ML20214L441

Report to Congress on Abnormal OCCURRENCES.July-September 1986

ML20214L441
Person / Time
Issue date:	04/30/1987
From:	NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
To:
References
NUREG-0090, NUREG-0090-V09-N03, NUREG-90, NUREG-90-V9-N3, NUDOCS 8705290301
Download: ML20214L441 (60)

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NUREG-0090 Vol. 9, No. 3 Report to Congress on Abnormal Occurrences i July-September 1986 l

U.S. Nuclear Regulatory i Commission Office for Analysis and Evaluation of Operational Data ps** "%s i

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Available from Superintendent of Documents U.S. Government Printing Office Post Office Box 37082 Washington, D.C. 20013-7082 A year's subscription consists of 4 issues for this publication.

Single copies of this publication are available from National Technical Information Service, Springfield, VA 22161

NUREG-0090 Vol. 9, No. 3 Report to Congress on Abnormal Occurrences July-September 1986 DJ,t3 Published: April 1987 i Office for Analysis and Evaluation of Operational Data U.S. Nuclear Regulatory Commission WIshington, DC 20556 i

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Previous Reports in Series NUREG 75/090, January-June 1975, NUREG-0090, Vol. 4, No.1 January March 1981, published October 1975 pubitshed July 1981 NUREG-0090-1, July-September 1975 NUREG-0090, Vol.4, No.2, April-June 1981, '

pubitshed March 1976 published Oc~tober 1981 NUREG-0090-2, October-December 1975, NUREG-0090, Vol.4, No.3, July-September 1981, published March 1976 . published January 1982 NUREG-0090-3, January-March 1976 NUREG-0090, Vol.4, No.4, October-December 1981, ,

pubitshed July 1976 pubitshed May 1982 NUREG-0090-4, April-June 1976, NUREG-0090, Vol. 5, No.1, January March 1982 published March 1977 published August 1982 NUREG-0090-5, July-September 1976 NUREG-0090 Vol.5, No.7, April-June 1982, pubitshed March 1977 published December 1982 NUREG-0090-6, October-December 1976, NUREG-0090, Vol.5, No.3, July-September 1982, published June T 7 published January 1983 NUREG-0090-7, January March 1977, NUREG-0090 Vol.5, No.4, October-Deceber 1982, '

pubitshed June 1977 published May 1983 NUREG-0090-8 April-June 1977, NUREG-0090, Vol.6, No.1, .lanuary March 1983, published September 1977 published September 1983 NUREG-0090-9, July-September 1977, NUREG-0090, Vol.6, No.2, April-June 1983, pubitshed November 1977 published November 1983 NUREG-0090-10, October-December 1977 NUREG-0090, Vol.6, No.3, July-September 1983, published March 1978 published April 1984 NUREG-0090 Vol.1, No.1, January-March 1978, NUREG-0090, Vol.6,' No.4, October-December 1983, published June 1978 published May 1984 NUREG-0090 Vol.1, No.2. April-June 1978 NUREG-0090, Vol 7, No.1, January March 1984, published September 1978 published July 1984 NUREG-0090, Vol.1, No.3, July-September 1978, NUREG-0090, Vol 7, No.2, Apett-June 1984, published December 1978 published October 1984 NUREG-0090, Vol.1, No.4, October-December 1978 NUREG-0090 Vol.7, No.3, July-September 1984, published March 1979 published April 1985

, NUREG-0040, Vol.2 No.1, January-March 1979, NUREG-0000. Vol.7, No.4, October-December 1984,

! published July 1979 pubitshed May 1985 NUREG-0090, Vol .2, Nn ?, Aortl-June 1979 NUREG-0090, Vol.8, No.1, Januarv March 1985, published November 1979 published August 1985 NUREG-0090, Vol.2, No.3, July-September 1979, NUREG-0090, Vol.8, No.2, April-June 198$.

published February 1980 published November 1985

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NUREG-0090. Vol .2, No.4, October-December 1979, NUREG-0090, Vol.8, Ko.3, July-September 1985 l published April 1980 published February 1986 I

NUREG-0090, Vol .3, No.1, January-March 1980 NUREG 0090, Vol.8, No.4, October December 1985, published September 1980 published May 1986 NUREG 0090, Vol.3, No.2, April-June 1980 NUREG-0090, Vol.9, No.1, January March 1986, published Novertber 1980 published September 1986 NUREG-0090, Vol.3, No.3, July $eptember 1980 NUREG-0090, Vol.9 No.2, April-Jure 1986, pubitshed February 1981 Pubitshed January 1987 NUREG 0090 Vol.3, No.4, October-December 1980, published May 1981

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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, 1986.

The report states that for this reporting period, there.were four abnormal occurrences at the nuclear power plants licensed to operate. The events were (1) a differential pressure switch problem in safety systems at LaSalle facil-1 ity, (2) abnormal cooldown and depressurization transient at Catawba Unit 2,

(3) significant safeguards deficiencies at Wolf Creek and Fort St. Vrain, and

< (4) significant deficiencies in access controls at River Bend Station. There was one abnormal occurrence at the other NRC licensees; it involved a therapeu-

tic medical misadministration. There was one abnormal occurrence reported by

, an Agreement State; it involved a therapeutic medical misadministration.

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The report also contains information updating some previously reported j abnormal occurrences.

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i CONTENTS P_ag ABSTRACT ......................................................... i ii PR E F AC E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

, ' INTRODUCTION ................................................ vii i THE REGULATORY SYSTEM ....................................... vii REPORTABLE OCCURRENCES ...................................... viii

-AGREEMENT STATES ............................................ ix FOREIGN INFORMATION ......................................... x j

REPORT TO CONGRESS ON ABNORMAL OCCURRENCES, JULY-SEPTEMBER 1986 .. 1 I

NUCLEAR POWER PLANTS ........................................ 1 i

i' 86-15 Differential Pressure Switch Problem in Safety Systems at LaSalle Facility ...................... 1 1 86-16 Abnormal Cooldown and Depressurization

Transient at Catawba Unit 2 ....................... 6 j 86-17 Significant Safeguards Deficiencies-

, at Wolf Creek and Fort St. Vrain .................. 9

! 86-18 Significant Deficiencies in Access Controls i j at River Bend Station ............................. 11 ,

! FUEL CYCLE FACILITIES (Other than Nuclear Power Plants) ..... 12 l OTHER NRC LICENSEES (Industrial Radiographers, Medical Institutions, Industrial Users, etc.) ..................... 12 i'

86-19 Therapeutic Medical Misadministration ............. 13 AGREEMENT STATE LICENSEES ................................... 15 J

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AS86-7 Therapeutic Medical Misadministration ............. 15 REFERENCES ....................................................... 17

. APPENDIX A - ABNORMAL OCCURRENCE CRITERIA ........................ 19

) APPENDIX B - UPDATE OF PREVIOUSLY REPORTED ABNORMAL OCCURRENCES .. 21 NUCLEAR POWER PLANTS ........................................ 21 l

79-3 Nuclear Accident at Three Mile Island ............. 21 85-7 Loss of Main and Auxiliary Feedwater Systems . . . . . . 24 85-14 Management Deficiencies at Tennessee i Valley Authority .................................. 24 j

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85-20 Management Deficiencies _at' Fermi Nuclear Power Station ............................. 29 86-2 Loss of Integrated Control System Power and Overcooling Transient ................... 30 86-9 Emergency Core Cooling System Mini-Flow Design Deficiency ....................... 32' FUEL CYCLE FACILITIES ....................................... 34 86-3 Rupture of Uranium Hexafluoride Cylinder and Release of Gases .......................................... 34 OTHER NRC LICENSEES ................. .......................

. 35 85-4 Unlawful Possession of' Radioactive Material ....... 35 86-7 Tritium Overexposure and Laboratory Contamination ..................................... 36 APPENDIX C - OTHER EVENTS OF INTEREST ............................ 37 REFERENCES (FOR APPENDICES) ...................................... 45 vi

PREFACE INTRODUCTION The Nuclear Regulatory Commission reports to the Congress each quarter under provisions of Section 208 of the Energy Reorganization Act of 1974 on any abnnrmal occurrences 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 l 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 occurrence reporting. This report covers the period from July 1 to September 30, 1986.

Information reported on each events includes: date and place; nature and prob-able consequences; cause or causes; and actions taken to prevent recurrence.

THE REGULATORY SYSTEM The system of licensing and regulation by which NRC carries out its responsi-bilities is implemented through rules and regulations in Title 10 of the Code 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 stan-dards and rules; issuing licenses and permits; inspecting for compliance; en-forcing license requirements; and carrying on continuing evaluations, studies and research projects to improve both the regulatory process and the protection of the public health and safety. Public participation is an element of the regulatory process.

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 which will assure the safe use of nuclear materials. The regulations include design vii

1 and quality assurance criteria appropriate for the various activities licensed by NRC. An inspection and enforcement program helps assure compliance with the regulations.

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 processed periodically and the exposure results normally serve as the official 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 and has been sufficiently low, NRC regulations permit an individual in a restricted area to receive up to three rems of whole body exposure in a calendar quarter. Higher values are permitted to the extremities or skin of the whole body. For unre-stricted areas, permissible levels of radiation are considerably smaller. Per-missible 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 Actual operating experience is an essential input to the regulatory process for assuring that licensed activities are conducted safely. Reporting requirements 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 infor-mation, and to feed back the experience into licensing, regulations, and operations.

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 qual-ity, of reports required to be submitted, but also the method used to analyze the data. Two primary sources of operational data are reports submitted 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 (INP0), a nuclear utility organization.

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 licensees' technical specifications, and/or in license provisions. In order to more effectively collect, collate, store, retrieve, and evaluate the information 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 effectiveness of data processing and the quality of reports required to be submitted by the licensees.

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l Effective January 1, 1984, major changes were made to the requirements to re-port 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 for all nuclear power plant licensees and eliminate reporting of events which were of low individual significance, while requiring more thorough documentation and analyses by the licensees of any events required to be reported. All such re-I ports are to be submitted within 30 days of discovery. The revised system also i

permits licensees to use the LER procedures for various other reports required i

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-Supplements 1 and 2 to NUREG-1022.

Also effective January 1,1984, the NRC amended its immediate notification re-quirements of significant events at operating nuclear powe* 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 terminology reportingthresholdsthataresimilartothoseof10CFR$ phrasing,and 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.

i 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 July 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. INP0 reports that significant improvements in licensee participation are being made. The Commission considers the NPRD sys-tem to be a vital adjunct to the LER system for the collection, review, and feedback of operational experience; therefore, the Commission periodically moni-tors 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 l 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.

The Congress is routinely kept informed of reportable events occurring in l

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AGREEMENT STATES Section 274 of the Atomic Energy Act, as amended, authorizes the Commission to enter into agreements with States whereby the Commission relinquishes and the ix l

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States assume regulatory authority over byproduct, source and special nuclear materials (in quantities not capable of sustaining a chain reaction). Compara-ble and compatible programs are the basis for agreements.

Presently, information on reportable occurrences in Agreement State licensed.

activities is publicly available at the State-level. Certain information is also provided to the NRC under exchange of information provisions in the agreements.

In early 1977, the Commission determined that abnormal occurrences happening at facilities of Agreement State licensees should be included in the quarterly reports to Congress. The abnormal occurrence criteria included in Appendix A is applied uniformly to events at NRC and Agreement State licensee facilities.

Procedures have been developed and implemented and abnormal occurrences reported by the Agreement States to the NRC are included in these quarterly reports to Congress.

FOREIGN INFORMATION 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 OCCURRENCES JULY - SEPTEMBER 1986 NUCLEAR POWER PLANTS b

The NRC is reviewing events reported at the nuclear power plants licensed to operate during the third calendar quarter of 1986. As of the date of this report, the NRC had determined that the following events were abnormal occurrences.

86-15 Differential Pressure Switch Problem in Safety Systems at LaSalle Facility The following information pertaining to this generic problem is also beirg reported concurrently in the Federal Register. Appendix A (see the second general criterion) of this report notes that majnr degradation of essential safety-related equipment can be considered an abnormal occurrence. In addition, Example 12 of "For All Licensees" in Appendix A notes that incidents with impli-cations for similar facilities (generic incidents), which create major safety concern, can be considered an abnormal occur mice.

Date and Place - On June 1, 1986, LaSalle Unit 2 experienced a feedwater transient that resulted in low water level in the reactor vessel. The level reached a point where an automatic reactor scram would be expected; however, no such scram occurred. LaSalle County Puclear Power Station consists of two Units, each utilizing a General Electric-designed boiling water reactor., The Station is operated by Commonwealth Edison Company (the licensee) and is located in LaSalle County, Illinois.

Subsequent investigation found that the P oblem was caused primarily y I inadequate calibration of mechanical diherential aressure switches st.pplied by 50R, Incorporated (formerly Static "0" Ring Pressure Switch Company). Similar switches have been installed in safety systems at many nuclear power plants.

Background - 10 CFR S50, Appendix A, General Design Criterion 21 (" Protection System Reliability and Testability") requires that the reactor protection system be highly reliable. Recent experience with SOR mechanical differential pres-sure switches at LaSalle (as described below) and similar experience at Oyster Creek has strongly suggested that this may not be the case if the switches are not adequately calibrated.

Earlier concern for mechanical level indication equipment was expressed in NRC Generic Letter No. 84-23 (Ref. 1) which addressed water level instrumentation for boiling water reactor (BWR) reactor vessels. The generic letter was based on NRC's evaluation of a report by S. Levey, Incorporated, which had been com-missioned by a BWR Owner's Group. The generic letter addressed the need for BWR licensees to review plant experience related to mechanical level indication equipment, indicated that analog trip units have better reliability and greater accuracy than mechanical level indication equipment, and stated that BWR licensees should replace such equipment with analog transmitters unless operating experience indicates otherwise. Responses to Generic letter No. 84-23 have shown that 80% of BWR licensees have replaced or plan to replace their mechanical level instrumentation with analog level transmitters.

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S0R mechanical differential pressure switches have been installed by many licensees predominantly as environmentally qualified electrical equipment impor-tant to safety, as described in 10 CFR $50.49(b). The licensee for LaSalle Unit 2 installed SOR Series 103 differential pressure switches in mid 1985 as part of an environmental qualification modification which was performed after initial operation of the unit. Identical switches were also installed in LaSalle Unit 1. LaSalle Units 1 and 2 each have about 60 of these switches in various systems, including the reactor protection system and the emergency core cooling system.

Nature and Probable Consequences - At about 4:21 a.m. (CDT) on June 1, 1986, LaSalle Unit 2 was operating at 93 percent of full power. Both turbine-driven feedwater pumps were operating, with the "A" pump in manual control and the "B" pump in automatic control. The motor-driven feedwater pump was in standby.

While a surveillance test was being conducted on feedwater pump "A", the turbine governor valve unexpectedly opened further resulting in an increase in pump output and,a corresponding rise in reactor water level. At about the same time, the automatic control systems for both turbine-driven pumps locked out. The reactor operator regained control of feedwater pump "A" and ran back the feed-water pump's' speed in an attempt to restore the normal water level. A few seconds later when the "B" reactor feedwater pump's control system was reset, the "B" feedwater pump controller automatically ran back the pump speed to zero.

