam prevents uncovering fuel in the spent fuel l
pooJJ # dny future reactor cavity seal problem.
The licensee performed an integrated safety analysis for reactor cavity seal failure events. This analysis showed that a significant reduction in the probability and consequences of such an event had been achieved, and that public health and safety would not be jeopardized during a subsequent seal failure event.
NRC - As stated previously, the NRC reviewed and approved the licensee's recovery program prior to the resumption of refueling operations at the site.
On August 24, 1984, the NRC issued Inspection and Enforcement Bulletin No. 84-03 which informed licensees of this occurrence (Ref.12).
The bulletin required each licensee to evaluate the potential for a similar event at their facility and to summarize this evaluation in writing to the NRC prior to refueling.
NRC Region I performed inspections to determine the circumstances associated with this event. An enforcement conference was held in the Region I (Phila-delphia) office with the licensee on October 1, 1984.
The licensee presented its corrective actions resulting from this event, which were acknowledged by the NRC staff.
On December 13, 1984, the NRC forwarded to the licensee a Notice of Violation and Proposed Imposition of a Civil Penalty in the amount of $80,000; in addition, an Order modifying the license was imposed (Ref. 13).
The Order requires a review and appraisal by an independent organization of (1) design modification packages approved since January 1, 1979, to determine the adequacy of design control and to determine whether each such modification introduced any previously unanalyzed failure mode or mechanism, and (2) the process for initiating, evaluating, reviewing, approving, and implementing design change modifications to determine if deficiencies exist in the process, and to provide recommenda-tions for improvement.
The licensee paid the civil penalty in January 1985.
The NRC will monitor the actions taken by the licensee to assure that corrective actions taken are satisfactory.
On December 17, 1984, the NRC issued Inspection and Enforcement Information l
Notice No. 84-93 (Ref. 14), which informed licensees of features in some pressurized water reactors and boiling water reactors that may have a signifi-cant potential to cause loss of water in the refueling cavity.
This incident is closed for purposes of this report.
FUEL CYCLE FACILITIES (Other than Nuclear Power Plants)
The NRC is reviewing events reported by these licensees during the third calendar quarter of 1984.
As of the date of this report, the NRC had deter-mined that the following was an abnormal occurrence.
23
84-12 Degraded Material Access Area Barriers
~
The following information pertaining to this event is also being reported concurrently in the Federal Register.
Appendix A (see Example 11 of "For All Licensees") notes that serious deficiency in management or procedural controls in major areas can be considered an abnormal occurrace.
Date and Place - On May 22, 1984, an NRC Physical Security Inspector, while conducting a routine physical security inspection of the Nuclear Fuel Services (the licensee) facility, discovered three arera of degradation in a material access area (MAA) boundary which lessened the overall effectiveness of the security barrier.
A subsequent survey by the licensee of all MAA barriers identified four additional boundary degradations.
The licensee's facility, located in Erwin, Tennessee, manufactures nuclear fuel for the Department of Energy.
Nature and Probable Consequences - The degradations in the MAA boundaries were created by previous modification and maintenance activities in which barrier penetrations, consisting primarily of deleted piping, were not adequately sealed or secured.
The unprotected barrier penetrations provided a possible diversion path for special nuclear material.
Cause or Causes - Review of the circumstances of the event by NRC Region II management and the licensee determined that the barrier degradations occurred as a result of inadequate communication and interface between the facility maintenance and security personnel relative to modification and maintenance impact on security effectiveness.
It was further determined that the licensee's management and administrative control systems failed to promptly detect and correct the degradations of the MAA boundaries.
Actions Taken to Prevent Recurrence Licensee - The licensee implemented compensatory protection measures immediately upon discovery of the degraded MAA boundaries.
The licensee conducted a survey of all MAA facilities to identify any additional unprotected boundary penetrations.
All penetrations identified were appropriately sealed.
In addition, the licensee conducted an engineering study and evaluated all utility-type lines within the facility with respect to securing them from unauthorized use.
A formal procedure which upgrades the safeguards controls over maintenance and repair activities was prepared by the licensee. After receiving NRC
" Licensee Safeguards Guidance Group Bulletin No. 38," described below (Ref.15),
the licensee submitted a plan for comprehensive preventive action which included commitments and scheduled completion dates.
The more immediate corrective measures have been completed.
NRC - The NRC Physical Security Inspector who discovered the degradations of the MAA boundaries remained on site until completion of the initial survey of all MAA boundaries by the licensee and implementation of appropriate corrective actions or compensatory measures.
An enforcement conference was held in the NRC Region II Office on June 13, 1984. The licensee presented findings that contributed to the occurrence of the event, and proposed actions te prevent recurrence.
Subsequent management meetings were held between NRC Region II and the licensee at the licensee's 24
facility on July 19, 1984, and August 8-9, 1984', to review progress on licensee commitments to improve safeguards control of maintenance and modification y_.~
activities associated with MAA barrier penetrations, and to improve engineering drawings of special nuclear material process lines, and non-special nuclear material pipes and drains. Additionally, the results of the licensee's survey of all MAA barrier penetrations and their significance were reviewed.
On July 27, 1984, the NRC Region II Office forwarded to the licensee a Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $100,000 (Ref. 16).
The licensee responded on September 14, 1984.
Based on the licen-see's prompt and extensive corrective actions, the NRC decided to reduce the proposed civil penalty.
On January 22, 1985, the NRC issued an Order Imposing a Civil Monetary Penalty in the amount of $80,000 (Ref.17).
On August 3, 1984, the NRC Office of Nuclear Material Safety and Safeguards forwarded to the licensee and all other licensed fuel fabrication facilities a copy of " Licensee Safeguards Guidance Group Bulletin No. 38" (Ref.15), which provides guidance relative to pipes, conduits, duct work, and similar necessary penetrations of MAA barriers.
This incident is closed for purposes of this report.
OTHER NRC LICENSEES (Industrial Radiographers, Medical Institutions, Industrial Users, etc.)
There are currently more than 8,000 NRC nuclear material licenses in effect in the United States, principally for use of radioisotopes in the medical, indus-trial and academic fields.
Incidents were reported in this category from licensees such as radiographers, medical institutions, and byprodact material users.
The NRC is reviewing events reported by these licensees during the third calendar quarter of 1984. As of the date of this report, the NRC had deter-mined that the following were abnormal occurrences.
84-13 Contaminated Radiopharmaceuticals Used in Diagnostic Administrations The following information pertaining to this event is also being reported concurrently in the Federal Register.
Appendix A (see Example 12 of "For All Licensees") of the report notes that a series of events which create major safety concern can be considered an abnormal occurrence.
In addition, the general abnormal occurrence criteria notes that an event involving a moderate or more severe impact on public health or safety can be considered an abnormal occurrence.
Date and Place - On May 18, 1984, two nuclear pharmacies (i.e., Nuclear Pharmacy, Inc., located at Chicago, Illinois, and Syncor International, Inc., located at Blue Ash, Ohio) received faulty devices from the Medi-Physics, Inc. facility located at Tuxedo, New York, which were used for preparing doses of technetium-99m, a radiopharmaceutical widely used for diagnostic medical tests.
The radiophar-maceutical was contaminated with molybdenum-99, another radioactive material.
25
-n- - - -, - - - -, - - - -,
r--- - -,
Contrary to NRC license conditions, the contaminated radiopharmaceuticals were shipped by the nuclear pharmacies to hospitals, which resulted in 28 patients receiving unnecessary exposures during diagnostic medical tests.
Nature and Probable Consequences - Technetium-99m is a radiopharmaceutical which is widely used in hospitals and doctors' offices for diagnosing a variety of diseases.
It has a short halflife of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (i.e., it loses half of its radioactivity every 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. ) It is a product of the decay of another radio-active material, molybdenum-99.
The technetium-99m producing devices, called generators, contain molybdenum-99.
Technetium-99m, the short-lived product, is removed from the generator as needed by using a saline solution which combines with the technetium-99m, but leaves most of the molybdenum-99 in place.
Molybdenum-99 has no medical application and is considered a contaminant; NRC requirements permit no more than 5 microcuries molybdenum-99 contaminant in a dose of technetium-99m.
Both Syncor and Nuclear Pharamacy received a defective generator from Medi-Physics on May 18, 1984, and both proceeded to prepare technetium-99m radiophar-maceuticals for use by their medical customers.
The NRC requires that the solution removed from the generators be tested to assure that there had not been a " breakthrough" of the molybdenum-99 to contaminate the technetium-99m.
However, as discussed under "Cause or Causes" below, contaminated technetium-99m was distributed to various medical customers of the two nuclear pharmacies.
Some of the medical customers performed independent surveys, detected abnormal radiation levels, and did not use the contaminated technetium-99m.
- Others, however, administered the technetium-99m for diagnostic tests.
Inspections by the NRC and reviews by the licensees determined that 16 patients received contaminated technetium-99m distributed by Syncor and 12 patients received contaminated technetium-99m distributed by Nuclear Pharmacy.
The highest confirmed quantity of molybdertm-99 as a contaminant in a specific dose was 234 microcuries, although other patients could have received somewhat higher doses.
(A microcurie - one millionth of a curie - is a standard measure of radioactivity.)
According to an NRC medical consultant, 234 microcuries of molybdenum-99 would have resulted in an additional total body radiation exposure of 100 to 150 milli-
)
rems, which is not considered to be medically significant.
(For comparison, a typical chest x-ray involves an exposure of 20-50 millirems and individuals receive approximately 100 millirems of radiation each year from natural environ-mental sources.)