Reactor water level started falling at about 2 inches /second.

Subsequently, separate reactor water level switches responded to the falling reactor water level by reducing recirculation flow to reduce power, and the operator started the motor-driven feedwater pump to increase level. The level continued to fall for a few more seconds before the flow from the motor-driven pump began to raise the water level. The minimum reactor scram setpoint required in the technical specification is 11 inches. (This point is 11 inches above a water level specified as " instrument zero," which is a measuring reference point. Instrument zero is approximately 13 feet above the top of the reactor core; all levels indicated here are above instrument zero.) There are four water level sensing switches, each normally set to trip at 13.5 inches above instrument zero, and reactor operators are trained to expect a reactor trip by the time the water level reaches 12.5 inches. The switches are in pairs (two each in two circuits, called channels), and one switch in each pair must trip in order for there to be a reactor scram signal generated.

As the water level was falling, one of the four switches tripped at approximately 10 inches; the other three did not actuate, and therefore no scram signal occurred. (With a switch tripped in just one channel, the condition is called a " half scram.")

The subsequent investigation indicated that the reactor water level fell briefly to a minimum level of 4.5 inches (above instrument zero, but more than 13 feet above the reactor fuel). The water level was below the scram setpoint for about two seconds before the increased feedwater flow increased the level.

During the incident, the reactor operators did not have sufficient data to eval-uate the water level drop and the failure of the differential pressure switches to actuate. Shortly after the subsequent shift change, the oncoming thift engineer's review indicated that the reactor water level appeared to have fallen 2

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below the scram setpoint and the level switches may not have performed properly. '

After further review, the licensee believed that a malfunction of the scram system may have occurred. Based on this concern, the licensee declared an

" Alert," started an orderly shutdown of the plant, and notified the NRC. The licensee subsequently notified SOR, Incorporated, of possible malfunctions involving its Series 103 mechanical differential switches. The Alert was terminated at 9:22 a.m., June 2, 1986, when all control rods were inserted.

I On June 2, 1986, the NRC determined that the incident warranted a thorough investigation. The Administrator for NRC Region III sent an Augmented Inspection Team (AIT) to the site to investigate the root cause and significance of the feedwater transient, the performance of the differential pressure switches in the low 1avel trip channels, the response of the reactor protection system, and related matters.

The licensee continued testing of the reactor scram water level switches; the additional data demonstrated continued erratic behavior of switch setpoints.  ;

As of June 9, 1986, the licensee had also tested SOR Series 103 switches in the residual heat removal system and the high pressure core spray systems. Similar erratic results were found; therefore, all SOR Series 103 switches used in the plant became suspect. The licensee declared all emergency core cooling systems in both units to be inoperable. At the time of the incident, Unit 1 was shut down for its first refueling outage. Both units were kept in cold shutdown

while the investigations continued, i Most of the tests performed at LaSalle Units 1 and 2 showed erratic setpoints for the Series 103 switches and, in one case, the switch failed to operate at all. During the vessel water level drop tests at LaSalle 1 on June 2, one of two Series 103 switches used to provide a confirmatory water level input signal to the automatic depressurization system failed to function. On June 25, the switch was disassembled and inspected. Rust (severe corrosion) was found inside the switch assembly and probably caused a cross shaft bearing, which is outboard of the 0-rings, to seize.

The event at LaSalle was not the first indication of erratic behavior of SOR mechanical differential pressure switches. A precursor event had previously occurred at Oyster Creek Unit 1 on January 17, 1986, during monthly surveillance of four SOR differential pressure switches which detect low water level in the reactor vessel. The "as-found" setpoints for three of the switches had drifted downward as much as 6 inches. During the subsequent 11 weeks, the level switches continued to perform erratically; each switch was replaced one or more times; ,

and modified switches were installed. On April 7, after a modified switch had nonconservative setpoint drift, the licensee performed daily surveillance until about April 12 when the reactor was shut down for a six month outage. Increased surveillance frequency did not resolve the problem. (At LaSalle, however, changing the setpoint and increasing the suneillance testing of the switches have resulted in acceptable performance.)

50R, Incorporated also manufacturers Series 102 mechanical differential pressure switches. Therefore, all Series 102 and 103 switches installed in BWR and pres-surized water reactor (PWR) plants were suspect. Use of such possibly erratic behavior switches in reactor scram systems and various engineered safety features i

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raises serious concern regarding the safety and health of plant personnel and the public. Such systems are designed and installed in plants to prevent the occurrences, or ameliorate the effects, of serious accidents.

Problem Areas - A review of the testing performed at LaSalle, and discussions with the manufacturer, show that there are several potential problems that could account for the erratic behavior of Series 102 and 103 switches. These problems include a shift of the setpoint caused by calibration under atmospher M pressure instead of actual operation pressures; a shift in setpoint which occurs as the switch is subjected to constant pressure over a period of time; setpoint varia-tion depending on whether the setpoint is approached from the high side or the low side; and a tendency, in some cases, for the switches to " stick," i.e. , to require a higher differential pressure to actuate the switch on the first actua-tion than on later actuations.

At LaSalle, the licensee has successfully compensated for these phenomena by setting the setpoint to account for the setpoint shift, which occurs under actual operating conditions and, further, by checking the calibrations periodically.

The manufacturer is conducting long range tests with switches which have a more highly polished shaft to minimize the " stickiness" that may have affected the actuating setpoint. Also the LaSalle plant is using the first test of the switches after they have not been actuated for a period of time, rather than actuating the switches several times before performing the test, which had been the previous practice. This testing provides a more accurate determination that the switches would function as intended.

Although there is no evidence to suggest that it was involved in the LaSalle switch performance, another factor that is under review is the affect of aging and exposure to reactor water on the 0-ring materials and other components of the differential pressure switches.

Cause or Causes - The problems with the Series 103 switches at LaSalle appear to be associated with the licensee's procedures for testing them, and a possible design deficiency resulting in occasional " sticky operation."

Actions Taken to Prevent Recurrence Licensee - Commonwealth Edison Company undertook an extensive testing program to evaluate the nature of the SOR switch problem at LaSalle. This testing determined that the switches, if properly calibrated to include the predicted setpoint shift, can continue to be used in their current applications. The licensee and the manufacturer are testing the switches on a more frequent basis over long time periods to assure their continued operability.

NRC - The licensee's investigation of the water level switch problem was ini-tially monitored by the resident inspectors. As previously mentioned, an NRC AIT was later dispatched to the site on June 2, 1986, to evaluate the incident and the nature of the switch problem and corrective actions. The NRC's Office of Nuclear Reactor Regulation reviewed the results of the tests performed by the licensee and the vendor and concluded that the SOR Series 102 and 103 differential pressure switches could remain in service until NRC reviewed the licensee's long-term plans.

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The NRC AIT's report, Inspection Report No. 50 374/86-23, was issued on September 17, 1986 (Ref. 2).

On June 10, 1986, Inspection and Enforcement Inforcation Notice No. 86-47 (Ref. 3) was issued to inform licensees of the erratic behavior of SOR differen-tial pressure switches during the incident at LaSalle 2 on June 1 and during subsequent testing. An attachment to the Notice listed licensees to which SOR had supplied Series 103 differential pressure switches. The informatim notice also announced a public meeting of representatives from NRC, General Electric Company, SOR, and interested licensees to discuss the application and performance of Series 102 and 103 switches in safety-related systems, which was held on June 12, 1986.

Since the SOR differential pressure switches were installed by many licensees predominantly as environmentally qualified electrical equipment important-to-safety, Inspection and Enforcement Bulletin No. 86-02 (Ref. 4) was issued on July 18, 1986, to update the information provided in Notice No. 86-47 and to ensure that all licensees currently using the SOR switches in safety-related systems were taking appropriate remedial actions. Licensees with SOR switches installed were requested per the Bulletin to determine which of those Switches are installed in systems which are subject to Limiting Conditions for Operations of the plant Technical Specifications. For SOR differential switches that are not in systems subject to Technical Specifications, licensees were expected to review the information in the Bulletin and consider actions, if appropriate, to preclude problems similar to those discussed in the Bulletin from occurring.

For SOR differential pressure switches that were installed in systems subject to Technical Specifications, the Bulletin requested licensees to take certain actions to assure that these switches and systems will be capable of performing acceptably, if called upon during an actual plant transient or accident.

First, the Bulletin requests that each licensed reactor operator (and senior reactor operator) on duty be made aware of the potential problem that may occur at their plant in terms of where SOR differential pressure switches are installed in their plant, how to detect a malfunction or failure of any of these switches, and the remedial actions that they should be prepared to take if a malfunction were to occur.

Second, the Bulletin equests licensees to conduct special operability tests of each system that is subject to Technical Specifications that involve SOR differential pressure switches. Special tests are necessary to determine the actual trippoint of the switches and the operability of the systems since tests of the type typically conducted may not be adequate to reveal the type of prob-lems that have been revealed at the LaSalle station.

Lastly, the Bulletin requests licensees to determine what long-term corrective actions may be appropriate and will be taken, including consideration of the potential effects of common mode failures. The NRC staff is currently reviewing reports made by licensees in response to the Bulletin.

Future reports will be made as appropriate.

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l 86-16 Abnormal Cooldown and Depressurization Transient at Catawba Unit 2 The following information pertaining to this event is also being reported con-currently in the Federal Register. Appendix A (see Example 4 of "For Commercial Nuclear Power Plants") of this report notes that discovery of a major condition not specifically considered in the safety analyses report (SAR) or technical specifications that requires immediate remedial action can be considered an abnormal occurrence.

Date and Place - On June 27, 1986, while Duke Power Company (the licensee) was conducting a startup test at Catawba Unit 2 from remotely located control panels, the reactor experienced an unexpected depressurization and cooldown. Catawba Unit 2 utilizes a Westinghouse-designed pressurized water reactor and is located in York County, South Carolina.

Background - On February 24, 1986, the licensee was issued a fuel loading and low power (up to 5%) license for Catawba Unit 2. The Unit achieved initial criticality on May 8, 1986. A full power license was issued on May 15, 1986; however, some startup tests had to be completed before the plant could be taken to full power.

During the morning of June 27, 1986, the licensee planned to perform a Loss of Control Room Functional Test (procedure TP/2/A/2650/03) to fulfill one of the commitments for startup testing delineated in its Final Safety Analysis Report (FSAR).

The purposes of the test are to demonstrate:

a. That the plant can be brought to Hot Standby conditions from a moderate power level (10-25%) using Auxiliary Shutdown Panel (ASP) controls and following procedure AP/2/A/5500/17 (Loss of Control Room).

b. That the plant can be maintained at Hot Standby conditions for 30 minutes from the ASPS.

c. That the plant can be brought to Hot Standby and maintained in that condi-tion with the minimum shift requirements of Technical Specifications (five people).

d. That the reactor ccolant system (RCS) can be cooled down at least 50 degrees F from a steady state Hot Standby condition while being operated from the ASPS.

The test would be performed by a crew of five (simulating the minimum shift I crew available to Unit 2 operations) leaving the control room (since this was I a test, the control room would remain fully staffed by the regular operations  ;

shift), tripping the reactor, and proceeding to remote shutdown panels. At  !

these panels, the crew would saitch reactor control to these panels and proceed with the test.

Nature and Probi le Consequences - At 9:41 a.m. on June 27, 1986, the test was initiated with the reactor at 24% power. The crew of five left the control room, tripped the reactor from the trip breaker panel, and proceeded to the two 6

l 9

remotely-located ASPS and the auxiliary feedwater pump turbine control panel (AFWPTCP).

At the ASPS and AFWPTCP, switches were activated transferring control of vital functions from the control room to the auxiliary panels. By design, the trans-fer blocked automatic initiation of safety injection (SI). By error, the trans-fer of control of steam generator (S/G) power operated relief valves (PORV) to the AFWPTCP also commanded all four PORVs to open to seventy-five percent of full stroke. Reactor pressure and pressurizer level, which had been decreasing slowly as a result of the cooldown after the trip, fell rapidly. Within a minute of the transfer, pressurizer level indication was lost; and within two core minutes, pressure had dropped below 1845 psig generating an SI demand signal. After another three and one-half minutes of unsuccessful attempts to manage the situation from the ASPS and AFWPTCP, control was returned to the control room which was staffed by the regular operations shift. The transfer, which automatically initiated a SI, occurred at a pressure of 702 psig. After approximately 5 minutes, pressurizer level was restored to a level near 34 percent, with a presure of 1250 psig, and about 100 F subcooling. At this point the operaters had full control of the stabilized plant.

The cooldown and depressurization transient did not result in any adverse thermo-hydraulic or nuclear effects on the plant; there were no actual consequences to public health or safaty. However, if the decay heat load of the reactor core had been greater and if the use of the remote shutdown panels had been actually required during a plant emergency, a more severe transient could have occurred.

NRC Resident Inspectors were on site witnessing the test. The NRC Region II Office was notified and an Augmented Inspection Team (AIT), regional plus headquarters staff participants, was sent to the site from the Regional Office to investigate the event. The licensee began investigating the cause of the event and agreed not to restart the reactor without NRC concurrence; this was confirmed by a Region II Confirmation of Action Letter sent to the licensee on June 30, 1986 (Ref. 5). The AIT made their inspection from June 28 through July 2,1986, and numerous deficiencies were identified in the areas of human factors, procedures, equipment labeling, retraining of personnel, and equipment repair. On July 3,1986, Region II issued a Confirmation of Action Letter documenting the licensee's commitment to develop a detailed restart plan which deals with the corrective actions necessary to correct the deficiencies (Ref. 6).

In addition, the licensee agreed to rerun the Loss of Control Room Functional Test, after attaining the requisite power rating to adequately demonstrate that the plant can be safely shut down and cooled down from the auxiliary shutdown station following evacuation of the control room.

Cause or Causes - The underlying cause of this event was the failure to specify in the Design Control documents that the mode of control of the S/G PORV con-trollers at the AFWPTCP had been changed. This, in turn, led to a failure by station personnel to change procedures and to train operators on this modifica-tion. The situation was further exacerbated by human engineering deficiencies introduced by the modifications. As a consequence, the staff assigned to per-form the test did not understand the function and interaction of controls on the shutdown panels. This lack of understanding led to a pretest setup of the panels that ensured that the PORVs would open on transfer and that attempts to shut them would be futile. Other human engineering factor failures led to 7

reducing charging pump flow to the reactor coolant pump seals by the very attempts to increase flow.

Although the main control room PORV controllers had been replaced with safety-related controllers, the licensee chose not to replace or modify the AFWPTCP controllers. Also, no human engineering deficiency review was performed on the shutdown panels.

Other contributing factors to this event included inadequate training on the shutdown panel instruments and controls, inconsistencies in labeling of instru-ments and controls, lack of termination test criteria, and reluctance by the control room crew to assist the shutdown panel crew for fear of invalidating the test.

Actions Taken to Prevent Recurrence Licensee - In accordance with the restart plan, the licensee has taken the following corrective actions:

a. A review of all Design Changes and Construction Department Shutdown Requests implemented after hot functional testing and prior to fuel load was per-formed prior to Unit 2 re-entering Mode 2, Startup.

b. A review of both Units ASPS and AFWPTCPs was performed to identify all differences between Units and all human engineering deficiencies. Numerous Unit differences and labeling problems were identified. Labeling problems were corrected.

c. Revisions were made to Operating and Abnormal Procedures to reflect changes required as a result of Corrective Action b above. Also instructions were added to manually initiate SI, Containment Spray, and Annulus Ventilation if required following a loss of Control Room Incident. Test termination criteria were also clarified in the test procedure.

d. A new procedure was developed and performed, to verify proper function of various valves while controlling at the ASPS.

e. An existing procedure, Controlling Procedure for Power Escalation, was revised to include more thorough pre-transient test preparation and walk throughs. This will include reviews of previous test results, Operating Procedures, Abnormal Procedures, and Emergency Procedures.

f. Various problems were identified with Operator Aid Computer indication.

The problems are being investigated.

g. Personnel had difficulty controlling reactor coolant pump seal flow during the event. Additional labeling on the ASPS was added to clarify control requirements for 2NV-309, Seal Injection Flow Control Valve. The appro-priate operations procedures were also revised to clarify use of the valve.

h. 2NV-148A, Letdown Pressure Control Valve, failed open during the the event following transfer to the ASP. A poor electrical connection in the control circuitry was found and corrected. The control circuit for the valve had 8

l l

l l maintenance performed on it in January 1986. It is not certain if the poor connection was the result of this previous maintenance activity.

i. Difficulty was encountered during the event in resetting the main steam isolation bypass valves. The problem could not be recreated during inves-tigation. The associated Monthly Surveillance Test was performed successfully.

Following the above, the plant was restarted. After reaching 20% power on July 11, 1986, the licensee satisfactorily reperformed the Loss of Control Room Functional Test. Subsequently, the plant reached 100% power and on August 19, 1986, the licensee declared the plant to be in commercial operation.

NRC - The NRC monitored the licensee's corrective actions to assure that they were responsive and satisfactory before permitting the plant to restart.

On November 12, 1986, the NRC forwarded to the licensee a Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $50,000 (Ref. 7).

The first violation pertained to a significant failure in the licensee's design control program. The second violation pertained to the licensee's failure to establish adequate procedures for the Loss of Control Room Test.

The NRC AIT's report was issued on July 25, 1986 (Ref. 8).

This incident is considered closed for the purposes of this report.

86-17 Significant Safeguards Deficiencies at Wolf Creek and Fort St. Vrain The following information pertaining to this event is also being reported con-currently in the Federal Register. Appendix A (see Example 8 of "For All Licensees") of this report notes that any substantial breakdown of physical security, such as access control, that significantly weakened the protection against theft, diversion, or sabotage, can be considered an abnormal occurrence.

Date and Place - On July 7,1986, NRC Region IV issued enforcement letters containing Severity Level II violations to the licensees of two nuclear power plant stations for serious deficiencies in plant physical barriers. The li-censees are: (1) Kansas Gas and Electric Company (KG&E), operator of the Wolf Creek Generating Station, a Westinghouse-designed pressurized water reactor located in Coffey County, Kansas; and (2) Public Service Company of Colorado (PSC), operator of Fort St. Vrain, a General Atomic Corporation-designed high-temperature, gas-cooled reactor located in Weld County, Colorado.

Nature and Probable Consequences - The July 7, 1986 letters identified serious failures of the licensees to comply with NRC regulatory requirements pertaining to physical barriers. In the most serious example, it was determined at the Wolf Creek Generating Station that multiple uncontrolled access paths existed from the Owner Controlled Area (0CA) into the Protected Area (PA) and in two instances into Vital Areas (VAs). This condition was identified by the licensee as part of a quality assurance surveillance followup and confirmed by a Region IV safeguards specialist during reactive inspection No. 50-482/85-44 (Ref. 9). At the Fort St. Vrain Nuclear Station, NRC inspectors identified 9

during routine inspection No. 50-267/85-32 (Ref. 10) two uncontrolled access paths from the OCA to the PA and VA. In this situation, each access had a barrier installed, but each was evaluated to be inadequate and not capable of preventing an intruder from defeating it easily.

In these examples, conditions existed whereby an intruder could have obtained unauthorized and undetected access into protected and/or vital areas from the OCA. It appeared from the inspections and review of licensee records that the conditions had existed at both plants for a minimum of six to seven months.

Cause or Causes - The cause of these occurrences was a failure in management control, including design oversight during the system planning stages, con-struction deficiencies, and the failure of the startup testing / surveillance program to identify these deficiencies. Another related cause at the Wolf Creek Generating Station was the failure of management to provide coordination among the various organizational entities which may affect facility security.

Actions Taken to Prevent Recurrence Licensees - In each case identified, the licensee took immediate corrective action to post compensatory guards and install appropriate barriers. At Fort St. Vrain Nuclear Station, the affected piping was secured with adequate bar-riers and a routine surveillance was initiated to ensure that no degradation to these and similar barriers had occurred. The Wolf Creek Generating Station installed acceptable barriers where required and initiated a complete walkdown of the PA and VA to identify all possiule points of vulnerability. This work is being conducted by a KG&E Security Passive Barrier Task Force that was formed to review all penetrations in passive barriers to assure that no further problems exist.

Both licensees have modified engineering / design change procedures to ensure that security system requirements are considered as part of any overall plant changes that could impact the safeguards program / systems.

NRC - On the date that the Wolf Creek Generating Station identified this condi-tion, NRC Region IV initiated calls to all the Region IV licensees and to the other NRC Regional Offices to alert them to the possible generic implications of this finding.

On July 7, 1986, Region IV issued enforcement letters to the licensees involved as follows:

a. A Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $40,000 to KG&E (Ref. 11). The violation was categorized as Severity Level II (on a scale where Severity Levels I and V arc considered the most-significant and least significant severity levels).

b. A Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $65,000 to PSC (Ref. 12). The Civil Penalty consisted of $40,000 for the Severity Level II violation and $25,000 for other less significant violations.

Enforcement conferences were held at the Region IV office on November 25, 1985, with KG&E and January 6, 1986, with PSC to discuss these issues and the 10

corrective actions undertaken by the licensee. The specific corrective actions described by the licensees have been evaluated by the NRC.

The NRC has inspected both sites since the violations were identified and is continuing to review the licensees' corrective actions to assure that all of the issues are satisfactorily resolved.

This item is considered closed for the purposes of this report.

86-18 Significant Deficiencies in Access Controls at River Bend Station The following information pertaining to this event is also being reported con-currently in the Federal Register. Appendix A (see Example 8 of "For All Licensees") of this report notes that any substantial breakdown of physical security, such as access control, that significantly weakened the protection against theft, diversion, or sabotage, can be considered an abnormal occurrence.

Date and Place - By letter of August 7,1986 (Ref.13), the NRC issued to Gulf States Utilities (GSU),' licensee for the River Bend Station, an enforcement letter containing a Severity Level II violation for serious deficiencies in the plant's safeguards program pertaining to access controls. River Bend Unit 1 is a General Electric-designed boiling water reactor located in West Feliciana Parish, Louisiana.

Nature and Probable Consequences - The Severity Level II violation involved four examples of failure to adequately control the access of personnel to vital areas. In the most serious example, the licensee incorrectly devitalized the plant auxiliary building access control system for over 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />. The other three examples included (1) improperly removing a hatch cover that allowed uncontrolled vital-island-to-vital-island access; (2) allowing a vital island door to be unsecured and uncompensated for about 30 minutes; and

-(3) improperly removing a large concrete floor plug which served as a vital-island-to-vital-island barrier. In all four examples, conditions existed whereby an intruder could have obtained unauthorized and undetected access into vital arcas from either the protected area or other vital areas. It appeared from interviews with licensee personnel and a review of maintenance records that the floor plug had been removed for several months.

The August 7,1986 letter also described a second violation of lesser signifi-cance involving two examples of inadequate vital area physical barriers.

Details of the items that constitute the two violations described above are contained in NRC Inspection Reports 50-458/86-11 and 50-458/86-17 (Refs. 14 and 15, respectively).

Cause or Causes - The cause of these deficiencies was the failure of management-to exercise effective personnel access control and to recognize and correct plant design deficiencies as they related to implementation of the security program.

11

Actions Taken to Prevent Recurrence Licensee - In each example identified, the licensee took immediate corrective action to post compensatory guards where required. At the locations where uncontrolled access was identified, the licensee secured the area and conducted

, a search to confirm that no unauthorized activity has occurred, or conditions existed that would prevent safe plant operation. In the " devitalization inci-dent," the licensee performance-tested all equipment essential for safe shutdown that was not operating during that period. The licensee has revised procedures and trained personnel to be aware of the safeguards implications of work performed by maintenance / operations personnel. Markings have been placed on all plugs, hatches, etc., that form part of the vital area barrier to alert personnel to notify Security before removal. The licensee implemented an engineering review and walkdown to identify any barrier openings that existed. Acceptable barriers have been installed to prevent unauthorized access through these openings.

NRC - An enforcement conference with GSU was held at the NRC Region IV office on June 10, 1986, to discuss these matters and the corrective actions under-taken by them. The August 7, 1986 enforcement letter forwarded a Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $65,000.

The Civil Penalty consisted of $40,000 for the Severity Level II violation and

$2.5,000 for the other less significant violation. The NRC has inspected the site since the violations were identified and is continuing to review the li-censee's corrective action to ensure that the issues are resolved satisfactorily.

This item is considered closed for the 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 1986. As of the date of this report, the NRC had not determined that any events were abnormal occurrences.

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 byproduct material users.

The NRC is reviewing events reported by these licensees during the chird calendar quarter of 1986. As of the date of this report, the NRC had determined that the following, event was an abnormal occurrence.

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86-19 Therapeutic Medical Misadministration The following information pertaining to this event is also being reported concurrently in the Federal Register. Appendix A (see the general criterion) 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.

Date and Place - On September 4, 1984, NRC Region III was notified by the University of Cincinnati Medical Center, Cincinnati, Ohio, that an iodine-125 radiation source, which had been ieplanted in a patient, had leaked, causing an unintended radiation exposure of 2,087 rac to the patient's thyroid. The leaking radioactive source was one of eight implanted in a patient August 27, 1984, for treatment of a brain tumor. The eight sources were removed on September 1, 1984.

The event has not been previously reported as an abnormal occurrence because at the time of the incident it was not classified as a medical misadministration as defined in 10 CFR S35.41-35.45. However, a recent reevaluation of the event by the NRC Staff concluded that the event should have properly been classified as a medical misadministration, and reportable as an abnormal occurrence, because the treatment was intended to irradiate only the patient's brain tumor, but because of the leaking source, also irradiated the thyroid. (In the body, iodine is deposited in the thyroid, and therefore, the radiation from the leaking iodine source would be concentrated there.)

Nature and Probable Consequences - On August 27, a total of eight seeds were placed in thin plastic catheter tubes and were temporarily implanted in the brain of a terminally ill patient. The next day, iodine-125 contamination was detected in the brachytherapy source storage room (BSR). Bioassay results showed that the technicians who had worked with the iodine-125 seeds had measurable uptakes of iodine. When the seeds were removed from the patient on September 1, a radiation survey of the patient's neck revealed a radiation level of 1.5 milli-rem per hour at two inches from the thyroid, which confirmed the seeds were leaking inside the patient. The patient was then discharged from the hospital with instructions to return for further bioassay analyses.

Subsequent bioassay testing of the patient's thyroid determined that there had been a deposition of 557 microcuries of iodine-125 in the thyroid. This level of deposition would result in a radiation dose to the thyroid of 2,087 rad.

(A rad is a standard measure of absorbed dose.) Such an exposure would be expected to result in some diminished thyroid function. Drugs are available to compensate for the reduced thyroid function.

The licensee found that the patient's friend and about 60 hospital personnel had received thyroid uptakes of 0.04 to 209 nanocuries; the NRC's maximum per-missible thyroid burden for iodine-125 is 720 nanocuries. The 209 nanocuries was received by one of the technicians involved in preparing the iodine-125 seeds, and would result in a thyroid dose of about 0.8 rad. .This dose would not be expected to result in any clinically detectable effects. The doses received by the other people were all considerably less than that received by this tec:.ician. Followup 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> urine bioassay testing of the two technicians involved in preparing the iodine-125 seeds showed a thyroid deposition of 29 nanocuries for one and no detectable activity for the other. The results of thyroid function testing of both individuals were normal.

13

The hospital personnel who received iodine uptakes included those who had

handled or were in close vicinity of the leaking source, those involved in the control and cleanup of the contamination of the BSR, and those who frequented the areas outside of the BSR. In regard to the latter, the licensee found that a positive differential pressure between the BSR and the area outside it had j existed for several days following the discovery of contamination in the BSR.  ;

This positive pressure contributed to the airborne migration of the iodine-125 i into adjacent areas. (The licensee later changed the room to be under negative pressure.)

The licensee's investigation of the contamination incident determined that one of the iodin?-125 seeds had been cut, apparently when it was being removed from a catheter tube from a previous patient implanted on August 13-17, 1984. Two technicians w ae involved in removing the seeds, and reported that after the tubes were removed from the previous patient, they were discolored and the seeds were difficult to see. One technician stated that he believed the damage most likely occurred when the ends of the catheter tubes were cut off with scissors.

The use of high activity iodine-125 seeds as removable brachytherapy sources was a new procedure at the University of Cincinnati. Previous uses (treatment protocols) involved the use of low activity iodine-125 seeds (0.1-1 millicurie) as permaneet brachytherapy implants.

Although the contamination of the BSR was extensive, wipe surveys and air samples revealed that the contamination was essentially limited to the BSR.

The room was decontaminated and then painted to fix any remaining contamination in place. Subsequent air samples in the room and in adjoining areas showed no detectable radioactivity. Some equipment (i.e., a sink, shelving, and storage safe) were found to have some residual contamination; they were covered in plastic to allow for radioactive decay prior to use.

Cause or Causes - The cause of the misadministration was found to be an inade-quate procedure used in removing the iodine-125 seeds from the catheter tubes l for reuse. Further, there were inadequate radiation surveys performed in the work area where the source preparation was performed. Had adequate surveys ]

been performed, the leaking seed might have been discovered prior to its being implanted in the patient.

Actions Taken to Prevent Recurrence Licensee - The licensee's Radioisotope Committee recommended that the use of the high activity iodine-125 seeds be discontinued for this type of radiation therapy, pending a thorough review of the health physics aspects of their use. The hospital also constructed a new radiation source storage room with a greater distance between the storage area and the source preparation area. A fume hood was also installed in the room.

NRC - Region III conducted a special inspection at the hospital on October 10-12, 1984, to evaluate the circumstances of the source leakage and patient use. A Notice of Violation was issued for two violations, i.e., opening a sealed source and failure to make an adequate survey for the source storage area following the preparation of the iodine-125 seeds for patient use (Ref. 16).

14

Followup inspections have been conoucted to determine the adequacy of the licensee's corrective actions.