However, it is possible that the molybdenum-99 may have concentrated in certain organs (e.g., kidneys, bladder, liver) which would have resulted in organ j
exposures higher than the whole body exposure estimated above.
The NRC is not aware of any subsequent tests performed by the medical clients which might provide evidence of higher exposures to specific organs.
26
4 l
I:
l In any case, thel additional radiation to the patients represented unnecessary exposures which could have been avoided had the nuclear pharmacies not released j
contaminated technetium-99m to the medical clients, r
Cause or Causes - Even though the molybdenum-99/ technetium-99m generators were-defective and produced contaminated technetium-99m, it is the responsibility L
of the nuclear pharmacies to detect such contamination and not permit these i
products to~be given to the medical clients for patient use.
i Based on NRC inspections, the causes of the violations at the licensees are as i
follows:
-(1) At Syncor, the responsible radiopharmacist apparently at first misinterpreted
[
the test results.
However, af ter becoming aware of the contaminated technetium-99m,- he apparently made no attempt to notify clients or recover technetium-99m shipments he knew were contaminated, f'
(2) -At Nuclear Pharmacy, no breakthrough tests were performed.
In addition, until the NRC became involved, the licensee, even after being aware that a 4-breakthrough had occurred, did not take action to notify its clients and to
[
determine whether contaminated material had actually been used on patients.
4 Even after the licensee began investigating the matter, the licensee did not j
provide the NRC with reliable information.
' Actions Taken to Prevent Recurrence Licensees =- Both licensees have upgraded their procedures to assure that the NRC-required molybdenum-99 breakthrough tests are completed and fully evaluated before the technetium-99m is distributed to customers.
Both licensees operate other nuclear pharmacies as well as the facilities involved in this situation;
- ~
.their other facilities have taken similar steps to prevent the occurrence of a similar problem with distribution of contaminated technetium-99m.
j -.
In addition, both licensees are required to take other corrective actions in j
response to the NRC enforcement actions described below.
NRC
.Special inspections were conducted by the NRC's Region III Office into the handling of the molybdenum-99 contamination by the two licensees.
\\
On August 23, 1984, the NRC forwarded to Syncor a Notice of Violation and i
Proposed Imposition of Civil Penalties in the amount of $8,500 (Ref. 18). As stated in the forwarding letter, the NRC emphasized the importance of the violations and the need to ensure implementation of effective management and 1
quality control over the licensee's radiation safety program, including the need to take prompt corrective action when problems are identified. The licensee responded on September 19, 1984. On January 2, 1985, the NRC issued an Order Imposing a Civi.1 Monetary Penalty in the amount of $8,500 (Ref. 19).
1 The licensee paid the civil penalty, which was received by the NRC on l
January 22, 1985.
i On October 26, 1984, the NRC forwarded to Nuclear Pharmacy an Order Modifying Licenses, Effective Immediately (Ref. 20).
As stated in the forwarding letter, the NRC identified numerous violations at the licensee's Chicago, Illinois; Des Moines, Iowa; Wauwatosa, Wisconsin;-Philadelphia, Pennsylvania; and-27 i
Harrisburg, Pennsylvania, facilities. The inspections showed that the licensee had not maintained adequate control of its licensed activities. The licensee's ineffective and belated investigation of the molybdenum-99 breakthrough incident and the licensee's pervasive record-keeping problems were of particular concern.
The Order included specific changes in the licensee's procedures and weekly audits by each facility manager of all NRC-licensed activities.
In addition, the licensee shall obtain the services of one or more qualified independent organizations to assess the qualifications and adequacy of the licensee's employees, and the adequacy of the licensee's operating procedures, records, and radiation protection quality assurance program.
The licensee shall submit a written response to the NRC in regard to the independent organization (s) assessment and recommendations.
After the Order was issued, the NRC Region III received allegations that the terms of the Order were not being fully met at the Chicago facility.
Conse-quently, a special NRC inspection was performed on November 16 and 17, 1984; ten violations of the Order were identified. The licensee voluntarily suspended distribution of radiopharmaceuticals on November 17, 1984.
Because the licensee is a major supplier of radiopharmaceuticals in the Chicago region and a continued shutdown could affect the quality of health care in the region, NRC Region III permitted the licensee to resume operations at 11 p.m.,
on November 18, 1984, following extensive corrective measures.
During the shutdown, radiopharmaceuticals were provided to the licensee's customers by other suppliers in the Chicago area and by the licensee's Waukesha, Wisconsin, facility.
The licensee added staff to its Chicago facility from its corporate staff and provided extensive reorganization and retraining for processing and distribu-tion activities.
Consultant personnel supervised the revamping of the Chicago operations.
NRC Region III personnel observed the licensee's activities when they resumed on November 18-19, 1984. No violations of the Order of NRC requirements were observed.
NRC Region III intends to continue to closely monitor the licensee's activities at the Chicago facility and at its other NRC-licensed facilities.
On November 30, 1984, the NRC issued Inspection and Enforcement Information Notice No. 84-85 to all NRC medical licensees and radiopharmaceutical suppliers to notify them of the problems of molybdenum-99 breakthrough from the technetium-99m generators (Ref. 21).
Unless new significant information becomes available, this item is consicered closed for purposes of this report.
i i
84-14 Therapeutic Medical Misadministration The following information pertaining to this event is also being reported concurrently in the Federal Register.
Appendix A (see the' general criteria) of this report notes that an event involving a moderate or more severe impact on public health or safety can be considered an abnormal occurrence.
28
Date and Place - On July 3, 1984, Washington University Medical Center (the licensee), St. Louis, Missouri, reported to the NRC that a 64 year old patient had received a series of radiation treatments totaling 6,40G rads of radiation instead of the prescribed dose of 4,000 rads.
Nature and Probable Consequences - The patient, a 64-year osd woman, was to be treated for cancer of the brain utilizing a cobalt-60 radiation therapy device.
The prescribed dose was 4,000 rads to the head over a series of 20 equal treatments. The treatments were to consist of 100 rads to the right and left sides of the head for a total radiation dose of 200 rads per treatment.
Through an error in preparing the treatment plan for the patient, the patient received 200 rads to each side of the head during each treatment for a total of 400 rads per treatment.
The patient received sixteen doubled treatments before the error was discovered during a routine review of the patient's records.
The hospital has reported that the patient has had no acute, serious side effects as a result of the higher radiation doses.
An NRC medical consultant, retained to evaluate this case, stated that the total radiation dose to the head was still within the acceptable range for such treatments.
Cause or Causes - The misadministration was caused by an error in recording the radiation doses on the patient's treatment plan.
The total radiation dose for each treatment was interpreted as being the dose to be aaministered to each side of the head, thus doubling the dose for each treatment.
The caicula-tions used in administering the radiation treatment were subsequently checked several times by hospital personnel, as required by therapy department procedures.
These checks determined that there were no mathematical errors made, but failed to detect the deviation from the original treatment prescription.
Actions Taken to Prevent Recurrence Licensee - The licensee nas reviewed its proceoures used in checking patient records during a treatment series and has provided retraining to its staff on the handling of radiation treatments involving doses delivered from multiple locations.
The misadministration was the first in approximately 30,000 radiation treatments using the licensee's radiation therapy equipment in the past five years.
NRC - The NRC conducted a special inspection of the licensee's radiation therapy program on July 16-17, 1984, to review the circumstances of the misaaministra-tion.
The licensee's corrective actions are considered to be acceptable, and no violations of NRC requirements were identified in the inspection.
This incident is closed for purposes of this report.
a a
a a
84-15 Significant Internal Exposure to Iodine-125 The following information pertaining to this event is also being reported concurrently in the Federal Register.
Appendix A (see the general criteria) of this report notes that an event involving a moderate or more severe impact on public health or safety can be considered an abnormal occurrence.
29
Date and Place - On August 8, 1984, the NRC Region I office was notified by l
the Veterans Administration Medical Center, Bronx, New York, that on August 3, 1
1984, an individual (Individual A) working at the licensee's facility had been l
found to have a thyroid burden of approximately 524 microcuries of iodine-125 l
(apparently received on July 28, 1984), an amount which greatly exceeded the I
allowable NRC limits.
Three co-workers (Individuals B, C, and D) also showed thyroid burdens, but the values were within regulatory limits.
Nature and Probable Consequences - The following description is based upon the licensee's investigations and the results of an NRC inspection regarding the circumstances of the incident.
Although initially it was reported that the exposure had resulted from poor technique during an iodination (preparation of a tracing compound), it has not conclusively been determined how the uptake occurred.
The licensee believes that up to seven millicuries of iodine-125 was accidentally swallowed by Indi-vidual A or absorbed through his skin as a result of contamination, because seven millicuries of iodine-125 were found missing and unaccounted for from the inventory.
Individual A admitted he worked with this quantity of iodine-125 on July 28, 1984, using poor laboratory practices, such as not wearing a glove on his right hand.
The lesser uptakes by Individuals B, C and D, who live with Individual A, were probably the result of ingestion of contaminated food prepared by Individ-ual A.
All four individuals live on Veterans Administration property where the food was consumed.
Other individuals who may have consumed contaminated food received a thyroid bioassay and were found to have no uptake.
The licensee is continuing to monitor the four individuals involved.
Licensee surveys of the apartment occupied by the individuals found contamina-tion ranging from 1,000 to 3,000,000 disintegrations per minute.
The pillow of Individual A was reading 60 millirems / hour on contact.
The contamination found in the apartment was either carried by Individual A on his hands or from his own perspiration.
The apartment, which is owned by the licensee, was decontam-inated.
Individual A was temporarily moved to other living quarters to avoid further contamination to the other three individuals who remained at the decon-taminated apartment.