On September 30, 1986, the NRC issued Inspection and Enforcement Information Notice No. 86-84 (Ref. 17) to all NRC medical institution licensees to inform them of this event.

The NRC's Office of Nuclear Material Safety and Safeguards, and the NRC's Region Office, are evaluating what additional measures should be taken by the manufacturer and medical licensees to improve handling procedures for iodine seeds.

The NRC Office for Analysis and Evaluation of Operational Data undertook a review of the incident to determine if there was a generic problem associated with the reuse of high activity iodine-125 seeds in brachytherapy implant proto-cols, and to assess any associated health and safety problems. The findings, and recommendations for action by various NRC offices, were issued in AE0D/C601 during August 1986 (Ref. 18).

This incident is considered closed for the purposes of this report.

AGREEMENT STATE LICENSEES Procedures have been developed for the Agreement States to screen unscheduled 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 calendar quarter of 1986, an Agreement State (Iowa) reported the following abnormal occurrence to the NRC.

AS86-7 Therapeutic Medical Misadministration Appendix A (see the general criterion) 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.

Date and Place - On September 5, 1986, the Iowa Radiological Health Section, Bureau of Environmental Health (State Agency), was notified of a therapeutic medical misadministration received by a patient at the University of Iowa Hospitals and Clinics, Iowa City, Iowa.

Nature and Probable Consequences - An elderly male patient, dying of lung cancer, who had gone through chemo and external radiation therapy, was experiencing difficulty breathing because the tumor growth was preventing air flow through the bronchial tubes. A decision had to be made to either perform surgery or do further radiation treatment to relieve the patient's labored breathing. Because of the patient's condition, the decision was to do further radiation therapy in an effort to shrink the size of the bronchial tumor. A plastic tube (not including radioactive sources) was inserted by a pulmonary physician through the nose and down into the bronchus tube. The plastic tube was of specific length and was placed at an exact tumor location in the bronchus tube. After the tube was in place, a radiation oncologist after-loaded 34 millicuries of iridium (Ir)-192 sealed seeds.

15

t The above mentioned procedure has a normal treatment time of 12-18 hours. The misadministration occurred three to four hours before the treatment was to ter-minate. At approximately 4 p.m., the radiation oncologist checked the patient and the source was properly positioned. He rechecked the patient at 5:40 p.m.

and found the plastic tube and source lying on the patient's chest. Immediately upon noticing this, the doctor used tongs to place the plastic tube and Ir-192 source into the transport pig which had been left in the patient's room. The Radiation Oncology Dosimetrist was advised on the incident. He calculated that the patient received 1500 R to the chest in an area 3.4 cm long and 2 mm wide.

The Radiation Protection Office (RPO) of the University was also notified.

Personnel from the RPO conducted a radiation survey with the Ir-192 source as a standard. Using data collected, it was determined that the people coming into the patient's room, when the source was out of the patient, would not have received more than 80 mr. All individuals entering the patient's room during the treatment period were equipped with personnel monitoring devices. The devices were returned to the supplier for interpretation. Results were minimal for all.

Cause or Causes - A patient undergoing the above mentioned procedure is kept under sedation. Based on data collected, it is the opinion of the staff of the University that the source was inadvertently removed by the patient. It is theorized by the physicians that during sleep the patient hooked the loop of the plastic tube with his hand and pulled it out, and the tube containing the source came to rest on his chest. It is further surmised that the patient was unaware of his actions.

Actions Taken to Prevent Recurrence Licensee - It is the opinion of the physician that it may be unavoidable to completely restrain the patient during the 12-18-hour treatment time because of the patient's medical condition. The action taken to minimize exposure to staff and patients undergoing this type of treatment was to establish standing orders which would require that each patient be checked on a 30-minute basis.

It is recognized that this would not stop a patient from removing the source, but would minimize the amount of time that the source would be disloged from the patient.

State Agency - No actions are planned by the State Agency.

This item is considered closed for the purposes of this report.

1 16

REFERENCES

1. NRC Generic Design Letter No. 84-23, " Reactor Vessel Water Level-Instrumentation in BWRs," from Darrel G. Eisenhut, Director, Division of Licensing, NRC Office of Nuclear Reactor Regulation, to all BWR licensees of operating reactors (except Lacrosse, Big Rock Point, Humboldt Bay, and Dresden-1), October 26, 1984.*

2. Letter from Charles E. Norelius, Director, Division of Reactor Prcjects, NRC Region III, to Cordell Reed, Vice President, Commonwealth Edison Company, enclosing Augmented Inspection Team Report No. 50-374/86-23, Docket No. 50-374, September 17, 1986.*

3. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 86-47, " Erratic Behavior of Static "0" Ring Differential Pres-sure Switches," June 10, 1986.*

4. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Bulletin No. 86-02, " Static "0" Ring Differential Pressure Switches," July 18, 1986.*

5. Confirmation of Action Letter, from J. Nelson Grace, Regional Administrator, NRC Region II, to H. B. Tucker, Vice President, Nuclear Production Depart-ment, Duke Power Company, Docket No. 50-414, June 30, 1986.*

6. Confirmation of Action Letter, from J. Nelson Grace, Regional Administrator, NRC Region II, to H. B. Tucker, Vice President, Nuclear Production Depart-ment, Duke Power Company, Docket Nos. 50-413 and 50-414, July 3, 1986.*

7. Letter from J. Nelson Grace, Regional Administrator, NRC Region II, to H. 8. Tucker, Vice President, Nuclear Production Department, Duke Power Company, forwarding a Notice of Violation and Proposed Imposition of Civil Penalty, Docket Nos. 50-413 and 50-414, November 12, 1986.*

8. Letter from J. Nelson Grace, Regional Administrator, NRC Region II, to H. B. Tucker, Vice President, Nuclear Production Department, Duke Power Company, forwarding NRC Augmented Inspection Team Report (Inspection Report)

Nos. 50-413/86-25 and 50-414/86-27, Docket Nos. 50-413 and 50-414, July 25, 1986.* Letter with reviced pages to the report was sent August 4, 1986.*

9. Letter from J. E. Gagliardo, Chief, Reactor Projects Branch, Division of Reactor Safety and Projects, NRC Region IV, to Glenn L. Koester, Vice President - Nuclear, Kansas Gas and Electric Company, forwarding Inspection Report No. 50-482/85-44, Docket No. 50-482, April 24,1986.t

10. Letter from J. E. Gagliardo, Chief, Reactor Projects Branch, Division of Reactor Safety and Projects, NRC Region IV, to R. F. Walker, President, Public Service Company of Colorado, forwarding Inspection Report No. 50-267/

85-32, Docket No. 50-267, April 7, 1986.t

• Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).

tNonsafeguards version available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).

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1 I

~

11. Letter from Robert D. Martin, Regional Administrator, NRC Region IV, to Glenn L. Koester, Vice President - Nuclear, Kansas Gas and-Electric Company, forwarding a Notice of Violation and Proposed Imposition of Civil Penalty, Docket No. 50-482, July 7, 1986.t

12. Letter from Robert D. Martin, Regional Administrator, NRC Region IV, to R. F. Walker, President, Public Service Company of Colorado, forwarding a Notice of Violation and Proposed Imposition of Civil Penalty, Docket No. 50-267, July 7, 1986.t

13. Letter from Robert D. Martin, Regional Administrator, NRC Region IV, to William J. Cahill, Jr. , Senior Vice President, Gulf States Utilities, Docket No. 50-458, August 7, 1986.t

14. ' Letter from J. E. Gagliardo, Chief, Reactor Projects Branch, Division of-Reactor Safety and Projects, NRC Region IV, to William J. Cahill, Jr.,

Senior Vice President, Gulf States Utilities, forwarding Inspection Report 50-458/86-11, Docket No. 50-485, June 4, 1986.t

15. Letter from J. E. Gagliardo, Chief, Reactor Projects Branch, Division of Reactor Safety and Projects, NRC Region IV, to William J. Cahill, Jr. ,

Senior -Vice President, Gulf States Utilities, forwarding Inspection Report 40-458/86-17, Docket No. 50-458, June 4, 1986.t

16. Letter from W. L. Axelson, Chief, Nuclear Materials Safety and Safeguards Branch, NRC Region III, to Robert S. Daniels, M.D., Senior Vice President for the Medical Center and Dean, College of Medicine, University of Cincinnati, forwarding (1) a Notice of Violation, and (2) Inspection Report No. 30-02764/84-02 (DRSS), Docket No. 30-02764 (License No. 34-06903-05),

December 18, 1984.*

17. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 86-84, " Rupture of a Nominal 40-Millicurie Iodine-125 Brachy-therapy Seed Causing Significant Spread of Radioactive Contamination,"

September 30, 1986.*

18. Case Study Report, " Rupture of an Iodine-125 Brachytherapy Source at the University of Cincinnati Medical Center," AE0D/C601, prepared by the NRC-Office for Analysis and Evaluation of Operational Data, August 1986._*

• Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).

tNonsafeguards version available in NRC Public Document Room, 1717 H Street, NW,-

Washington, DC 20555, for inspection and copying (for a fee).

18 u__- _ - . _ _ . _ _ _ _ _. _ _._ _ 2 i , ._.

APPENDIX A ABNORMAL 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).

An event will be considered an abnormal occurrence if it involves 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:

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:

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 S20.403(a)(1)),

or equivalent exposures from internal sources.

2. An exporure to an individual in an unrestricted area such that the whole-body dose received exceeds 0.5 rem in one calendar year (10 CFR S20.105(a)).

3. The release of radioactive material to an unrestricted area in concen-trations 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 S20.403(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 circum-stances that substantial hazard may result to persons in unrestricted areas.

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 19 ,

1

l 1

l normally expected performance and which is judged to be caused by theft or diversion or by substantial breakdown of the accountability system.

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 S70.52(a)).

10. A major deficiency in design, construction, or operation having safety implications requiring immediate remedial action.

11. A major deficiency in management or procedural controls in major areas.

12. Series of events (where individual events are not of major importance),

recurring incidents, and incidents with implications for similar facilities (generic incidents), which create major safety concern.

For Commercial Nuclear Power Plants

1. Exceeding a safety limit of license technical specifications (10 CFR $50.36(c)).

2. Major degradation of fuel integrity, primary coolant pressure boundary, 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 emergency core cooling system, loss of control rod system).

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 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 core cooling system, loss of control rod system).

For Fuel Cycle Licensees

1. A safety limit of license technical specifications is exceeded and a plant shutdown is required (10 CFR S50.36(c)).

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.

20

APPENDIX B UPDATE OF PREVIOUSLY REPORTED ABNORMAL OCCURRENCES During the July through September 1986 period, the NRC, NRC licensees, Agreement States, Agreement State 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 Congressional abnormal occurrence reports below provide the initial and any updating information on the abnormal occurrences discussed.

The updating provided generally covers events which took place during the report period, thus some information is not current. Some updating, however, is more current as indicated by the associated event dates. Open items will be dis-cussed in subsequent reports in the series.

NUCLEAR POWER PLANTS 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 each subsequent report in this series, i.e., NUREG-0090, Vol. 2, No. 2 through Vol. 9, No. 2. It is further updated for this report period as follows.

Reactor Building Entries During the third calendar quarter of 1986, 91 entries were made into the TMI-2 reactor building, bringing the total number of entries since the March 1979 accident to 1047. Reactor building activities during this period centered on the continuing defueling operation, including: core stratification sampling, video inspection, core drilling, bulk defueling, and end fitting removal.

Efforts to improve the reactor vessel water clarity also continued. Seven of the eight reactor internals vent valves were removed to provide improved access to the reactor vessel lower head.

Reactor Vessel Defueling Operations In July 1986, the licensee conducted the core stratification sample acquisition program. A drilling rig was assembled on the defueling work platform and a total of 10 sampling penetrations were made. These full-length samples of the reactor core (approximately 2 1/2" in diameter and 8 feet long) will be analyzed at the Idaho National Engineering Laboratory (INEL) to provide useful information on the properties of the core material, which will aid in the design of defueling tools and techniques.

Video inspections were performed through several of the bore holes created by the drilling operations. The initial inspections have indicated that fuel assemblies near the original core periphery have essentially remained intact below the rubble bed, while the central core region appears to consist largely of a fused mass of material.

21

Following completion of the core sampling activities, solid face drill bits were used in the drilling rig to perforate the hard crust layer of the core in 48 locations. These perforations were made to improve the effectiveness of bulk defueling tools in breaking up and removing the debris. The core drilling rig was disassembled in early August to allow the resumption of debris removal activities. On August 12, 1986, bulk defueling of the reactor vessel commenced, using specially designed heavy duty tools. Several defueling canisters were filled during these operations; however, progress was limited by the difficulty encountered in breaking up the hard mass of core debris. Consequently, the drilling equipment was reinstalled in mid-October to make additional penetrations into the hard crust to further facilitate bulk defueling. Remaining fuel assembly end fittings were removed from the top of the debris bed to clear the area for additional core boring.

Poor visibility due to the growth of microorganisms and buildup of inorganic compounds in the reactor coolant continued to make defueling operations more difficult during the third quarter of 1986. Several methods were employed by the licensee to combat the problem. These included the addition of a hydrogen peroxide solution (which had been used previously to reduce the micoorganism population); feed and bleed processing to replace batches of reactor coolant with cleaner water; the use of bag filters with the Fines / Debris Vacuum system; and the use of deep bed diatomaceous earth filters with the Defueling Water Cleanup System. These interim efforts were successful in restoring reactor vessel water clarity to an acceptable level. The licensee is continuing to investigate long term methods for maintaining water clarity and will periodically perform those procedures that have been effective, as needed.

Defueling activities to date have resulted in the removal of approximately 19 percent (57,000 lbs) of the total estimated TMI-2 core debris. The licensee currently projects the completion of defueling operations in December of 1987.

Cask and Liner Shipments The first off-site shipments of TMI-2 core debris to INEL were made during the reporting period. Three loaded shipping casks, each holding seven defueling canisters, were transferred by rail. A total of 12,000 lbs of core debris (approximately 4% of the total estimated quantity) have been shipped to date.

Shipments of the damaged fuel and core debris are expected to continue for the next two years. There were no offsite shipments of EPICOR or SDS liners during the period.

EPICOR-II/ Submerged Demineralizer System (SDS) Processing Through mid-October 1986, a total of 4,215,401 gallons of water have been processed through the SDS and a total of 3,152,096 gallons have been processed through the EPICOR-II system. For the reporting period, approximately 117,000 gallons and 149,000 gallons were processed by the SDS and EPICOR-II systems, respectively. '

Auxiliary and Fuel Handling Building (AFHB) Activities Decontamination activities continued in the TMI-2 AFHB during the reporting period. Vacuum techniques were used for gross decontamination of the Reactor 22

Coolant Evaporator cubicle, the "A" Bleed Tank room and the Concentrated Liquid Waste Pump. " Hands-on" decontamination tasks were then performed in these rooms as well as in the Westinghouse valve room, the Evaporator Condensate Test Tank cubicle, the Neutralizer Tank Pump room, the Seal Injection valve room, and the annulus area between the reactor building and the AFHB. Assembly and start-up testing of the sludge transfer system was also conducted during the period.