The licensee projected a total absorbed dose to Individual A's thyroid of approximately 2000 rads, based on maximum measured uptake of 524 microcuries.
The licensee's consulting physician does not anticipate significant thyroid damage to occur, although son.m loss of thyroid function is possible.
The licensee's physician reports that the individual is progressing satisfactorily from a medical standpoint.
NRC Region I retained a medical consultant who agreed with the licensee's assessment.
The thyroid burdens for Individuals B, C, and D were approximately 156, 94, and 68 nanocuries respectively.
These would result in small thyroid exposures, well within NRC regulatory limits.
Cause or Causes - The direct cause of the incident has not been determined.
The most likely cause appears to be mouth pipetting or other poor laboratory practice in the handling of iodine-125.
Based on the licensee's and the NRC Region I's investigations, it is unlikely that a clearer understanding of the cause will be possible.
30
1 Actions Taken To Prevent Recurrence
-Licensee - The licensee increased the frequency of thyroid bioassays from quar-terly (every three months) to weekly for all individuals handling iodine-125
-as sodium iodide.
They reviewed their training program to ensure that required safety procedures have been communicated to all personnel.
The licensee's Radiation Safety Officer is making frequent visits to the laboratory to monitor work in progress and to perform surveys.
They plan to reduce the frequency of surveys in the future if experience continues to be that few instances of contamination are found.
NRC
. Inspectors from the NRC Region I office reviewed the circumstances of
.the incident during an inspection on August 9 and 10, 1984.
Subsequently, an 4
enforcement conference was held with the licensee.
Enforcement action is-pending.
4 Further reports will be made as appropriate.
n n
n n-a n
n j -
84-16 Therapeutic Medical Misadministration j
The following information pertaining to this event is also being reported con-currently in the Federal Reflister.
Appendix A (see the general criteria) of L
this report notes that a ma;or reduction in the degree of protection of the public health or safety can be considered an abnormal occurrence.
Date and Place - On August 15, 1984, the NRC was notified by the United States Air Force Medical Center (the licensee), at Keesler Air Force Base near Gulf Port, l
Mississippi, of a therapeutic medical misadministration which had been discovered on August 9, 1984.
i Nature and Probable Consec uences - The patient was an 18 year-old female with Hodgkin's disease, who hac been treated with six courses of chemotherapy.
Sub-
[
sequent to the chemotherapy treatments, the patient underwent consolidation l
irradiation to the diseased portion of the body under a physician's supervision.
l This therapy, beginning on June 3,~1984, was applied to the mediastinum, hilar areas, supraclavicular areas, and low and mid neck.
The initial prescribed dose was 3,000 rads to all involved fields.
Because the physician felt that i
the volume of lung involved would not tolerate this dose, he intended to reduce l
the area of lung irradiated after 1,500 rads to 1,800 rads of exposure.
How-I ever, this decision was only recorded on the initial simulation films and not j
on the radiotherapy treatment sheet or the consult notes. As a result, the physician did not remember to actually reduce.the field, and the irradiation l
resulted in a total exposure to a large portion of the patient's left lung of l
2,475 rads instead of the intended 1,500 to 1,800 rads.
No immediate adverse health effects were detected as a result of the overexposure; however, the. licensee agreed that the risk of radiation pneumonitis and radiation-induced fibrosis were significantly increased as a result of this event.
l Cause or~Causes - The overexposure occurred because the administrative procedures for control of the treatment were inadequate in that they placed total dependence l
on the memory of the person administering the treatment.
I 31 l
l L
f Actions Taken to Prevent Recurrence l-Licensee - As a result of conversations with NRC Region II personnel and commitments documented in an NRC Region II Confirmation of Action letter, the l-
-licensee agreed to take the following actions to prevent recurrence:
evaluate
-the circumstances that led to the event; prepare a new treatment plan form and l
implementing instructions; conduct training of personnel involved; and report j
the results of these actions to the NRC.
I:
NRC - An inspection was performed resulting in a reporting violation and the
'NRU Region II Confirmation of Action letter described above.
NRC Region II will review the actions proposed by the licensee to assure they-are satisfactory.
This incident is closed for purposes of this report.
AGREEMENT STATE LICENSEES Procedures have been developed for the Agreement States to screen unscheduled l
incidents or events using the same criteria as the NRC (see Appendix A) and report the events to the NRC for inclusion in this report. During the third l
calendar quarter of 1984, an Agreement State reported the following abnormal occurrence to the NRC.
.AS84-2 ' Contaminated Radiopharmaceuticals Used in Diagnostic Administrations
. Appendix A (see Example 12 of "For All Licensees") of this report notes that a series of events which create major safety concern can be considered an abnormal i
occurrence.
In addition, the general abnormal occurrence criteria notes that
.an event involving a moderate or more severe impact on public health or safety can be considered an abnormal occurrence.
Date and Place - On January 30 and 31, 1984, approximately 16 patients at
-Rhode Island Hospital, located in Providence, Rhode Island, were administered technetium-99m which was contaminated with molybdenum-99, another radioactive material.
Therefore, these patients received unnecessary exposures during diagnostic medical tests.
Nature and Probable Consequences - Abnormal Occurrence (AO) 84-13 described i
earlier in this report discusses somewhat similar contaminated technetium-99m events at-two NRC licensees.
It also discusses the methods of producing technetium-99m from generators.
For the Agreement State event, the generator was supplied by E. R. Squibb of New Brunswick, New Jersey.
In addition, Rhode Island Hospital obtains it own technetium-99m from the generator rather than procuring it from an outside nuclear pharmacy.
Therefore, the hospital is responsible for assuring that any breakthrough of molybdenum-99 is detected i
and that contaminated technetium-99m is not used in medical tests.
Several of the January 30, 1984 scans were noted to have artifacts which were attributed to oxidation in the radiopharmaceutical itself or the kit (i.e., a mixture of the radiopharmaceutical and selected chemicals which will cause the l~
32
former to concentrate in selected parts of the body, e.g.,
lung, gallbladder, liver, bone.) No additional action was taken at that time.
During the after-noon of January 31, 1984, one of the nuclear medicine physicians indicated that several bone scan images were unacceptable.
At that time it was thought that the problem was due to a bad (i.e., oxidized) radiopharmaceutical or some interference from the patient's medication.
The normal daily quality control tests on the kits were repeated and found to be within normal limits.
Because molybdenum-99 breakthrough was not suspected at that time, the breakthrough test was not repeated.
Squibb was then contacted about the problem.
They told the hospital that the problem was likely due to oxidation and a new generator would be shipped out.
The chief technologist indicated that he was orginally advised of the situation when he returned to work on February 6, 1984.
He stated that he reviewed some of the " problem" scans and noted a " halo effect" which is typical of high energy isotopes, but could also have been caused by use of an incorrect col-limator.
He also noted that several patients who had the " unacceptable" bone scans were scheduled for repeat studies.
The chief technologist gave orders for these patients to be rescanned prior to injection of any additional isotope, as he began to suspect the possiblity of molybdenum-99 contamination in the patients. When the scans showed positive (isotope concentrated in the liver), he launched his own investigation.
A review of the utilization log indicated that five patients had been injected with the contaminated radiopharmaceutical on January 30, 1984, while the remaining eleven, including two pediatric cases, were injected on January 31, 1984.
The quantity of radioactive material noted as being injected into each patient appeared appropriate for the particular scan being performed for diag-nostic medical testing.
Using uncontaminated technetium-99m for diagnostic medical testing, typical radiation exposures to the organs of interest would be expected to be on the order of a few rads.
However, the molybdenum-99 increased the patients' exposures; as discussed above, the scans ordered by the chief technologist indicated that the molybdenum-99 concentrated in the liver.
The licensee later estimated the dose to the liver from the molybdenum-99 for the 16 patients.
The estimates ranged from about 20 rads to 120 rads.
This represented unnecessary exposures to the patients which could have been avoided.
Cause or Causes - The principal cause of the incident was the failure of a staff technologist to properly perform the molybdenum-99 breakthrough assay prior to injecting a technetium-99m based radiopharmaceutical.
Investigation of the incident was complicated by improper record keeping of breakthrough assays. The logbook for the breakthrough assay was missing the page for the period in question (January 30, 1984 - February 4, 1984).
The assistant chief technologist stated that the missing page was in the log at 6:45 a.m. on February 7, 1984.
However, the page was missing at 11:55 a.m. on the same date when the radiation safety officer (the licensee's medical physicist) went to the log to extract some information.
33
Actions Taken to Prevent Recurrence Licensee - The technologist responsible for performing the molybdenum-99 assay was initially suspended from her duties in the hot lab on February 6,1984 and was subsequently terminated on February 8,1984.
Additionally, both the radiation safety officer and the chief technologist have reviewed the require-ments for the daily molybdenum-99 assay with all nuclear medicine technologists and have stressed the necessity for maintaining proper records of these assays.
State Agency - The Agency was notified of the potential problem by the licensee's radiation safety officer on February 6,1984.
The Agency was in frequent tele-phone contact with the licensee over the next few weeks and conducted an on-site inspection on February 22-23, 1984.
Appropriate violations have been cited by the Agency in a Notice of Violation issued on March 15, 1984. The licensee's proposed corrective actions were con-sidered acceptable to-the Agency.
This incident is closed for purposes of this report.
l I
l 34 l
REFERENCES 1.
U.S. Nuclear Regulatory Commission, Engineering Evaluation Report No. AE00/
E414, " Stuck Open Isolation Check Valve on the Residual Heat Removal System at Hatch Unit 2," May 31,1984 (issued on June 1,1984).*
2.