Proposal for Disposing of Accident Generated Water On July 31,1986, the licensee submitted a proposal for disposing of 2.1 million gallons of radioactive water contaminated as a result of the TMI-2 accident and subsequent cleanup operations. Of the alternatives considered, the licensee has selected a method that involves the forced evaporation of the water at the TMI site over a period of two and one-half years. The resulting evaporator bottoms, containing small amounts of cesium-137, strontium-90, and substantial '

volumes of boric acid and sodium hydroxide, would be solidified and disposed of as low-level radioactive waste. In conjunction with this proposal, the licensee has petitioned the Secretary of Energy for the additional burial ground waste volume allocation necessary to implement this plan.

In its proposal, the licensee indicated that the simplest, least costly option evaluated, involving insignificant environmental impacts, is the controlled discharge of the processed diluted water to the Susquehanna River. However, recognizing the political and public concerns that unique health risks are associated with that disposal method, the licensee considers the proposed forced evaporation method as the most desirable option.

The Commission's Statement of Policy, dated April 28, 1981, provided for Commis-sion review and approval of this issue. The NRC Staff will evaluate the licensee's proposal and provide a recommendation to the Commission for its consideration.

TMI-2 Enforcement Actions On September 29, 1986, the NRC issued a Notice of Violation (N0V) and Proposed Imposition of Civil Penalty to General Public Utilities Nuclear Corporation (GPUNC), the licensee for TMI-2 (Ref. B-1). A civil penalty of $40,000 dollars was assessed for failure of the licensee to follow established procedures in modifying the unit's polar crane main hoist brakes. The staff found that the required GPUNC Engineering and Change Memoranda and Work Permits were not properly developed and used in connection with the addition of a hand release mechanism to the polar crane brakes. The hand release mechanism, not present on the original brakes, thereby added a function to the main hoist brakes that was not properly documented. The violation was determined to be Severity Level III, for which the corresponding penalty at the time of the violation was the $40,000 penalty imposed. The licensee has 30 days from the date of the NOV

$ to pay the pcnalty or to protest the imposition of the penalty.

On March 4,1986, the staff issued an Order Imposing Civil Monetary Penalty to GPUNC in the amount of $64,000 for discriminatory acts against a former employee (Ref. B-2). The staff had reviewed the licensee's appeal of the earlier NOV, but concluded that the penalty should be imposed for the Severity Level II violation. On March 21, 1986, GPUNC requested a hearing on the imposition of 23 n

the civil penalty and on May 30, 1986, the NRC's Atomic Safety and Licensing Board Panel issued a Notice of Hearing. On July 30, 1986 a pre-hearing con-ference was held before an administrative law judge who, in consultation with the parties, scheduled an evidentiary hearing for Spring 1987.

TMI-2 Advisory Panel Meeting The Advisory Panel for the Decontamination of Three Mile Island Unit 2 met on August 13, 1986 in Lancaster, Pennsylvania. At this meeting, the licensee briefed the Panel on the status of defueling operations and on the preposal for disposal of the TMI-2 accident generated water. The licensee presented a video tape of the core stratification sample acquisition program and discussed future defueling plans. The NRC Staff also discussed its plan for the review of the licensee's proposal for accident generated water disposal.

Future reports will be made as appropriate.

85-7 Loss of Main and Auxiliary Feedwater Systems This abnormal occurrence, which occurred at Davis-Besse on June 9, 1985, was originally reported in NUREG-0090, Vol. 8, No. 2, " Report to Congress on Abnormal Occurrences: April-June 1985," and updated in NUREG-0090, Vol. 8, No. 3; Vol. 8, No. 4; Vol. 9, No.1, and Vol. 9, N3. 2. It is further updated through December 1986, as follows:

The full ACRS Committee met on Davis-Besse restart on July 11, 1986. The Committee has written a letter supporting restart. The Commission was briefed on July 24,1986, on the plant status by loledo Edison Company representatives and on the NRC Staff's evaluation of corrective actions. The Commission was briefed again prior to restart on November 21, 1986.

Reactor coolant pump shaf t replacement was completed, plus reinstallation of motors, testing, and replacement of other equipment which were removed for pump access.

Raychem splice inspection and replacement were completed.

The Commission subsequently voted 5 to 0 to allow the staff to authorize restart when the plant was dermed ready. Restart was authorized by the staff on December 19, 1986, and the plant was restarted on December 22, 1986.

This item is considered closed for the purposes of this report.

85-14 Management Deficiencies at Tennessee Valley Authority This abnormal occurrence was originally reported in NUREG-0090, Vol. 8, No. 3,

" Report to Congress on Abnormal Occurrences: July-September 1985," and updated in Vol. 9, No. 1, and Vol. 9, No. 2. It is further updated through December 1986, as follows:

24

The NRC Staff, led by a senior management team, has identified a number of major Tennessee Valley Authority (TVA) issues requiring resolution prior to the restart of any of the TVA reactors and has provided periodic status reports to the Commission, the most recent of which was issued December 9, 1986. TVA sub-mitted Revision 2 to their Corporate Nuclear Performance Plan and Revision 1 to the Sequoyah Nt lear Performance Plan on July 17, 1986.

Corporate Activities The Staff review of the Corporate Nuclear Performance Plan is essentially complev . The TVA Corporate Plan is generally acceptable to the Staff, subject to their review of TVA implementation in the coming months.

Conflict of interest issues in connection with TVA's arrangements with Stone and Webster, Bechtel, and others were resolved in December 1986. The TVA Inspector General (TVA IG) and General Counsel investigated this matter in response to the U.S. Office of Government Ethics concerns. Related to this matter is a reduction in Bechtel staff level effort on the resolution of employee concerns.

The ACRS issued its report on TVA and recommendations to the Commission on August 12, 1986. The ACRS agreed with the TVA diagnosis of their management problems, believed that immediate technical and management issues are being addressed, and provided comments to the Staff. The Staff has requested that TVA respond to the ACRS comments and will consider the TVA response in its ongoing review.

TVA responded to the NRC's evaluation of harassment and intimidation (H & I) at TVA on August 15, 1986, providirig their response to Staff concerns and stating their strong views on prohibiting harassment and intimidation in the workplace.

The TVA IG is investigating the H & I and wrongdoing issues prior to recommending action by TVA line management. Additionally, on August 8, 1986, TVA responded to the Staff's Notice of Violation and Proposed Imposition of Civil Penalty (issued July 10, 1986) regarding certain discriminatory acts. TVA paid the civil penalty and stated their corrective actions, including Mr. White's (TVA's Manager of Nuclear Power) strong position against H & I. The Staff will evaluate TVA handling of H & I issues as part of its review.

In response to the TVA IG's expressed need to contact concerned individuals directly as part of his investigative process in the H & I area, the Staff contacted selected concerned individuals in an attempt to establish communica-tions between the individual and the TVA IG. Arrangements for direct contact between concerned individuals who responded to the Staff and the TVA '.G are in process. Selected H & I cases have been transferred from the NRC Office of

, Investigations (0I) to the TVA IG. OI will monitor the TVA IG's investigation of these issues.

Sequoyah TVA submitted Revision 1 of the Sequoyah Nuclear Performance Plan on July 17, 1986.

25

Major Issues are described below:

Employee Concerns Program On August 29, 1986, TVA submitted their revised program for management of employee concerns received prior to February 1, 1986, including those applicable to Sequoyah. The first group of Sequoyah employee concerns regarding element evaluation reports was received in early September. The pacing group of Sequoyah employee concerns involves engineering and design control issues. The Staff believes the TVA program is generally acceptable but that resolution of many individual issues may impact the Sequoyah restart. Staff technical review teams are assigned, and in some cases, the Staff is reviewing draft documents at the site to stay current of TVA progress.

On July 17, 1986, TVA submitted their revised program for management of new employee concerns received beginning February 1,1986. The Staff believes this program is generally acceptable, subject to their review of TVA implementation.

Design Control TVA submitted its Design Baseline and Verification Program (DBVP) and the Staff found the TVA approach generally acceptable. Staff concerns remain unresolved regarding TVA interim criteria for small bore piping and cable tray supports. This item may impact Sequoyah restart, depending on the progress of TVA implementation and the extent of corrective actions.

Welding TVA and Staff acti?y in this area are nearing completion. Notwithstanding their innocuous nature, the number of weld discrepancies found during TVA

' reinspections (and not identified during the original construction) has led tte Staff to consider the need for an accelerated completion date for the first 10 year in-service inspection program for both Sequoyah units.

This will further assure the quality of welds in ASME-scope piping, pipe supports, and major component supports.

Technical Specification Surveillance Requirements NRC inspection efforts identified deficiencies regarding the adequacy of the licensee's surveillance test program. TVA acknowledged these concerns and has developed a program to reassess the adequacy of Sequoyah surveil-lance procedures and their performance. This program is designed to ensure that surveillance procedures are technically adequate prior to Sequoyah restart. Due to the significance of this issue, an enforcement conference '

was held in the Region II office on August 25, 1986.

Containment Isolation Valves During a recent inspection at Sequoyah, the Staff found that valves in the reactor coolant pump seal injection lines and an RHR return line may not provide adequate assurance of containment isolation in certain 26

accident situations. TVA and the Staff are evaluating the adequacy of the isolation provisions to determine if any corrective measures are required prior to restart. This configuration also exists at Watts Bar, and may exist at other similar Westinghouse facilities.

Watts Bar Based on informal discussion with TVA, Watts Bar Unit 1 is not expected to be ready for licensing until late 1988. Pacing items are expected to be TVA com-pletion of the Design Baseline and Licensing Verification Program, reanalysis of piping and supports, and resolution of employee concerns. Formal schedules regarding Watts Bar have not been received and the submittal date for the Watts Bar portion of the Nuclear Performance Plan remains uncertain.

Major issues are described below:

Design Baseline and Licensing Verification Program To address and reconcile various problems related to design control and licensing issues at Watts Bar, TVA is developing a comprehensive Design Baseline and Licensing Verification Program (DBLVP). TVA met with the NRC Staff on August 21, 1986, to discuss their proposed program which is being created to supplement and confirm the effectiveness of existing design, construction, and licensing processes. TVA intends to confirm that licens-ing, design and construction activities appropriately implement requirements and that Watts Bar Unit 1 is ready for power operation. This includes verification of licensing commitments, design bases, design documents, construction, and configuration control.

The Staff is in general agreement with the TVA approach; however, review of the docketed program and inspection of implementation remains to be accomplished. TVA schedules and milestones for this effort are not definite but the program is extensive and may be the pacing item to licensing.

Employee Concern Program As discussed under Sequoyah issues, changes to the employee concern program have been made and TVA is in the process of evaluating Watts Bar concerns. The level of effort by TVA contractor staff personnel has been impacted by the conflict of interest and contractual matters between TVA and Bechtel. Periodic inspections of TVA progress are ongoing.

Weldin_o TVA continues to reinspect welds at Watts Bar. TVA has expanded the scope

, of the weld inspection effort in the structural area and is evaluating the need for further expansion in different population groups on the basis of discrepancies found in the initial sample (the initial sample involved about 1700 components in various systems). The NRC Region I non-destruc-tive evaluation van has been onsite, and Staff and consultant inspections of TVA weld activities are ongoing.

27

Quality Technology Company (QTC) Employee Concerns Records The Staff completed the screening and expurgation of QTC employee concern files and has transmitted expurgated files to the TVA IG.

Browns Ferry On September 8, 1986, the NRC Staff issued a Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $150,000 regarding operations at the Browns Ferry facility (Ref. B-3). The violations pertained to Technical Specification 5.6, Seismic Criteria and 10 CFR Part 50, Appendix B, Quality Assurance; each were Severity Level III ($50,000). They included the following:

Cable tray supports in the Control Bay area, Diesel Generator Building, and Reactor Building improperly designed with respect to seismic criteria.

Failure to correct deficiencies involving overfilled cable trays and diesel generator maintenance in a timely manner after detection.

Failure to ensure that safety-related wiring configurations were consistent with the appropriate engineering drawings and procedures.

On October 8, 1986, TVA provided their detailed response regarding each viola-tion. In their response they stated that they did not contest the imposition of any of the proposed civil penalties. The NRC Staff is currently reviewing the detailed response.

TVA submitted the Browns Ferry portion of the Nuclear Performance Plan on August 28, 1986, and an initial Staff review is in progress. Although no TVA schedule for Browns Ferry restart is available, TVA stated that Unit 2 is expected to be ready not sooner than late 1987.

Major issues are described below:

Probabilistic Risk Assescment (PRA)

The Staff met with TVA regarding the (undocketed) draft PRA performed by TVA and their contractor in the early 1980s. TVA and the Staff agreed to a plan and schedule for review of the draft PRA and the additional TVA analysis needed to establish the severe accident characterization of the facility. TVA and the Staff will meet periodically to discuss status, pro-gress, and direction of the additional analysis. A final report on the severe accident characteristics will be submitted prior to the restart of any of the Browns Ferry units.

Configuration Management / Design Control All but a few facility modifications have been suspended pending system walkdown and verification that the design drawings reflect the as-built plant components. Delays in this program, in turn, could impact some modifications and the program to revise operating and surveillance pro-cedures. The whole baseline program is being re-evaluated for purpose and depth.

28

i Weld Inspections i

5taff-mandated (Generic Letter 84-11) (Ref. B-4) inspection for intergrandular stress corrosion cracking (IGSCC) in Unit 2 recirculation system piping found a number of nozzles with numerous crack indications.

TVA is replacing portions of the recirculation piping.

The reinspection of other system piping and structural welds is near completion.

Fire Protection Representatives of the NRC Offices of NRR, Inspection and Enforcement, and Region II met with TVA personnel at the Browns Ferry site in late June to review the modifications and actions proposed by TVA in early 1986 to meet 10 CFR Part 50 Appendix R requirements. While the general concept appeared reasonable, the NRC Staff requested that TVA submit additional documenta-tion regarding the fire hazards analysis combustible loadings calculations for each area and manual operations that would be required to support shut-down. The Staff is continuing to evaluate the fire protection program.

Fire protection could be a limiting issue for startup 'if TVA's request for specific exemptions cannot be found acceptable.

Future reports will be made as appropriate.

3 85-20 Management Deficiencies at Fermi Nuclear Power Station This abnormal occurrence was originally reported in NUREG-0090, Vol. 8, No. 4,

" Report to Congress on Abnormal Occurrences: October-December,1985," and updated in NUP.EG-0090, Vol. 9, No. 1 and Vol. 9, No. 2. It is further updated for the third quarter 1986 as follows.

On July 31, 1986, the Regional Administrator, NRC Region III, authorized Detroit Edison Company to resume operations at the Fermi Unit 2 Nuclear Power Station.

The plant had been shut down since October 1985 for maintenance, modifications, and correction of a number of management, personnel, ard equipment problems.

All issues related to the restart of Fermi Unit 2 were resolved prior to the Region III authorization. The authorization initially permitted operation at power levels up to 5 percent power. On September 12, 1986, the licensee was permitted to increase the Unit's power level to 20 percent for continuation of its startup testing prog am. Further power level escalation will be permitted following successful completion of the testing activities and NRC review of the

, licensee's performance.