Letter from James P. O'Reilly, Regional Administrator, NRC Region II, to H. G. Parris, Manager of Power and Engineering, Tennessee Valley Authority, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties, Docket Nos. 50-259, 50-260, and 50-296, January 28, 1985.*
3.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 84-74, " Isolation of Reactor Coolant System from Low-Pressure Systems Outside Containment," September 28, 1984.*
4.
U.S. Nuclear Regulatory Comission, Inspection and Enforcement Information Notice No. 84-81, " Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup," November 16, 1984.*
5.
Letter from E. H. Johnson, Chief, Reactor Projects Branch 1, NRC Region IV, to 0. R. Lee, Vice President, Electric Production, Public Service Company of Colorado, forwarding Inspection Report No. 50-267/84-18, Docket No. 50-267, September 11, 1984.*
6.
Letter from Harold R. Denton, Director, NRC Office of Nuclear Reactor Regulation, to R. F. Walker, President, Public Service Company of Colorado, foniarding " Preliminary Report Related to the Restart and Continued Operation of Fort St. Vrain Nuclear Generating Station,"
Docket No. 50-267, October 16, 1984.*
7.
U.S. Nuclear Regulatory Commission, "Abncrmal Occurrence:
Loss of Offsite and Onsite AC Electrical Power," Federal Register, Vol. 50, No. 6, January 9, 1985, 1140-1142.
8.
Letter from Thomas T. Martin, Director, Division of Engineering and Technical Programs, NRC Region I, to Bruce D. Kenyon, Vice President, Nuclear Operations, Pennsylvania Power and Light Company, forwarding Inspection Report No. 50-388/84-34, Docket No. 50-388, September 18, 1984.*
9.
Letter from James M. Taylor, Deputy Director, NRC Office of Inspection and Enforcement, to J. Calhoun, Senior Vice President, Nuclear, Pennsylvania Power and Light Company, forwarding a Notice of Violation and Proposed Imposition of Civil Penalty, Docket No. 50-388, December 18, 1984.*
10.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 84-76, " Loss of All AC Power," October 19, 1984.*
- Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555 for inspection and copying (for a fee).
35
11.
Letter from Walter A. Paulson, Acting Chief, Operating Reactors Branch #5, Division of Licensing, NRC Office of Nuclear Reactor Regulation, to W. G. Counsil, Vice President, Nuclear Engineering and Operations, Connec-ticut Yankee Atomic Power Company, " Reactor Cavity Seal Ring Failure,"
Docket No. 50-213, October 2, 1984.*
12.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Bulletin No. 84-03, " Refueling Cavity Water Seal," August 24, 1984.*
13.
Letter from James M. Taylor, Deputy Director, NRC Office of Inspection-and Enforcement, to W. G. Counsil, Senior Vice President - Nuclear Engineering and Operations Group, Connecticut Yankee Atomic Power Company, forwarding an Order Modifying License, and a Notice of Violation and Proposed Imposition of Civil Penalty, Docket No. 50-213, December 13, 1984.*
14.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 84-93, " Potential for Loss of Water from the Refueling Cavity, December 17, 1984.*
15.
Letter from Robert F. Burnett, Director, Division of Safeguards, NRC
' Office of Nuclear Materials and Safeguards, to K. D. Hensley, Manager, Licensing and Safeguards, Nuclear Fuel Services, forwarding " Licensee Safeguards Guidance Group Bulletin No. 38," August 3, 1984.* The same letter was sent to the other nuclear fuel fabricators.
16.
Letter from James P. O'Reilly, Regional Administrator, NRC Region II, to F. K. Guinn, Plant Manager, Nuclear Fuel Services, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties, Docket No.70-143, L
July 27, 1984.*
17.
Letter from James M. Taylor, Deputy Director, NRC Office of Inspection and Enforcement, to F. K. Guinn, Plant Manager, Nuclear Fuel Services, j
forwarding an Order Imposing a Civil Monetary Penalty, Docket No.70-143, January 22, 1985."
18.
Letter from James G. Keppler, Regional Administrator, NRC Region III, to Mark T. Hebner, President and Chief Executive Officer, Syncor Inter-national Corporation, forwarding a Notice of Violation and Proposed Impo-sition of Civil Penalties, License No. 34-18309-01MD, August 23, 1984.*
19.
Letter from James M. Taylor, Deputy Director, NRC Office of Inspection and Enforcement, to Mark T. Hebner, President and Chief Executive Officer, Syncor International Corporation, forwarding'an Order Imposin34-18309-0 Monetary Penalty, License No.
1 20.
Letter from James M. Taylor, Deputy Director, NRC Office of Inspection and Enforcement, to Nuclear P!nrmacy, Inc., forwarding an Order Modifying Licenses (effective immediately), License Nos. 12-18044-01MD, 14-19990-01MD, 20-21227-01MD, 37-18461-01MD, 37-19586-01MD, 37-21322-01, and 48-17466-01MD, October 26, 1984.*
- Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555 for inspection and copying (for a fee).
36 l
l
21.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 84-85, " Molybdenum Breakthrough from Techr.etium-99m Generators,"
November 30, 1984.*
i t
i l
1 i
i l
- Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555 for inspection and copying (for a fee),
i 37
APPENDIX A A8 NORMAL OCCURRENCE CRITERIA The following criteria for this report's abnormal occurrence determinations were set forth in an NRC policy statement published in the Federal Register on February 24, 1977 (Vol. 42, No. 37, pages 10950-10952).
Events involving a major reduction in the degree of protection of the public health or safety.
Such an event would involve a moderate or more severe impact on the public health or safety and could include but need not be limited to:
j 1.
Moderate exposure to, or release of, radioactive material licensed by or otherwise regulated by the Commission; 2.
Major degradation of essential safety-related equipment; or 3.
Major deficiencies in design, construction, use of, or management controls for licensed facilities or material.
Examples of the types of events that are evaluated in detail using these criteria are:
e For All Licensees 1.
Exposure of the whole body of any individual to 25 rems or more of radia-tion; exposure of the skin of the whole body of any individual to 150 rems or more of radiation; or exposure of the feet, ankles, hands or forearms of any individual to 375 rems or more of radiation (10 CFR 520.403(a)(1)),
or equivalent exposures from internal sources.
2.
An exposure to an individual in an unrestricted area such that the whole-body dose received exceeds 0.5 rem in one calendar year (10 CFR 520.105(a)).
3.
The release of radioactive material t) an unrestricted area in concentrations which, if averaged over a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, exceed 500 times the regulatory limit of Appendix B, Table II, 10 CFR Part 20 (10 CFR 520.403(b)).
4.
Radiation or contamination levels in excess of design values on packages, or loss of confinement of radioactive material such as (a) a radiation dose rate of 1,000 mrem per hour three feet from the surface of a package containing the radioactive material, or (b) release of radioactive material from a package in amounts greater than the regulatory limit.
5.
Any loss of licensed material in such quantities and under such circumstances that substantial hazard may result to persons in unrestricted areas.
39
6.
A substantiated case of actual or attempted theft or diversion of licensed material or sabotage of a facility.
7.
Any substantiated loss of special nuclear material or any substantiated inventory discrepancy which is judged to be significant relative to normally expected performance and which is judged to be caused by theft or diversion or by substantial breakdown of the accountability system.
4 8.
Any substantial breakdown of physical security or material control (i.e.,
access control, containment, or accountability systems) that significantly weakened the protection against theft, diversion or sabotage.
9.
An accidental criticality (10 CFR $70.52(a)).
- 10. A major deficiency in design, construction or operation having safety implications requiring immediate remedial action.
11.
Serious deficiency in management or procedural controls in major areas.
12.
Series of events (where individual events are not of major importance),
i recurring incidents, and incidents with implications for similar facilities I
(generic incidents), which create major safety concern.
For Commercial Nuclear Power Plants l
1.
Exceeding a safety limit of license technical specifications (10 CFR 550.36(c)).
l 2.
Major degradation of fuel integrity, primary coolant pressure boundary, l
or primary containment boundary.
3.
Loss of plant capability to perform essential safety functions such that a potential release of radioactivity in excess of 10 CFR Part 100 guidelines could result from a postulated transient or accident (e.g., loss of l
emergency core cooling system, loss of control rod system).
j l
4.
Discovery of a major condition not specifically considered in the safety analysis report (SAR) or technical specifications that requires immediate remedial action.
5.
Personnel error or procedural deficiencies which result in loss of plant l
capability to perform essential safety functions such that a potential-release of radioactivity in excess of 10 CFR Part 100 guidelines could result from a postulated transient or accident (e.g., loss of emergency L
core cooling system, loss of control rod system).
1 For Fuel Cycle Licenses i
1.
A safety limit of license technical specifications is exceeded and a i
plant shutdown is required (10 CFR 550.36(c)).
L 40 l
2.
A major condition not specifically considered in the safety analysis report or technical specifications that requires immediate remedial action.
3.
An event which seriously compromised the ability of a confinement system to perform its designated function.
3 i
f I
I i
41 l
APPENDIX 8 UPDATE OF PREVIOUSLY REPORTED ABNORMAL OCCURRENCES During the July through September, 1984 period, the NRC, NRC licensees, Agreement States, Agreement States licensees, and other involved parties, such as reactor vendors and architects and engineers, continued with the implementation of actions necessary to prevent recurrence of previously reported abnormal occur-rences.
The referenced Congressiona, abnormal occurrence reports below provide the initial and any updating information on the abnormal occurrences discussed.
l Those occurrences not now considered closed will be discussed in subsequent reports in the series.
NUCLEAR POWER PLANTS 76-11 Steam Generator Problems This abnormal occurrence was originally reported in NUREG-0090-5, " Report to Congress on Abnormal Occurrences:
July - September 1976," under the title of l
" Steam Generator Tube Integrity," and updated in subsequent reports in the series, i.e, NUREG-0090-8; Vol. 1, No. 4; Vol. 2, No. 3; Vol. 2, No. 4; Vol. 3 No. 1; Vol. 3, No. 2; Vol. 3, No. 4; Vol. 4, No. 1; Vol. 5, No. 2, and Vol. 7, No. 2.
In Vol. 5, No. 2, the title was changed to " Steam Generator Problems" since the scope of the reporting was expanded to include more than steam generator tube problems.
The item is further updated as follows.
l NUREG-0090, Vol. 5, No. 2 (" Report to Congress on Abnormal Occurrences:
April - June 1982") described repairs being made by General Public Utilities as a result of widespread, sulfur-induced stress corrosion cracking of the steam generator tubes at the Three Mile Island Unit 1 plant.
It is believed that the problem was a result of sodium thiosulfate being inadvertently intro-duced into the reactor coolant system.
Sulfur was removed by cleaning all the primary surfaces with a dilute solution of 5ydrogren peroxide.
Steam generator tube repairs consisted either of a kinetic expansion process to restore the integrity and functional status of the tubes or of plugging the ends of the tubes such that these tubes would no longer serve as a primary pressure boundary.
Later, problems were identified with several of the tubes which had been plugged during the repairs.
In several cases, plugs were found to be installed in incorrect tubes.
This problem has subsequently been corrected.
Hisplugging of tubes was also corrected.
In addition, it was discovered that six rolled plugs had come out of the lower tube sheet and are presumably in the bottom of the reactor vessel.
All similar plugs (approximately 1000) were tested for tightness.
About 25% moved during the test, and 2.5% pulled out completely.
Those that moved are being rerolled and retested, and the missin0 plu0s replaced.
The licensee attributes the problem to inadequate installation process controls, and has concluded that operation with the plugs in the reactor vessel pose no threat to pubile health and safety.
43
The licensee has submitted for NRC review a safety analysis report pertaining to the problem and the repairs made.
Subsequent to the above problem, during routine eddy current examination (required by technical specifications) of the steam generator tubes, there were indications of defects in a number of tubes.
The licensee is reviewing the situation to determine the number of tubes affected, the cause of the defects, and appropriate repairs.
A complete report is expected to be submitted to the NRC during the first calendar quarter of 1985.
This item is generally considered closed for purposes of this report.
- However, it occasionally is reopened to report steam generator information considered significant.
79-3 Nuclear Accident at Three Mile Island This abnormal occurrence was originally reported in NUREG-0090, Vol. 2, No. 1,
" Report to Congress on Abnormal occurrences:
January-March 1979," and updated in subsequent reports in this series, i.e, NUREG-0090, Vol. 2, No. 2; Vol. 2, No. 3; Vol. 2, No.4; Vol. 3, No. 1; Vol. 3, No. 2; Vol.3, No. 3; Vol. 3 No. 4; Vol. 4, No. 1; Vol. 4, No. 2; Vol. 4, No. 3; Vol. 4, No. 4; Vol. 5, No. 1; Vol. 5, No. 2; Vol. 5, No. 3; Vol. 5, No. 4; Vol. 6, No. 1; Vol. 6, No. 2; Vol. 6, No. 3; Vol. 6, No. 4; Vol. 7; No. 1; and Vol. 7, No. 2.
It is further updated as follows.
Reactor Building Entries During the third calendar quarter of 1984, 63 entries were made into containment.
There have been a total of 464 entries since the March 28, 1979 accident.
Reactor building activities during the third quarter included the removal of the reactor vessel head (described further below), installation of the Internals Indexing Fixture (IIF), and continued decontamination efforts using scabbling techniques to reduce area dose rates.
The purpose of the IIF, when placed over the open reactor vessel and filled with water, is to provide shleiding from the radioactivity of the core debris in the reactor vessel.
Scabbling consists of the mechanical removal of paint and a thin layer of concrete from walls, floors, etc., which are radioactively contaminated.
I Reactor Vessel Hoad Removal A major cleanup milestone was achieved in late July 1984 when the reactor pressure vessel head was removed and placed in shielded storage.
During the continuous 54 hour6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> work offort, the reactor vessel head was removed and placed on its storage stand, the IIF was placed over the open reactor vessel and filled with five feet of water, and the shleided work platform wa: installed on top of the IIF.
The operation was delayed due to failures of tho polar crane camera and hoist controls; these problems were subsequently coraected.
It is anticipated that the reactor vessel head wfIl not be put back on the vessel for the remainder of the 1MI-2 cleanup.
The next major evolution is the removal of the plenum during the first quarter of 1985 and fuel removal which is scheduled to begin during the summer of 1985.
44
EPICOR-II/ Submerged Demineralizer System (SDS) Processing The EPICOR-II system processed approximately 93,000 gallons of water during the third quarter of 1984.
The SDS processed approximately 140,000 gallons of water during the same time period.
EPICOR-II/Prefilter and SDS Liner Shipments One SDS liner was shipped from the THI site to Hanford, Washington, during this reporting period.
Auxiliary and Fuel Handling Building Activities Decontamination activities continued during this quarter.
The refurbishment of the "A" fuel pool continued as the four upper tanks, piping, and structural material were decontaminated and removed.
The makeup and purification demin-eralizer costum elution system was installed and tested following the NRC TMI Program Office (TMIPO) approval of the licensee's safety evaluation.
The six-week operation to reduce radiation levels to allow conventional sluicing of the demineralizer resins began in late September 1984.
A temporary cement solidification system was installed and operated to solidify spent resins and waste water from water processing operations.
The low level solidified waste will be disposed of at a shallow land burial site.
TMI-2 Advisory Panel Meetinas On July 12, 1984, the Advisory Panel for the Decontamination of THI-2 (Panel) held a meeting in Harrisburg, Pennsylvania.
Dr. W. Kirk, Director of TMI Field Station, U.S. Environmental Protection Agency (EPA), reported on the results of the interagency THI-2 radiological monitoring program review.
The radiological monitoring programs conducted by the NRC, tl.e Commonwealth of Pennsylvania and the licensee will remain essentially unchanged.
The EPA monitoring program will incorporate new sample methodology in a number of sampling programs.
The changes will, in many cases, increase the theoretical detection limits of the sampling.
The Panel was asked by Dr. Kirk to review the proposed changes and provide comments to EPA by the middle of August 1984.
Mr. J. Devine THI-2 Recovery Technical Planning Of rector, GPU Nuclear Corporation (GPUNC), provided a discussion on the licensee's continuing efforts to define the endpoint in the cleanup effort.
The licensee's goal at THI-2 is to eliminate any radiation release capability and place the facility in a fully stable and secure condition se that a decision can be made as to the disposition of the facility.
Act:ording to Mr. Devine, options under consideration are refurbishment, dismantling and interim safe storage.
Mr. E. Kintner, Executive Vice President, GPUNC, provided an update on THI-2 cleanup funding levels.
Anticipated funding for calendar year 1985 is
$120 million.
Mr. Kintner expressed optimism that the $1 billion required for the cleanup is "within striking distance."
45
Mr. E. Kearney, Senior Vice President of the Edison Electric Institute (EEI),
summarized EEI's efforts to date to secure voluntary contributions for the cleanup effort from its members which are investor owned utility companies.
Mr. Kearney stated that recent actions on the part of EEI will make $25 million a year available to GPUNC for cleanup of THI-2 beginning in 1985.
On August 9, 1984, the Panel met in Harrisburg, Pennsylvania.
Dr. W. Kirk, Director of TMI fleid Station, U.S. Environmental Protection Agency (EPA) l summarized the results of the EPA's radiation monitoring program in the vicinity of the TMI site during head lift.
Dr. Kirk reported that measurements taken during the head lift and all analyses completed from samples taken during the head lift operation show no increase in radioactivity attributable to the licensee's activities.
Dr. Kirk also received comments from the Panel on proposed changes to the EPA TMI radiation monitoring program.
Mr. K. Miller, a Panel member, provided written comments on the revisions to the program to both the Panel and Dr. Kirk.
The Panel passed a resolution endorsing the,
revised EPA program.
Mr. B. Kanga, Director TMI-2, GPUNC, and other licensee officials, briefed the Panel on the reactor vessel head lift operation.
The Panel and public were shown a video tape of the head lif t operation.
The licensee provided a detailed discussion of worker radiation exposure attributable to the head lift.
Cumula-tive radiation exposure was below that predicted by both the licensee and the NRC.
On September 19, 1984, the Panel met in Harrisburg, Pennsylvania.
The Panel received a presentation from the NRC staff on the staff's findings relative to the issue of alleged harassment by the licensee's management of specific individuals in the employment of GPUNC over issues of health and safety.
Licensee representativas provided the Panel with an update on anticipated funding of the cleanup effort for calendar year 1985 and beyond.
Staff members from the NRC's THIPO, U.S. Environmental Protection Agency, and Pennsylvania Department of Environmental Resources provided Information relatirg to an informal environmental survey on the Susquehanna River's vest shore.
Further reports will be made as appropriate.
A A
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A 81-8 Seismic DosJfqj Errors at Diablo Canyon Nuclear Power Plant This abnormal occ.ur ence was originally reported in NUREG-0090, V)1. 4, No. 4
" Report to Congress on Abnormal Occurrences:
October-December 1931," and updated in subsequent reports in this series, i.e., NUREG-0090, Val. 5, No. 1; Vol. 5, No. 3; and Vol. 7, No. 1.