Region III established a Restart Team which, together with the NRC resident inspectors, have been closely monitoring the licensee's performance.

29

On July 29, 1986, the NRC issued to the licensee a Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $75,000 for violations occurring in 1985 at Fermi Unit 2 (Ref. B-5). These violations were:

1. During the period ,luly 23-29, 1985, two of the plant's four emergency diesel generators and a portion of Emergency Core Cooling System (ECCS) were inoperable because a valve was closed in the cooling water system for the diesel generators and for the ECCS equipment. The valve--which is required to be open--was left closed after a plant operator made a routine check of the valve. The remaining diesel generators and the parallel portions of the ECCS systems were not affected by the cutoff of the equip-ment cooling water flow.

2. During the period June 21 through September 2, 1985, amvalve was left open and an attached small pipe uncapped, providing a potential leakage pathway from the reactor containment into the surrounding reactor building. The valve was in a system used for monitoring the atmosphe4e.in the reactor's primary containment. In addition,.a device used to control the buildup of hydrogen in the reactor containment was foJnd to have greater than permitted leakage on August 28, 1985, a conditicn existing since June 21, 1985.

This would also represent a potential small leakage pathway from the reactor containment into the surrounding reactor building.

3. The cooling system for the room containing portions of the ECCS was shut off from July 23-24, %85. Having the room cooler out of service rendered

, the ECCS equipment technically inoperable. Other ECCS systems remained in service.

This item is considered clcsed for the purposes of this report.

86-2 Lass of Integrated Control System Power and Overcooling Transient ,

t This abnormal occurrence, which occurred at Rancho Seco on December 26, 1985, was originally reported in NUREG-0090, Vol. 9, No. 1, " Report to Congress on <

Abnormal Occurrences, January-March 1986," and updated in NUREG-0090, Vol. 9, No. 2. It is further updat?d as follows.

In response to a senior NRC management request during a meeting at Rancho Seco on March 24-25, 1986, Sacramento Municipal Utility District (SMUD) initiated a management and performance improvement program on July 3, 198E, and Staff review of the program was initiated.

The week of August 25, 1986, personnel from the NRC Office of Nuclear Reactor Reguiation (NRR), accompanied by INEL contract personnel, visited the site to initiate an on site review of the SMUD system evaluation and test program. The INEL personnel performed a similar function at Davis-Besse. The team returned to the site the week of September 29, 1986, to continue their review. The week of September 8, 1986, an NRR Instrumentation and Control (I&C) Team visited the site to obtain information necessary for them to evaluate modifications to

, 30

the Integrated Control System (ICS)/Non-Nuclear Instrumentation (NNI) and other instrumentation that resulted from the December 26, 1985 event and t?e licensee's performance improvement program evaluations. The week of September 29, an NRR Human Factors Team visited the site to discuss control room modifications that resulted from the December 26, 1985 event, the Emergency Feedwater Initiation and Control System (EFIC) installation and the licensee's performance improvement program. The licensee submitted Amendment No. 1 to the Rancho Seco Action Plan on September 15, 1986. Primarily, the amendment confirms the licensee's commitment made during an August meeting to install EFIC and have it operational prior to restart and updates the details of the systems review and test program.

On September 12, 1986, the licensee announced that requalification of the Transamerica Delaval, Inc. diesels will be completed prior to restart. This will delay the estinated restart date of May 1987.

On October 22, 1986, the NRC forwarded to the licensee a Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $375,000 (Ref. B-6).

The violations involved the licensee's failure: to maintain the plant's cooldown rate within the limits prescribed by technical specifications, following the December 26, 1985 event; to establish appropriate procedures in anticipation of a " loss of DC power to the ICS" event; and to adequately implement or maintain certain aspects of plant emergency procedures during and after the event.

idture reports will be made as appropriate.

Annex Reassessment of Babcock & Wilcox (B&W)-Designed Plants As mentioned in the original reporting of the December 26, 1985 Rancho Seco event (i.e., NUREG-0090, Vol. 9, No. 1), since the TMI-2 accident there has l been a growing realization of the sensitivity of B&W plants to operational transients. By letter dated January 24, 1986, the NRC Executive Director for Operations informed the Chairman of the B&W Owners Group (BWOG) that a number i

of recent events at B&W-designed reactors lead the staff to conclude that there is a need to re-examine the basic requirements for B&W plants (Ref. B-7). The NRC Staff subsequently developed a plan for this re-examination and forwarded a copy to the Commission on March 21, 1986 (Ref. B-8).

Subsequent to the development of the plan, the Staff encouraged the BWOG to take the leadership role in the reassessment of B&W plants. The BWOG committed to take this lead and provided a description of their program on May 25, 1986.

The BWOG program is entitled the " Safety and Performance Improvement (SPI) Pro-gram" and is documented in BAW-1919. In light of the BWOG commitment to i

assume the leadership role in the reassessment program, the Staff updated its

?

plan to reflect the BWOG activities. On August 29, and October 31, 1986, the BWOG provided revisions to the document incorporating the results of the program to date.

The object of the generic evaluation of B&W plants is to reassess the basic requirements and operational characteristics of these plants. Also, the study will compare the overall safety of B&W plants to other PWRs. Potential improve-ments to reduce the frequency of complex post-trip response to anticipated 31

operational occurrences, and thereby improve the overall safety of B&W plants, will be identified.

To achieve the objectives, a multi-faceted approach is being used by the BWOG and the NRC Staff. Included as part of the reassessment are: (1) review of operational transients which have occurred on B&W plants: (2) feedback from operational and maintenance personnel, along with the views of NRC Regional personnel and Resident Inspectors; (3) deterministic assessments; (4) prob-abilistic assessments; and (5) computer simulations.

The NRC Staff is actively reviewing the results of the BWOG efforts. Working level meetings between the BWOG and the Staff have been held to discuss the system review tasks, the sensitivity study being performed by MPR Associates, the operator burden task, and the BWOG Recommendation Tracking System. The system reviews-being performed include the Integrated Control System /Non-Nuclear Instrumentation (ICS/NNI), the Main Feedwater (MFW) system, the Emergency Feed-water / Auxiliary Feedwater (EFW/AFW) system, the Secondary Plant Relief systems, and the Instrument Air system. The Staff has concluded that the BWOG is generally pursuing a broad-based examination of these systems.

The program for reassessment of B&W plants was discussed with the ACRS Subcom-mittee on B&W Reactor Plants on June 25, 1986 and at the full Committee meeting on July 11, 1986. Following the full Committee meeting, the ACRS commented, in a letter dated July 16, 1986 on the B&W plant reassessment program and expressed concerns regarding the scope of the BWOG SPI Program. The Staff responded to the ACRS letter on August 14, 1986. On September 12, 1986 the Staff and the BWOG met with the full Committee to further discuss the program. At that meet-ing, the ACRS was generally satisfied with the current program and stated that the program appeared responsive to their concerns.

The staff believes that the BWOG SPI Program is generally on target to reassess and improve the safety of B&W plants. The Staff is continuing to monitor the BWOG efforts. The initial safety evaluatien report (SER) is expected to be issued in February 1987. Supplements to the SER will be issued thereafter; the final supplement is expected to be completed in mid-1987.

Future reports will be made as appropriate.

86-9 Emergency Core Cooling System Mini-Flow Design Deficiency This abnormal occurrence was originally reported in NUREG-0090, Vol. 9, No. 2, .

" Report to Congress on Abnormal Occurrences: April-June 1986," under the title l of " Boiling Water Reactor (BWR) Emergency Core Cooling System (ECCS) Design  !

Deficiency." That report discussed a significant design deficiency in the BWR  !

residual heat removal (RHR) system mini-flow protection logic at several facil- 1 ities. The following update describes a single failure vulnerability of some '

pressurized water reactor (PWR) safety injection (SI) systems due to a design deficiency in the SI pump mini-flow protection. Since the two events.are simi-lar in that they both involve single failures in mini-flow protection equipment which could disable all trains of ECCS systems, the title of the abnormal occur-rence has been changed to indicate that both certain BWRs and PWRs are affected.

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On July 24, 1985, Wisconsin Electric Company submitted a report in accordance with 10 CFR Part 21 for the Point Beach Nuclear Plant describing a design deficiency involving the minimum flow recirculation valves for the SI pumps.

At Point Beach, the discharge lines for each of the SI pumps are connected to a common recirculation header to provide a test flow path and a recirculation flow nath for minimum flow at times when the reactor coolant system'(RCS) pres-sure exceeds the SI pump shutoff head. The common recirculation header is provided with two air-operated valves in series. These valves close to isolate the refueling water storage tank (RWST) from the containment sump during the recirculation phase of emergency core cooling following a postulated loss-of-coolant accident (LOCA). Closure of these valves is intended to prevent con-tainment reactor coolant from being pumped outside containment to the RWST during the recirculation phase. Both of the recirculation header isolation valves are designed to fail closed when their control circuits' lose electrical power or control air- pressure. The Part 21 report noted that a single failure (open) of the breaker associated with either_of the two valves would isolate the minimum flow path for both SI pumps, defeat the control room remote opera-tion capability of the affected valve, and cause the loss of control room valve position indication.

On February 5, 1986, Carolina Power and Light submitted a Licensee Event Report describing essentially the identical design deficiency involving the minimum flow recirculation path for the SI pumps at H. B. Robinson. On June 20, 1986, Rochester Gas and Electric discovered a similar design deficiency at the Ginna plant and on June 25, 1986, Florida Power and Light Company reported a similar design deficiency at the Turkey Point plant.

The concern in all four cases above involves a postulated small break LOCA which initiates a safety injection signal that starts the SI pumps. During a small break LOCA, RCS pressure may not readily decrease below the SI pump shutoff-head. A single failure resulting in the loss of the minimum flow path concurrent with SI pump actuation would cause the pumps to operate deadheaded until RCS pressure decayed below the SI pump shutoff head. The simultaneous loss of mini-mum flow valve position. indication in the control room will exacerbate this loss of minimum flow path. The availability of valve position indication is-not expected to sufficiently ameliorate this event. Operating the SI pumps deadheaded could result in pump damage and failure within a few minutes. The failure of multiple trains in an ECCS due to a single failure violates the single failure criterion in 10 CFR Part 50, Appendix A, General Design Criterion 35

(" Emergency Core Cooling"). In all the above cases, the short-term corrective actions taken by the licensees were to mechanically block open the SI pump recirculation valves to ensure a minimum flow path and to revise the applicable plant LOCA procedures to manually close these valves prior to switching to the recirculation mode.

On October 8, 1986, Inspection and Enforc2 ment Compliance Bulletin No. 86-03 4 (Ref. B-9) was issued by the Office of Irspection and Enforcement to inform-addressees of recent reports regarding tr.c design deficiency and to request that licensees affected by the problem promptly provide appropriate instructions and training to plant operators on how to recognize the problem if it occurs and take appropriate mitigating actions. Inspection and Enforcement Information Notice No. 85-94 (Ref. B-10) had previously been issued on the subject on December 13, 1985. Reports from licensees regarding corrective actions taken are currently under review by the NRC staff.

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Future reports will be made as appropriate.

FUEL CYCLE FACILITIES 86-3 Rupture of Uranium Hexafluoride Cylinder and Release of Gases This abnormal occurrence, involving Sequoyah Fuels Corporation, Gore, Oklahoma, was originally reported in NUREG-0090, Vol. 9, No. 1, " Report to Congress on Abnormal Occurrences: January-March 1986, and updated in NUREG-0090, Vol. 9, No. 2. It is further updated as of mid-November 1986 as follows.

On July 18, 1986, Sequoyah Fuels Corporation (SFC) requested approval to perform limited cleanup activities at its facility near Gore, Oklahoma. This request was based on the need to reduce liquid inventories to allow access to equipment for essential maintenance and repair. Reducing these inventories would also allow SFC to resume decontamination activities which had been stopped because of lack of storage space for the liquid generated during cleanup. After dis-cussions with NRC Region IV, the Environmental Protection Agency (EPA) and the State of Oklahoma, the NRC agreed on August 22, 1986 to allow limited operation of the yellowcake digestion tanks, solvent extraction system, evaporators, and uranyl nitrate boildown tanks. All of the activities allowed would have had to be performed irrespective of the Commission's decision on restart. NRC Region IV is monitoring these operations which have been uneventful to date.

On July 28 through August 1,1986, a special team (consisting of personnel from the NRC, EPA, and FEMA) conducted an announced inspection at the facility. The inspection effort focused on the areas of emergency planning, completion of items committed to by SFC prior to resuming producing of UFe, close-out of items identified by previous NRC inspections, and review of allegations made regarding the safety of operation of the facility. As documented in NRC Inspection Report No. 40-08027/86-08 dated September 4,1986 (Ref. B-11), the inspection resulted in closing out 22 of the 23 items identified as either apparent violations, deviations, or open items in NRC Inspection Report No. 40-08027/86-02 dated May 9, 1986 (Ref. B-12). One item was not closed out and will remain open pending restart to allow the licensee to complete on-the-job training of operators and walk down evaluations of modified plant equipment. Additionally, all 12 allegations were reviewed and no violations or deviations were identified.

On October 2, 1986, the NRC issued an Order which modified SFC's license (Ref. B-13); however, the Order did not authorize resumption of production oper-ations. The order was issued because the NRC's findings regarding the January 4, 1986 accident demonstrate that there is a need for significant improvement in the licensee's control and supervision of licensed activities, especially those regarding the filling and preparation for shipment of UFs cylinders. The NRC determined that implementation of commitments made by the licensee is essential to ensure the safe operation of the facility. In addition, other areas requir-ing corrective action have been identified. These include training and super-vision of employees, adequacy of plant staffing, and proper followup of the health impacts of the accident on licensee personnel who were exposed to uranium.

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Furthermore, the NRC determined that additional oversight of facility operations is necessary to provide reasonable assurance that the licensee will be in compliance with Commission requirements if the facility is permitted to resume operations. Therefore, the Order includes provisions requiring SFC to obtain the services of an independent oversight organization and have personnel from this organization onsite anytime the facility is in operation. The requirement can be withdrawn at a future time when the NRC Region IV Administrator deems appropriate.

On October 14, 1986, the NRC issued a Notice of Violation and Proposed Imposi-tion of Civil Penalties in the amount of $310,000 (Ref. B-14). The violations which were directly associated with the January 4, 1986 accident were categorized as a Severity Level I problem and accounted for $300,000 of the proposed civil penalty. These involved flagrant violations identified by the NRC, that reflected a serious breakdown in management controls.

On November 14, 1986, the NRC authorized Sequoyah Fuels Corporation to restart production activities. NRC provided 24-hour oversight of restart and production activities and continued the requirement for an independent oversight organi-zation to provide a third party examination of operations. Both of these oversight activities have continued as the facility resumed production.

Future reports will be made as appropriate.

OTHER NRC LICENSEES 85-4 Unlawful Possession of Radioactive Material This abnormal occurrence, involving the John C. Haynes Company, Newark, Ohio, was originally reported and closed out in NUREG-0090, Vol. 8, No. 1, " Report to Congress on Abnormal Occurrences: January-March 1985." It is being reopened to report the following significant information.