It is further updated as follows.
The Olablo Canyon Nuclear Power Plant Unit 1 low power license was issued in September 1981.
When seismic structural design errors were reported by the licensee shortly thereaf ter, the Commission suspended fuel load authnrlty in November 1981 and required tn Independent Design Verification Program (10VP) to be performed as a prorcadisite to reinstating the low power license.
The l
Ilconsee has completed the program, including the necostary modifications and corrective actions which resulted from the design verification paogram.
l 46 r
In November 1983, the Commission reinstated the authority to load fuel and conduct cold system testing.
In January 1984, the Commission granted further cuthorization to perform hot system testing with the reactor remaining sub-critical. On April 13, 1984, the Commission authorized full reinstatement of the low power license, in particular the authority to go critical and perform low power testing up to 5% of rated power.
Diablo Canyon Unit I went critical cn April 29, 1984.
The low power testing was completed on May 23, 1984.
The reinstatement of the suspended low power license and a Commission's decision regarding issuance of the full power license required satisfactory resolution of three related major efforts.
The first was the completion of the design verification effort as previously reported in NUREG-0090, Vol. 7, No. 1.
This effort has been completed and four supplements to the Safety Evaluation Report (Ref. B-1) have been issued, i.e., Supplements 18 (Ref. B-2), 19 (Ref. B-3),
20 (Ref. B-4), and 24 (Ref. B-7).
As a result of the design verification Cffort, allegations regarding design, construction, operation and management have been submitted to the NRC since early 1983.
As of July 1984, approxi-mately 1400 allegations had been submitted by various sources.
The staff's Cvaluation of these allegations is presented in Supplements 21 (Ref. B-5), 22 (Ref. B-6), and 26 (Ref. B-9), to the Safety Evaluation Report. Many of the cliegations are identical or very similar.
The staff applied certain criteria for determining which allegations must be resolved on a priority basis.
The staff has completed its review of the allegations and concluded in Supplement 26 that they have been resolved for issuance of a full power license.
The third effort was on piping and supports, which was also the subject of numerous allegations and concerns reviewed by the staff.
This resulted in seven specific license conditions to be completed prior to a full power Itcense decision.
The licensee's efforts to resolve these matters have been completed.
A team of NRC staff and consultants has performed audits, inspections and cvaluations of the efforts including plant walkdowns.
The conclusions are presented in Supplement 25 (Ref. B-8) to the Safety Evaluation Report.
On August 2, 1984, the Commission voted to authorize a full power license for Unit 1.
However, on August 17, 1984, the U.S. Court of Appeals, responding to a petition of the Joint Intervenors, granted a stay of issuance of a full power license pending the court's review based on the issues of (1) compli-cating effects of earthquakes on emergency planning, and (2) reevaluation of the adequacy of the seismic design for piping, t
On October 31, 1984, the U.S. Court of Appeals lifted the stay of issuance of a full power Itcense.
Accordingly, on November 2, 1984, the NRC issued Facility Operating License OPR-80, authorizing full power operation (3338 megawatts-thermal) of Unit 1.
The licensee expected that the unit would be in full power operation in approximately two months.
This incident is closed for purposes of this report, e
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~
83-15 Emergency Diesel Generator Proolems This abnormal occurrence was originally reported in NUREG-0090, Vol. 6, No. 4,
" Report to Congress on Abnormal Occurrences:
October-December 1983." The item is updated as follows.
In the previous report, it was noted that as a result of several occurrences where the quality assurance of Transamerica Delaval, Inc. (TDI) diesels was in question, and after a crankshaft fracture during testing at the Shoreham Nuclear Power Plant on August 12, 1983, the following actions were taken:
1.
The applicant, Long Island Lighting Company (LILCO), replaced the 11 x 13 crankshaft assemblies on the DSR-48 diesels at Shoreham, whose design was judged to be inadequate by the applicant and its consultant, with 12 x 13 crankshaft assemblies similar to those reportedly installed in all other DSR-48 diesels.
The DSR-48 diesel is an eight cylinder engine whose cylinders are in a straight line (straight-8).
2.
A group of Utility Owners (13) who have TDI diesels formed an owners group to address the reliability of the emergency diesel generators.
The NRC was informed of the formation of this group by letter dated December 23, 1983.
There are 3 basic engine designs now under review:
the previously mentioned straight-line 8 (DSR-48); a V-16, 16 cylinders in a V configuration, eight on each side (DSRV-16); and a V-20, ten on each side (DSRV-20). When the group was originally formed, a V-12 was also under consideration; however, the plant (Midland) was canceled.
There are three plants that have DSR-48s, eight have DSRV-16s and one has a DSRV-20.
Each plant may have two to three diesels per reactor unit.
3.
On January 16, 1984, a special NRC project group was formed to coordinate the overall NRC review of TDI diesel generators.
The group's primary responsi-bility is to evaluate the overall qualification of TDI diesel generators for nuclear service.
Pacific Northwest Laboratory (PNL) was chosen to assist the staff in assessing and evaluating the corrective action plans being submitted by the Owners Group and by utilities possessing TDI diesel generators.
The Owners Group developed a program plan (0GPP) to resolve the TDI Diesel issues which consists of three program elements.
The first program element, Phase I, consists of a review of a limited number of diesel components with known design and or manufacturing concerns that warrant attention on an accele-rated schedule.
The number of components in Phase ! is 16, however, components of different engines (e.0,, crankshaf ts for the straight-8 and the V-16) have to be treated separately.
Therefore, there are more than 16 components actually being reviewed.
PNL and the NRC staff will review the Owners Group evaluations and recommendations for these components and the NRC will issue safety evaluation reports (SERs) for each component.
It is expected that all Phase I SERs will be completed during the first calendar quarter of 1985.
Phase II cf the OGPP, the Design Review / Quality Revalidation (DR/QR), is a review of a larger set of engine components to assure that their design and manufacture including specifications, quality control and assurance and opera-tional surveillance and maintenance are adequate.
The Owners Group will 48
submit the DR/QR to the individual applicants and licensees so that they can i
verify the results and they in turn will submit the DR/QR to PNL and the NRC.
PNL will audit the DR/QR reviews by doing its own review of 10 to 20 components and the NRC will issue a DR/QR SER on each plant.
It is expected that the SERs for all scheduled Phase II DR/QRs will be completed during the third calendar quarter of 1985.
In addition to these two phases of the program, the Owners Group has proposed engine teardown and inspections for all utilities as an additional program element.
These inspections are used to develop the data required for the DR/QR program.
Inspections are also made after preoperational tests have been performed to provide one of the bases for approval of diesel operation for an interim period prior to completion of Phase I and Phase II review.
PNL reviewed and evaluated the OGPP; their report was issued in June 1984 (Ref. B-10).
The NRC staff also reviewed the OGPP, and PNL's evaluation.
On August 13, 1984, the NRC staff issued an SER on the OGPP (Ref. B-11).
The NRC staff concluded that the OGPP incorporates the essential elements needed to resolve the outstanding concerns relating to the reliability of the TDI engines for nuclear service.
PNL and the staff also prescribed conditions that had to be met by the diesels in order that licensing on an interim basis, i.e., for at least one operating cycle, could proceed.
The plants whose TDI diesels have been approved, by the issuance of SERs, for operation until the first refueling outage are Grand Gulf, Catawba, Comanche Peak, Shoreham, and San Onofre.
Other diesels expected to be reviewed for approval on an interim basis are at River Bend.
Approval of these diesels over the long term will be reviewed after completion of Phase I and Phase II of the program and any additional tests that may be required.
A final SER will be issued for each of the plants that are being licensed or restarted based on interim diesel availability.
For plants where the Phase I and Phase II programs are scheduled to be completed sufficiently ahead of the licensing or restart of the plant, a final TDI Diesel SER will be developed which encompasses the results of Phase I, Phase !!
and any additional tests that may be required.
Plants anticipated to be Itcensed directly on a long-term basis, because the Phase I and Phase !!
program results will be available for implementat hn in time, are Shearon Harris, Perry, Vogtle, Rancho Seco, and Washington Nuclear Unit 1.
Upon completion of all the DR/QR SERs (Phase II), the NRC staff will review the results to determine if any generic or plant-specific implications may exist for each plant with TDI diesels and will modify the final SERs accordingly.
The TDI diesel hearing for Shoreham, before the Atomic Safety and Licensing Board, began on September 10, 1984.
Suffolk County, Long Island, is the inter-venor.
The litigated items at the start of the hearing were cylinder heads, cylinder block, crankshaft, and pistons.
During the course of the hearing, cylinder heads and pistons were dropped as litigated items.
Cross examination regarding all filed testimony before the Board was completed and the hearing.
adjourned on November 16, 1984.
The hearing is to resume on February 12, 1985, in consideration of a motion by LILCO to partially reopen the record in the following areas:
a) requalification of diesels at a load of 3300Kw, and b) discussion of recent Emergency Diesel Generator (EDG)-103 test results, especially with regard to the crankshaft and cylinder block.
49
LILC0 completed a 740 hour0.00856 days <br />0.206 hours <br />0.00122 weeks <br />2.8157e-4 months <br /> fatigue endurance test, at a load of 3300 Kw, for EDG-103.
The subsequent non-destructive inspection of the crankshaft of EDG-103 was completed on November 15, 1984.
Liquid penetrant indications in the web to pin regions of the crankshaft were examined by eddy current test and found not to be cracks.
No other EDG-103 component non-destructive examination has revealed results of any concern to the licensee or the NRC consultants monitoring the examinations.
Further reports will be made as appropriate.
AGREEMENT STATE LICENSEES AS83-9 Exposures tn Americium-241 This abnormal occurrence was orginally reported in NUREG-0090, Vol. 6, No. 2,
" Report to Congrer.s of Abnormal Occurrences:
April-June 1983."
It is updated as follows.
As mentioned in Vol. 6, No. 2, the Texas Department of Health (the Department) issued orders in March 1983 to suspend the licensee's (Gulf Nuclear Inc., of Webster, Texas) radioactive materials license and to cease certain radioactive materials handling operations.
Shortly after issuance of the orders, the radiological concerns of the Department were satisfactorily resolved and subsequently the licensee was permitted to resune operations.
However, the licensee filed suit against the Department regarding its authority to issue such orders without a prior hearing.
On August 29, 1983, the NRC flied an " amicus curiae" brief with the Texas Appeals Court, which stated the NRC's belief in the necessity of being able to issue emergency orders without prior hearings as an extremely important aspect of the regulation of nuclear materials and activities.
On February 1, 1984, a Texas Appeals Court handed down a long-awaited judgement in the legal matters between the licensee and the Department.
The court found that the Department did not have the authority to suspend Gulf Nuclear's license wit 1out a prior hearing.
However, the court upheld the Department's authority to protect the public health and safety by the issuance of emergency orders to impound radioactive materials or to cease specified operations involving the handling of radioactive materials without a prior hearing.
These findings are in line with the authorities granted to the Department under the State's Radiation Control Act according to the court.
The State l
considers the decision a precedent-setting victory in the confirmation of its authority to issue emergency orders without prior hearings.
The incident is closed for purposes of this report.
I 50 1
i
F APPENDIX C OTHER EVENTS OF INTEREST The following events are described below because they may possibly be perceived by the public to be of public health significance.
The events did not involve a major reduction in the level of protection provided for public health or safety; therefore, they are not reportable as abnormal occurrences.
1.
Seal Table Leaks Since January 1984, there have been several events involving damage to fittings at incore probe seal tables.
All three occurred as plant personnel were per-forming maintenance on the fittings while the reactor coolant systems were at clevated pressures and temperatures.
These events resulted in increased potential hazard to personnel performing the maintenance.
However, the actual impact on their health or safety was small; therefore, the events are not reportable as an abnormal occurrence.
They are being reported here since at least one of the events (i.e., at Sequoyah Unit 1) attracted wide public interest.
The seal table is the termination point for a series of tubes, called thimbles, which carry probes into the reactor vessel to monitor the neutrons produced in the fission process.
The tubes are double walled with the inner tube providing a pathway for the probes.
The space between the inner tube and outer tube is filled with reactor cooling water at the same pressure as the reactor cooling system.
The incore instrument system is used to satisfy technical specification require-ments for surveillance of reactor core parameters during power operation.
Moni-toring of core parameters is necessary to ensure that the reactor fuel is kept t;ithin the bounds imposed by the facility safety analysis so as to prevent fuel cr cladding damage during potential transients.
The inability to perform required core flux mapping would require a plant shutdown in accordance with technical specifications.
The events occurred on, (1) January 20, 1984, at Zion Unit 1 operated by Commonwealth Edison Company and located in Lake County, Illinois, (2) April 19, 1984, at Sequoyah Unit 1, operated by Tennessee Valley Authority and located in Hamfiton County, Tennessee, and (3) September 13, 1984, atTrojan, operated by Portland General Electric Company and located in Columbia County, Oregon.
All three plants are Westinghouse-designed, pressurized water reactors.
Sequoyah Unit 1 The event at Sequoyah Unit 1 is considered the most significant of the three cvents because a highly radioactive component was ejected from the core which i
51 l
could have been highly hazardous to personnel.
Significant efforts by the licensee were required to safely recover the component.
In addition, the event received widespread media coverage.
l l
On April 19, 1984, Unit 1 was at 30% power, with maintenance in progress for cleaning of the interior of the D-12 thimble tube (stainless steel tubing about 0.3 inch 0.0.).
The cleaning assembly for drybrushing of the thimble tube was inserted about 80 feet into tube D-12 when the high pressure seal fitting, which forms the reactor coolant system (RCS) pressure boundary, failed.
The RCS pressure caused a 25-35 gallons per minute (gpm) reactor coolant leak. At the first indication of leakage, the eight workers in the incore instrument room immediately left the room through the containment airlock without injury.
Whole body doses for the eight workers were well within regulatory limits and none of the workers were contaminated.
Shortly after the workers left the area, RCS pressure caused ejection of thimble tube D-12.
An NRC Regional radiation specialist inspector was sent to the site due to the radiation hazard associated with the irradiated thimble tube.
After extensive preplanning and mockup training, plant personnel recovered the highly radio-active thimble tube over the period of April 25-28, 1984.
The tubing was cut and stored in a shielded cask utilizing a robot obtained from the U.S. Depart-ment of Energy.
The cause of the event is attributed to failure of the licensee to control modf-fications made to the cleaning fixture used to support the drybrushing apparatus.
The tool had been repeatedly modified since 1979 by plant personnel without per-forming technical evaluations or tests to determine the effects of the modifica-tions of the tool on the thimble tube seal reactor coolant pressure boundary.
Based on mockup testing after the event, the cleaning fixtures were determined to impose unusual bending and lifting forces on the high pressure seal due to the mechanical advantage associated with the fixture and its base.
The ejected thinble tube 0-12 was replaced and the high pressure seal for 0-12 repaired.
All seal table pressure boundary seals were visually inspected and checked for tightness.
The licensee committed to stop cleaning thimble tubes at pressure and temperature and to develop a program for control of special tubes.
Additionally, procedure reviews were initiated to develop improved programs and procedures for control of maintenance activities.
NRC followup of the event was accompitsbed by the resident inspector and a special inspection team from the NRC Region 11 Office.
A management meeting was held with the Ilconsee subsequent to the event to discuss licenseo manage-ment controls concerning maintenance, and administrative controls over mainte-nance activities, associated with the incore instrument systems.
Escalated enforcement actions are pending.
Zion Unit 1 On January 20, 1984, a small leak of reactor cooling water was observed in the seal table room inside the reactor containment.
At the time, the pInnt was in hot shutdown, preparing to resume operations after a refueling outage.
62
The leak was found to be at the high pressure seal for one of the tubes, thimble E-11, where it was connected to the seal table.
Two licensee mechanics attempted to stop the leakage by tightening a fitting for the high pressure seal.
The leakage was reduced, but not eliminated.
RCS pressure was then reduced from 1000 pounds per square inch (psi) to 400 psi to attempt further repairs.
The two workers believed that the fitting was not properly seated and removed two bolts holding the fitting in place.
The fitting then broke loose, increasing the leakage to approximately 18 gpm.
The workers were not injured.
The leakage was uncontrolled and could not be isolated from the RCS; therefore, plant depressurization and cooldown were immediately initiated.
Once RCS pressure was reduced, the high pressure seal was replaced and the leakage terminated.
Subsequent examination of the fitting for thimble E-11 and the other thimbles determined that a ferrule, or sleeve, around the tube inside the fitting had moved out of position on 51 of the 58 thimbles.
The licensee determined that these fittings had moved out of place during assembly of the high pressure and low pressure seals inside the fitting.
The low pressure seals are believed to have pulled up the ferrules, causing an improper fit of the high pressure seals.
The out-of place ferrule on thimble E-11 is believed to have caused the initial leak.
Excessive tightening of the fitting during the initial repair attempt probably put added stress on the ferrule and allowed it to break loose when the bolts were removed.
For corrective actions, the licensee has changed the maintenance procedures used to make up the seal table to assure that the ferrules of the high pressure seals are not displaced.
The event was reviewed by the NRC resident inspectors at the plant.
After the Zion Unit 1 and Sequoyah Unit 1 events, the NRC issued Inspection and Enforcement Information Notice No. 84-55 on July 6, 1984, to inform all facilities holding an operating license or construction permit of the two events (Ref. C-1).
Tro. fan The event at Trojan was similar to the previously discussed Zion Unit 1 event.
During a periodic operating test on September 12, 1984, for RCS integrity, which was being performed prior to initial startup after a refueling outage, three Swagelok fittings (J-7, L-11, and E-5) located at the seal table were noted to be leaking slightly.
The plant was in hot standby at normal operating tempera-ture and pressure.
During the morning of September 13, 1984, a maintenance crew including a radia-tion protection technician entered the containment to tighten the three fittings.
The leaks from the J-7 and L-11 fittings were successfully stopped af ter t'ight-ening.
An attempt to tighten the E-5 fitting was made, but it continued to weep.
A bow was noted in the tubing above the fitting, and an attempt was made 53
l to straighten it by loosening the isolation valve mounting bolts.
As this point the E-5 fitting failed. The two maintenance workers were sprayed with water before exiting.
The control room was notified and immediately tegan depressur-izing and cooling down the RCS to minimize the leak rate.
The leakage from the failed fitting was estimated to be about 15 gpm.
Approxi-mately 15,000 gallons of reactor coolant were discharged into the containment sump system during the course of the event.
Since the failed fitting could not be easily repaired, the conduit was seal-welded and the RCS was returned to test pressure.
The inspection results of the repaired area were acceptable.
The maintenance workers received minor external contamination which was removed by routine decontamination proceduras.
The root cause of the event was tb: licensee's failure to properly incorporate industry operating experience int, maintenance instructions.
Therefore, the mechanics who were attempting to stop the leak during plant recovery were not aware of the risks associated with loosening the bolts on the thimble isolation valve (such as the Zion Unit 1 event).