On July 22, 1986, John C. Haynes was sentenced to five years probation after pleading guilty in U.S. District Court, Columbus, Ohio, to charges of making a false statement and illegal possession of byproduct (radioactive) materials (americium-241).

Mr. Haynes had been previously licensed by the NRC to use radioactive americium-241 for the purpose of irradiating gems to cause a color change. His license had subsequently been restricted to prohibit the possession and use of americium-241 except for the material remaining as contamination in his labor-atory facility. Subsequent to his arrest in 1985, Haynes' laboratory facility was decontaminated under the Environmental Protection Agency's Superfund project.

After decontamination, his restricted license was revoked by the NRC.

As a condition of his probation, Mr. Haynes is to make restitution of $129,580 toward the cost of cleanup of the facility and to no longer deal with nuclear materials.

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This item is closed for the purposes of this report.

86-7 Tritium Overexposure and Laboratory Contamination This abnormal occurrence, involving Ferris State College, Big Rapids, Michigan, was originally reported in NUREG-0090, Vol. 9, No.1, " Report to Congress on  ;

Abnormal Occurrences: January-March 1986." It is updated as follows.

On July 11, 1986, the NRC sent to the licensee a Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $10,500 (Ref. B-15).

Item I in the Notice of Violation involved an individual who was exposed in a restricted area'on August 3, 1985 to a tritium vapor concentration approximately 20 times the permissible limit. This resulted in the individual receiving a calculated whole-body dose of 21 rem. This event is of particular concern be-cause the individual performed an experiment using curie quantities of tritium in liquid form without functional monitoring instruments.

Item II involved the licensee's failure to report to the NRC, as required, the August 3, 1985 event and a second event that occurred on December 17, 1985 after urinalysis tests, performed by the individual described above, showed tritium concentrations in excess of NRC limits. The individual knew the concentrations were excessive but failed to recognize the radiological significance of the event and therefore decided not to inform the Radiation Control Office. NRC holds licensees responsible for acts such as this because licensees are responsible to properly train their employees and monitor their work activities.

Item III described additional violations that resulted from inadequate surveys and evaluations, inadequate training and supervision of individuals that used licensed material, failure to take adequate corrective action after radiological hazards were identified, failure tc follow procedures, and failure to maintain adequate records.

The NRC forwarding letter stated that collectively, these violations indicated a serious lack of management oversight of the radiation safety program, lack of an effective audit program to monitor personnel, and a failure to reasonably ensure that NRC requirements are being followed.

The licensee paid the $10,500 civil penalty and as corrective action, the licensee upgraded its procedures governing the use of radioactive materials and its system of auditing these uses. Further, the licensee's NRC license was amended in April 1986 changing the license classification from broad scope, which permitted the licensee to authorize individual users of radioactive materials and to approve operating procedures, tc a limited scope .

license which requires NRC approval of users and procedures. j This item is considered closed for the purposes of this report.

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APPENDIX C OTHER EVENTS OF INTEREST The following items are described below because they may possibly be perceived by the public to be of public health significance. The items 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. BWR Scram Solenoid Pilot Valve Refurbishment Kit Problems at Vermont Yankee On June 14, 1986, during single rod scram time testing at Vermont Yankee Nuclear Plant, Vermont Yankee Nuclear Power Corporation (the licensee) reported that one control rod failed to scram and five others hesitated from 5 to 7 seconds before scramming. The failure of these control rods to function correctly was attributed to the failure of their respective scram solenoid pilot valves (SSPVs). Vermont Yankee is a General Electric-designed boiling water reactor (BWR) located in Windham County, Vermont.

At Vermont Yankee, each control rod has two electrically controlled SSPVs; when activated by a scram signal, these valves' divert air from the normally closed air-operated scram inlet and outlet valves. When the scram inlet and outlet valves open, high pressure water is directed into the control rod drive mechanism causing the control rod to move into the reactor core.

The cause of the six SSPV failures was determined to be attributed to three types of problems: (a) in the SSPV associated with the failure to scram, the core spring of the SSPV was separated from the core assembly; (b) on another SSPV, the diaphragm was installed backwards on the exhaust side of the solenoid valve; and (c) on the remaining four SSPVs, an incorrect core assembly was installed in the valve. During the outage that preceded Vermont Yankee's single rod scram time tests, all 178 SSPVs were refurbished with replacement kits supplied by the General Electric Company (GE). Evaluation of the above failed SSPVs revealed that five of the six were refurbished with defective replacements kits.

An NRC inspection at GE's facilities in San Jose, California revealed that the six failed SSPVs were refurbished using defective kits that were part of a 3000-kit shipment from the Automatic Switch Company (ASCO) to GE. GE subse-quently issued Service Information Letter (SIL) No. 441 dated July 17, 1986 recommending corrective action for all BWR owners. This corrective action consisted of the following: (a) continued control rod surveillance per Technical Specifications to detect SSPV performance deterioration; (b) return of all unused SSPV replacement kits to GE-for reinspection; (c) inspection for correct engagement of the coil spring onto the core assembly for all kits during SSPV refurbishment at the reactor site; and (d) verification of SSPV operability

, through scram valve time tests or single rod scram time testing. NRC Inspection and Enforcement Information Notice No. 86-78 dated September 2, 1986 was issued to ensure that all licensees were aware of this problem and of the appropriate corrective actions (Ref. C-1).

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The problems experienced at Vermont Yankee represent a small percentage of the total number of replacement kits (approximately 21,000) delivered to BWRs since 1979. Of the six SSPVs that failed, only the core spring separation caused a failure to scram while the other discrepancies led to delayed scram initiation.

The planned single rod scram testing before plant startup, following the SSPV refurbishment, demonstrated that such testing is a prudent method of determining control rod drive mechanism operability and of exposing such anomalies. However, in the event the prestartup testing had not identified the scram anomalies, the small number and random occurrences of these anomalies would not have prevented controlled shutdown of the plant. Furthermore, all of the control rods with these SSPV anomalies would have been inserted during a plant scram by the existing scram air header backup scram valves.

Even though the event had minimal effect on public health or safety, the condition did degrade the BWR scram system. The SSPVs are considered as the primary means for safe reactor shutdown.

The event is of interest because it represents multiple failures of components resulting from a single root cause, which had possible generic implications.

2. Reactor Fuel Failures at McGuire Unit 1 On June 26, 1986, debris was discovered on the McGuire Unit 1 reactor core baffle plate r. ear core location P-3, while performing the Reactor Core Verification procedure following the Unit I reactor core reload. McGuire Unit 1 utilizes a Westinghouse-designed pressurized water reactor. The plant is operated by Duke Power Company and is located in Mecklenburg County, North Carolina. Video inspections of the reactor core baffle plate revealed what was suspected to be loose fuel pellets near core location P-3. A video inspection of the reactor core confirmed the presence of four whole fuel pellets and some pieces of fuel pellets near core location P-3. Unit 1 was in Mode 6 (Refueling) at the time of the discovery.

On June 27, a task force was organized by McGuire Nuclear Station (MNS) management to address the possible loss of fission products. The loose fue! ,

pellets, pieces of fuel pellets, and other debris found in the reactor core I were placed in a container and stored in the spent fuel pool. Face 1 of fuel assembly 0-03 was identified as having damage to fuel rods 15, 16, and 17; the fuel assembly was removed from the reactor core and stored in the spent fuel pool. Personnel began unloading the reactor core on July 2; this was completed ,

on July 4. The reactor core was redesigned without fuel assembly D-03. The l reactor baffle joints (gaps) near reactor core location P-3 were measured. l Fuel assemblies that had resided in reactor core location P-3 were inspected.

Fuel assemblies located in the center reactor baffle locations were also inspected. Following the inspections of the reactor core area and fuel assemblies, the reactor core was loaded starting on July 27, and was completed 1 on July 31. )1 Based on the indications of iodine activity in the Unit 1 reactor coolant system, it has been concluded that the fuel damage to fuel assembly D-03 38 l

likely occurred just after the beginning of core cycle 3, followed by a slight further degradation throughout the remainder of the core cycle. This conclusion is further supported by an increase in neptunium-239 (Np-239) activity from the l

end of core cycle 2 into core cycle 3.

l There were an estimated five leaking fuel rods present during core cycle 3.

l These consisted of three damaged fuel rods in fuel assembly D-03 and two additional fuel rods (based on assumed core average power level) with well developed defects, most likely carried over from core cycle 2.

Fuel assembly D-03, located in reactor core location P-3, during core cycle 3, was damaged on tha face of the fuel assembly parallel to the baffle plate.

The damage found indicates an enlarged corner baffle gap. The resulting increased jet of water flows parallel to the face of the fuel assembly between the fuel assembly and the adjacent baffle plate. This type of flow also causes fuel rod swirling and vibration to occur at the rod locations that were damaged on fuei assembly D-03. The baffle jetting-induced rod motion also causes fuel rod fretting resulting in abnormal clad wear against the Inconnel grid strap assemblies. Baffle jetting parallel to the fuel rods ultimately results in failure of adjacent fuel rods.

The damaged fuel was in a low power region of the core reducing the potential for fission products in the coolant. The coolant activity remained within

~

Technical Specification limits the entire cycle with one post-trip exception.

The observed fuel failures had no effe::t on public safety or the environment and did not result in radioactivity levels or effluent r21 eases in excess of those allowed by the operating license. Since the particular fuel damage was not considered a major degradation, the incident was deemed not reportable as an abnormal occurrence.

Similar fuel damage in certain Westinghouse-designed plants have been reported previously in the NUREG 0090 quarterly abnormal occurrence series of reports.

Appendix C, item 2 of NUREG-0090, Vol. 5, No. 2, discussed fuel degradation at the Trojan Nuclear Plant which was discovered by Portland General Electric Company during inspections on April 26, 1982. Appendix C, Item 3 of NUREG-0090, Vol. 6, No. 1, discussed fuel degradation at Farley Unit 1 which was discovered by Alabama Power Company during inspections on January 29, 1983.

3. Uncontrolled Withdrawal of a Single Control Rod at Grand Gulf Unit 1 On July 30, 1986, while Grant dulf Unit 1 was operating at 69% power, a single control rod continued drifting out of the core after receiving a single notch withdrawal command. The rod failed to insert on demand and continued to withdraw to the full-out position. Operators redaced reactor power, inserted the rod fully, and hydraulically disarmed it.

Grand Gulf Unit 1, operated by System Energy Resources, Inc. (formerly operated by Mississippi Power and Light Company), utilizes a BWR-6 designed by General Electric Company (GE). The plant is located in Clairborne County, Mississippi.

39 m

As the control rod pattern was being changed in preparation for a power reduction, an operator' withdrew rod 20-45 one notch from notch position 08 to notch position 10 (notch' positions are even numbered). The " Rod Drif t" and

" Rod Block" alarms occurred and the operator observed that rod 20-45 was at

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notch position 12 and continuing to withdraw. The operator pressed the insert pushbutton several times and observed the "in" light and the " settle" light to illuminate. The repeated notch insertion attempts slowed the rod outward movement, but the rod continued to withdraw to the full-out position'at notch position 48. It is estimated that the. control rod took 3 minutes and 10 seconds to travel from position 08 to position 48. The operator carried out the actions required by the Alarm Response Instructions. As a conservative measure, reactor power was reduced to 60 percent for thermal limit concerns, and a coupling check was performed. Once control of rod insertion was regained, the rod was placed at position 44 and withdrawn back to position 48 to test the Rod Withdrawal Limiter. The rod was declared inoperable, fully inserted, and hydraulically

. disarmed.

Inspections and bench checks were performed on the withdraw control valve, valve C11-F422. The valve demonstrated no sign of abnormal operation, and no fouling of the valve seat surface was evident. It is concluded that temporary particulate accumulation on the valve seating surface caused an incomplete closure of the valve when the withdrawn command was terminated, allowing drive water pressure to leak past the valve and force the drive piston downward.

The C11-F422 valve, manufactured by Automatic Switch Company (ASCO), GE Part No. 105D6025P1, was replaced with a new valve, and the faulty valve was disassembled for inspection. The newly installed valve was retested satisfactorily. The control rod was restored to service on July 31, 1986.

During the investigation it was determined that a General Electric Service Information Letter (SIL) #292 had been issued in July 1979 addressing this situation a1d providing additional recommended operator actions to be.taken should this occur. Appropriate additional operator instructions have been added to the Off-Normal Event Procedure for Control Rod / Drive Malfunctions based on recommendations from SIL #292. The procedure revisions included the following actions to be taken as necessary:

a. Application of continuous control rod insert signal,

b. Manual scram of individual control rod, and

c. Isolation of affected control rod drive.

The event did not constitute a threat to plant safety nor to the safety function of the control rod drive system. The inadvertent control rod ' withdrawal did  ;

not cause fuel safety limits to be exceeded and did not compromise fuel precon- l ditioning limits. The apparent valve malfunction did not affect the ability of 1 the rod to scram. l In the licensee's Final Safety Analysis Report (FSAR), Section 15.4 discusses the evaluation of reactivity and power distribution anomalies. The control rod drift event that occurred at Grand Gulf is most similar to the-FSAR 15.4.2 analysis of a rod withdrawal error (RWE) transient which is postulated to occur at power. The RWE transient at power results from a procedural error j l

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and is effectively mitigated by the single failure proof rod withdrawal ,

limiter (RWL) mode of the rod control and information system (RCIS). In this j analysis, the RWL mode limits the extent of rod (or gang) withdrawal by  ;

initiation of a control rod block signal. This transient is classified as an event of moderate frequency and was determined not to exceed the minimum critical power ratio (MCPR) safety limit. The July 30 rod was not stopped by the RWL. However, analysis of the July 30 rod drift event indicates that the limits on linear heat generation rate (LHGR) and MCPR were not violated.

Certain failures in the control rod system can result in the drifting of an individual rod past the selected position. As occurred at Grand Gulf, the rod can drift to a full-out location. Even so, such an event is considered to be a low frequency incident based on overall BWR operating experience.

It should be noted that even with the exceeding of the MCPR safety limit, the consequences are significantly less severe than the limiting control rod related event analyzed under the category of reactivity and power distribution anomalies, namely the control rod drop accident (FSAR 15.4.9).

On October 16, 1986, information regarding this event, as well as similar events at Pilgrim and Browns Ferry Unit 2 occurring on April 8,1978 and June 24, 1980, respectively, was sent to all BWR licensees by Inspection and Enforcement Information Notice No. 86-89 (Ref. C-2).

4. Management Deficiencies at Turkey Point Nuclear Power Station On August 12, 1986, the NRC issued to Florida Power and Light Company (licensee of Turkey Point Units 3 and 4) a Confirmatory Order, and a Notice of Violation (NOV) and Proposed Imposition of Civil Penalties in the amount of

$300,000, for violations pertaining to various management and procedural control deficiencies (Ref. C-3). Turkey Point Units 3 and 4 are Westinghouse-designed pressurized water reactors located in Dade County, Florida.