Investigation showed that a high pressure ferrule had inadequately compressed an outer guide tube onto the E-5 Swagelok fitting that connects to the inner thimble tube.
When the workers loosened the isolation valve restraints on the thimble tuba, system pressure caused the Swagelok fitting to fail.
As enrrective actions, the licensee is revising maintenance procedures to cau-tion against moving the seal table isolation valve at pressure and preclude cleaning guide tubes while the RCS is pressurized.
A personnel safety procedure will be developed to provide maintenance guidelines for working on pressurized and/or hot systems.
As an interim measure, permission from the plant duty manager will be required prior to work being done on pressurized fittings.
Additional training for mechanics has been given on compression fitting use.
Added management attention is being given to assure that proper work instruc-tions and personnel training cre provided.
A design review will be conducted to determine if a better sealing method is available for the seal table.
2.
Reactor Vessel Flaw On August 5,1984 during a planned 10 year inservice inspection of the Indian Point Unit 2 reactor vessel, an ultrasonic indication of a flaw was identified at or near the outside of one of the vertical weld seams in the beltline region.
The indication was initially reported as within 0.25 inches of the outside surface, with a size of approximately two inches vertically and two inches radially (depth).
Indian Point Unit 2 is a Westinghouse-designed pressurized water reactor, operated by Consolidated Edison (the licensee), and located in Westchester County, New York. The pressure vessel was manufactured by Combustion Engineering.
To further and more accurately evaluate the indication, the licensee reviewed the original fabrication records, fleid fabrication records, and fleid installa-tion photographs.
In addition, an alternate ultrasonic technique was applied.
Westinghouse performed laboratory tests on full thickness mockups using the same instruments used for inspection of the reactor vessel.
From this informa-tion Westinghouse concluded that the flaw depth was approximately 0.3 inches deep.
54
In a letter to the licensee dated August 16, 1984, the NRC staff requested additional information and indicated that NRC review and approval for restart would be required.
In accordance with 10 CFR $50.55(a), the need for repair or additional inspection would be based on ASME Code Section XI requirements.
Using depth estimates from the licensee analyses only (the NRC staff performed independent analyses),
normal operation and inspections at 10 year intervals could be resumed if the depth is less than 0.31 inches.
If the depth is between 0.31 inches and 2.7 inches, operation could be resumed with augmented inspection.
If the depth is greater than 2.7 inches, repairs would have to be accomplished prior to restart.
The NRC staff also requested additional information from the licensee in a letter dated September 19, 1984, and during meetings on August 11, 1984 (held in Bethesda, Maryland), August 15-17, 1984 (held in Pittsburg, Pennsylvania),
and October 3,1984 (beld in Bethesda, Maryland).
The licensee responded by letters dated September 7, 1984, September 21, 1984, October 10, 1984, and October 12, 1984.
The licensee, together with its consultants (i.e., Westinghouse, the prime con-tractor for the reactor vessel examination; and Combustion Engineering, the vessel manufacturer) concluded that the best estimate of size of the ultrasonic indication is a maximum depth of 0.26 inch and no longer than 0.85 inch. The licensee further concluded that the indication size is within ASME Code Section XI requirements for allowable flaw size and therefore requires neither repair nor augmented inservice inspection.
As described in the NRC's safety evaluation (Ref. C-2), the NRC concluded that insufficient vessel inspection data exists to conclusively support the Itcensee's estimate of indication size (i.e., 0.26 inch deep and 0.85 inch long).
- However, l
the NRC did have reasonable assurance that a through wall dimension of 1.2 inches l
and a length of 2.0 inches should conservatively bound the actual flaw; this flaw size is well within the maximum flaw size as calculated by fracture mechan-l ics analyses.
Fatigue crack growth of the flaw during the remaining life of the vessel will be negligible and is not considered a significant factor in the fracture evaluation of the flaw.
Further, even if a low-temperature, over-pressure (LTOP) ovent should occur (a low probability event), the probability of failure of the vessel is considered negligible.
The NRC agreed that the vessel is acceptable for continued service.
Therefore, in a letter dated October 16, 1984 (Ref. C-2), the NRC approved restart of Indian Point Unit 2.
However, since the NRC was unable to conclude that the flaw size is within ASME Code Section XI allowable, augmented inspec-tion of the pressure vessel will be necessary during the next 10 year inservice inspection program.
The Itcensee has submitted a license amendment request to incorporate appropriate technical specifications regarding the augmented inservice inspections.
l The licensee initiated actions to return the plant to powar operation.
l This event had no impact on the public health or safety.
Therefore, it is not l
considered reportable as an abnormal occurrence.
55
l REFERENCES (FOR APPENDICES)
B-1 U.S. Nuclear Regulatory Commission, " Safety Evaluation Report Related to the Operation of Diablo Canyon Nuclear Power Plant, Units 1 and 2,"
Docket Nos. 50-275 and 50-323, USNRC Report NUREG-0675,* Supplements issued as follows:
B-2 Supplement No. 18, issued August 1983.*
B-3 Supplement No. 19, issued October 1983.*
B-4 Supplement No. 20, issued December 1983.*
B-5 Supplement No. 21, issued December 1983.*
B-6 Supplement No. 22, issued March 1984.*
B-7 Supplement No. 24, issued July 1984.*
B-8 Supplement No. 25, issued July 1984.*
B-9 Supplement No. 26, issued July 1984.*
B-10 Pacific Northwest Laboratory, Report No. PNL-5161, " Review and Evaluation of TDI Diesel Generator Owners' Group Program Plan," published June 1984.**
B-11 Letter from Darrell G. Eisenhut, Director, Division of Licensing, NRC Office of Nuclear Reactor Regulation, to J. B. George, Chairman, Transamerica Delaval, Inc. Owners Group, Texas Utilities Generating Company, forwarding
" Safety Evaluation Report, Transamerican Delaval, Inc.
Diesel Generator Owners Group Program Plan," Docket Nos. 50-322/416-417/206/312/458-459/
400-401/413-414/440-441/438-439/445-446/424-425/329-330/460, August 13, 1984.**
C-1 U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 84-55, " Seal Table Leaks at PWRs," July 6, 1984.**
C-2 Letter from Steven A. Varga, Chief, Operating Reactors Branch 1, Division of Licensing, NRC Office of Nuclear Reactor Regulation, to John D. O'Toole, Vice President, Consolidated Edison Company of New York, forwarding the safety evaluation of the ultrasonic flaw indication detected in the Indian Point Unit 2 reactor pressure vessel, Docket No. 50-247, October 16, 1984.**
- Available in NRC Public Document Room, 1717 H Street, NW., Washington, DC 20555 for inspection.
Available for purchase from NRC-GPO Sales Program, DivisIonofTechnicalInformationandDocumentControl,U.S.NuclearRegulatory Commission, Washington, DC 20555.
C*Available in NRC Pubile Document Room, 1717 H Street, NW., Washington, DC 20555, for inspection and copying (for a fee).
57
leRC pores 333 U S. NUCLEAR REGUL ATORV COMussat04 1 A t + f Nu v e e d #4ss<,aea.F IJOC. 8dd FOi %D. 88 StFJ
'hE BIBLIOGl4APHIC DATA SHEET 3
Sit INSfasCTIONS ON THE RivtR$t 3 sif Lt AND SystiTLE 3 LE4veSLANn Rrpor t to Corgress on Abnormal Occurrences July-Septembi 1984
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.t.R ri1 1QM F Ptm.QRW4NG QRGAN12 AflON NAME A W AILING ADDRE SS nacwee le c. des aPROJ. T ASK WORE UNt f NVUSER Office for Analysis d Evaluation of Operational Data I
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to SPONiumeNG ORG AN62 AfiON N AME AND W Ast !NG a t.5 star 4m te Codes i t. 7VPtceREPORY Office for Analysis and Eva ation of Operational Da U.S. Nuclear Regulatory Com sion Quarterly
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Washington, DC 20555 Julv-Seotember 1984 T 2 SUPPLt WE NT AR Y NOf t S o&.if..c,,m r,
Section 208 of the Energy Reorganization of 1974 identifies an abnormal occurrence as an unscheduled incident or event which Nuclear Regulatory Commission determines to be significant from the standpoint of gibb c health and safety and requires a quarterly report of such events to be macp to ongress.
This report covers the period July 1 to September 30, 1984 During t repo period, there were four abnormal cccurrences at the nuclear power plant license o operate.
These involved degraded isolation valves in emergency core co ng system degraded shutdown systems, a loss of offsite and onsite AC electrical p er, and a r ueling cavity water seal failure, rCspectively. There was one abnorma occurrence at fuel cycle facility; the event involved degraded material access a a barriers.
The were four abnormal occurrences at the other NRC licensees. One i olved contaminated adiopharmaceuticals used in sev:ral diagnostic administration Two involved thera utic medical misadministra-tiens. The other involved signif cant internal exposure iodine-125 to a hospital employee.
There was one abnorma. occurrence reported by a Agreement State; the ev:nt involved contaminated rad pharmaceuticals used in se ral diagnostic admin-abn:rmal occurrences.
. previously reported istrations.
The report also c tains information updating s
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..R i Isolat n Valves; Shutdown Systems; Loss of AC Power; unciancifind Refueling Cavity Water S al failure; Material Access Area Carriers;
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Fuel Cycle Facility; Con aminated Radiopharmaceuticals; Nuclear une13eettina Pharmacies; Diagnostic 0 crexposures; Therapeutic Medical Misadministra-
" N M ' u ra m tions; Medical Instituti ns; Significant Internal Exposure to Hospital 4**'"
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