The enforcement action was based on a Safety System Functional Inspection conducted by the NRC Office of Inspection and Enforcement during tne periods August 26-30 and September 9-13, 1985, and a followup inspection conducted by NRC Region II during the periods November 4-8 and 18-22, 1985. Other inspections were also conducted by Region II during the period January-6-10 and February 17 - May 15, 1986. The focus of some of these inspections was the auxiliary feedwater system (AFW) and the supporting back-up nitrogen system.

As a result of these inspections, failures to comply with NRC regulatory requirements were identified. Accordingly, Enforcement Conferences to discuss these matters were held in the Region II Office on January 8 and 31, 1986 and at the Turkey Point site on May 9, 1986.

The NOV contained six Severity Level III violations (based on a scale in which Severity Levels I and V are the most and least significant, respectively), each with multiple examples and each assessed a civil penalty of $50,000.

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Item I of the NOV involved significant weaknesses identified in the design control program. These violations indicated that the licensee had not exercised adequate control to ensure that changes required as a result of system modifications were appropriately translated into operating procedures, drawings, system descriptions, and design basis documents. Most of these violations affected the AFW and back-up nitrogen systems. The NRC Staff considered these violations significant because operability of the back up nitrogen system is essential to ensure that the AFW can perform its intended function upon the loss of the non-safety grade instrument air system. The program weaknesses identified could have led to degradation or complete loss i of the safety functions of these systems.

Item II of the NOV involved the failure to satisfy the requirements of 10 CFR Part 50.59. In several cases, adequate safety evaluations were not performed for the effects of: (1) changes made which could lead to AFW steam supply vent failure at low steam pressure conditions; (2) temporary system alterations pertaining to the removal of the AFW governor speed control system; and (3) temporarily adding loads to an engineered safety features electrical bus which could have overloaded the emergency diesel generator supplying that bus. These examples are considered significant because of the repetitive weaknesses demonstrated in this area 'ncluding three previous escalated enforcement actions involving 10 CFR S 50.59 rview deficiencies. It is apparent that the previous corrective actions taken in this area were not adequate.

Item III of the NOV involved two signi.icant violations of Technical Specification (TS) Limiting Conditions for Operation (LCOs). On January 2, 1986, radiography personnel identified three AFW steam supply stop check valves as unacceptable per the acceptance criteria of Tett Request 001-86.

These valves were then inoperable and the system should have been declared inoperable. The operability of the valves was not adequately evaluated and an LC0 was not entered as required by TS 3.8.5. On January 7, 1986, an NRC inspector questioned the operability of the valves. At that time, the valves were acknowledged to be inoperable. Unit 3 was then shut down and Unit 4 was placed in a 72-hour LC0 as required by TS 3.8.5. Unit 4 was subsequently shut down on January 10, 1086. This violation is considered particularly significant in that all functions of the valves should have been questioned when the problem was initially identified on January 2,1986. It was not until January 7, 1986, that the licensee's engineering organization evaluated the radiographic report and determined that the disc guide studs were bent or broken. The second TS violation occurred when on February 12, 1986, the Unit 3 reactor was taken critical with only three safety injection' pumps operable instead of four as required by TS 3.4.1.4.

1 Item IV of the NOV identified weaknesses in the licensee's procedural control '

program. These involved failures to establish or implement adequate procedures and to properly control the revision and distribution of safety-  !

related procedures. These examples indicated that the procedural control program was not fully effective.

Item V of the NOV involved the failure to conduct adequate load capacity testing and monthly surveillance tests of safety-related batteries as required and the failure to conduct adequate preoperational load capacity tests of these same batteries. This violation is significant because surveillance and 1 preoperational testing did not demonstrate the operability of the batteries I l

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as required by TS 3.7. In addition, examples of weaknesses involving the corrective action program were identified in the performance of maintenance activities. This is significant as previous problems were also identified in this area.

Item VI of the NOV involved failures to take prompt and comprehensive corrective actions once deficiencies were identified by the licensee and the NRC. Inadequate corrective actions were taken with regard to: (1) the adjustment of cooling water flow to heat exchangers due to low flow problems without an evaluation of the resulting change in flow to other components also served by the cooling water system; (2) the potential for an intake cooling water valve not to close as intended on a loss of power or control air which was identified in November 1984 but was not properly evaluated until February 14, 1986, at the urging of the NRC; and (3) the misinstallation of component cooling water (CCW) piping for the Unit 4 safety injection pump coolers which caused these coolers to be dependent on the Unit 3 CCW trains. Adequate safety evaluation and administrative controls were not established to assure that the Unit 3 CCW system operated with sufficient redundancy when Unit 4 was operating and Unit 3 was shut down. As a result of these failures to perform adequate evaluations and to take adequate corrective actions in response to identified deficiencies, systems did not satisfy their design requirements under certain conditions. These examples indicate that although the licensee has shown great initiative in identifying potential safety problems, they must demonstrate the same degree of initiative in evaluating and correcting problems once they are identified.

Since early 1984, the licensee has corrected performance problems in several major systems, e.g.; switchyard design change; auxiliary feedwater system upgrades; and instrument power supply replacement and upgrade. In early 1984, the utility embarked on a massive performance enhancement program. The program covered mostly operational and control problems and people problems, but also addressed major site physical improvements that were thought to be important to staff performance. This closely managed program has been updated twice as improvements allowed a clearer view of other problems or causes of problems.

The results include: new buildings which enhance staff performance; a new simulator being ordered; submittal of updated Technical Specifications which is almost complete; enlargement of the on-site staff; and strengthened organization.

The new human factored procedures are more effective and are being followed more consistently. The equipment is better maintained. These add up to a con-dition where significant transienti are rare and of smaller magnitude with fewer intersystem interactions.

The licensee recently responded to the Notice of Violation with enhancements in the design control process, engineering, and the maintenance procedure area as well as numerous additional specific corrective actions.

The NRC recognizes that the licensee had initiated extensive action., to examine all safety systems and to identify and correct problems at Turkey Point. Indeed, some of the violations cited in the enforcement package were identified as a result of these actions. The NRC is encouraged by the programs the licensee has recently instituted and believes these measures are necessary to improve opera-tions at the Turkey Point facilities. The purpose of the Confirmatory Order (Ref. C-3) was to update the original two year old Order and to incorporate the 43

new initiatives being pursued by the licensee. It facilitated control and review of the new activities.

Since the spring of 1986, the NRC has conducted several inspections in addition to the standard program inspections. These included inspection of the licensee's phase 1 and phase 2 selected safety system reviews, the operator requalification progran, accelerated requalification training, emergency operating procedures, emergency diesel generator (EDG) loading safety evaluations, EDG load modifica-tion, and several preoperational tests.

The l'.;ensee submits quarterly reports on programs and meets with Region II mane a ment at least quarterly. These will continue for the duration of the Coni:cmatory Order.

Region II has augmented the standard inspection program. This will continue for the foreseeable future.

While the management / procedural deficiencies described in the enforcement letter are significant, they were determined not reflective of a major breakdown in licensee corporate or plant management, or controls. Therefore, they do not meet the threshold for abnormal occurrence reporting. This is further supported by:

(1) The notice of violation was purposefully structured to contain separate Severity Level III violations involving somewhat different areas, events, and time frames. A much more serious alternative would have been to (a) issue one violation to focus on management,-(b) require an outside consultant to oversee licensee management, and/or (c) issue a 10 CFR S 50.54(f) letter to the licensee to enable the NRC to determine whether the license should be modified, suspended, or revoked.

(2) Due to the time span of inspection involved and the time span of activities involved, many activities were being corrected long before the notice of violation was issued. The licensee's management was already taking strong corrective actions that had already produced pocitive results. Indeed, some of the violations in the NRC enforcement letter were identified as a result of these actions. The Order that was issued folded the new correc-tive actions into a two year old program that had already produced massive changes at the site in virtually every activity.

44

REFERENCES FOR APPENDICES B-1 Letter from James M. Taylor, Director, NRC Office of Inspection and Enforcement, to P. R. Clark, President, General Public Utilities Nuclear Corporation, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties (Investigation Report Nos. H-83-002 and I-84-029).

Docket No. 50-320, September 29, 1986.*

l B-2 Letter from James M. Taylor, Director, NRC Office of Inspection and i

Enforcement, to P. R. Clark, President, General Public Utilities Nuclear Corporation, forwarding an Order Imposing Civil Monetary Penalty, Docket No. 50-320, March 4, 1986.*

B-3 Letter from J. Nelson Grace, Regional Administrator, NRC Region II, to S.A. White, Manager of Nuclear Power, Tennessee Valley Authority, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties, Docket Nos. 50-259, 50-260, and 50-296, September 8, 1986.*

B-4 NRC Generic Letter No. 84-11, " Inspections of BWR Stainless Steel Piping," from Darrell G. Eisenhut, Director, Division of Licensing, NRC Office of Nuclear Reactor Regulation, to all licensees of operating reactors, applicants for operating license, and holders of construction permits for boiling water reactors, April 19, 1984.*

B-5 Letter from James G. Keppler, Regional Administrator, NRC Region III, to B. Ralph Sylvia, Group Vice President - Nuclear, The Detroit Edison Company, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties, Doc,ket No. 50-341, July 29,1986.*

B-6 Letter from John B. Martin, Regional Administrator, NRC Region V, to l William K. Latham, Acting General Manager, Sacramento Municipal Utility (

District, forwarding a Notice of Violation and Proposed Imposition of I

Civil Penalties, Docket No. 50-312, October 22, 1986.*

B-7 Letter from Victor Stello, Jr. , NRC Acting Executive Director for Operations, to Hal Tucker, Chairman, Babcock & Wilcox Owners Group, requesting an evaluation of design of B&W plants for reduction of plant trips and mitigating transient response, January 24, 1986.*

B-8 Memorandum from Victor Stello, Jr. , NRC Acting Executive Director for Operations, to the Commissioners, entitled "B&W Design Reassessement,"

March 21, 1986.*

B-9 U.S. Nuclear Regulatory Commission, Inspection and Enforcement Compliance Bulletin No. 86-03, " Potential Failure of Multiple ECCS Pumps Due to Single Failure of Air-0perated Valve in Minimum Flow Recirculation Line," October 8,1986.*

• Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).

45

f _B-10 U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 85-94, ." Potential for Loss of Minimum Flow Paths.

Leading to ECCS Pump Damage During a LOCA," December ~13, 1986.*

B-11. Letter from William'L.' Fisher, Chief,~ Radiological and Safeguards Branch, NRC Region lIV, to J.C. Staut?.r, Director, Nuclear Licensing and-Regulation, Sequoyah Fuels Corporation,: forwarding NRC-Inspection Report  ;

, No. 40-08027/86-08, Docket No. 40-08027, September 4, 1986.* Correction'

issued by letter dated October 23, 1986.*

B-12 Letter from Richard L. Rangart, Director, Division of Radiation Safety- ,

and Safeguards, NRC Region IV, to J. C. Stauter, Director, Nuclear. l Licensing and Regulation, Sequoyah Fuels Corporation, forwarding NRC Inspection Report No. 40-08027/86-02, Docket No. 40-08027, May'9, 1986.*

B-13 Letter from James M. Taylor, Director, NRC_0ffice of Inspection and i Enforcement, to J. G. Randolph, President,.Kerr-McGee Center, Sequoyah Fuels ,

Corporation, forwarding an Order Modifying License, Docket No. 40-08027, j October 2, 1986.*  !

B-14 Letter'from James M. Taylor, Director, .NRC Office of Inspection and Enforcement, to J. G. Randolph, President, Kerr-McGee Center, Sequoyah a Fuels Corporation, forwarding a Notice of Violation and Proposed 3 Imposition of Civil Penalties, Docket No. 40-08027, October 14, 1986.*

1 B-15 Letter from James G. Keppler, Regional Administrator, NRC Region III, ,

to J. W. Wenrich, President, Ferris State College, forwarding a Notice of

~

4 Violation and Proposed Imposition of Civil Penalties, Docket No. 30-08783, i July 11, 1986.*

l t C-1 U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information 4

Notice No. 86-78, " Scram Solenoid Pilot Valve (SSPV) Rebuild Kit Problems,"

j September 2, 1986.*

4 C-2 U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information i

i Notice No. 86-89, " Uncontrolled Rod Withdrawal Because of a Single Failure,"

October 16, 1986.*

C-3 Letter from James M. Taylor, Director, NRC Office of Inspection' and I j Enforcement, to C. O. Woody, Group Vice President, Nuclear Energy

! Department, Florida Power and Light Company, forwarding a Confirmatory i

' Order and Notice of Violation and Proposed Imposition of Civil Penalties, Docket Nos. 50-250 and 50-251, August'12, 1986.*

i l

1 ij *Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).

j 46 1

35 U S. NUCLE AR E ;.ULATOav COMMIS$104 1 r EPOHT NUM8E4 fAmpaed er F10C. set Yet /We. et eners b.: ' CELIO RAPHIC DATA CHEET NUREG-0090 Vol. 9, No. 3 ut i=st ONs ON t E atnasE g

2. TITLE AND TITLE 3 LEAVE BLANK R por o Congress on Abnormal Occurrences July-Se ember 1986 , , , , , , , ,c,,,,,,,

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Washington, D.C. 55 10 SPON5ORiNG ORGANi2ATION NAUE AND MA. G A00pE55 ftwwoele Ceres 1ta TYPE OF REPORT U. S. Nuclear Regulato- Commission Office for Analysis ar:d valuation of Operational ata Guarterly Washington, D. C. 20555 a a 'oo ""a ' o "~~~ a ='

s Julv-Seotember 1986 12 $UPPLE+ENTARY NC 'E3 g 13,..sioCTam. , ,

g Section 208 of the Energy Reorga zat n Act of 1974 identifies an abnormal occurrence as an unscheduled inciol or event which the Nuclear Regulatory Commission determines to be signif" nt from the standpoint of public health and safety and requires a quarter port of such events to be made to Congress. This report covers th 4pe d July 1 to September 30, 1986. During the report period, there were f 'r.abr mal occurrences at the nuclear power plants licensed to operate. T events pere (1) a differential pressure switch problem in safety systems at aSalle fac lity, (2) abnormal cooldown and de-pressurization transient at a'tawba Unit k (3) significant safeguards deficiencies at Wolf Creek nd Fort St. Vr)in, and (4) significant deficiencies in access controls at Riv Bend Station. ere was one abnormal occurrence at the other NRC licence ; it involved a th apeutic medical misadministration.

There was one abnormal currence reported b an Agreement State; it involved a therapeutic medical mi administration. The re rt also contains information updating some previou y reported abnormal occu ences.

i. occu E NT AN AL n . . u m os oEsca.PToas g ,, p,Ag un Differential P ssure Switch; Low Water Level; SOR, Inc. Cooldown/

Depressurizat on Transient; Auxiliary Shutdown Pr.nel; Lo' of Control Room Test; D sign Deficiency; Safeguards Deficiencies at clear Plants; ' ' "Un l imi t ari Therapeuti Medical Misadministrations; Scram Solenoid Pil Valves;

. .od75A9&dl } T[.0silures; Uncontrolled Withdrawal of Control R

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