ML20237G863
| ML20237G863 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse, LaSalle, 05000000 |
| Issue date: | 02/02/1987 |
| From: | James Keppler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | Heltemes C NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| Shared Package | |
| ML20237F649 | List: |
| References | |
| FOIA-87-377, RTR-NUREG-0090, RTR-NUREG-90 NUDOCS 8709030002 | |
| Download: ML20237G863 (73) | |
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- i February 2,1987 MEMORANDUM FOR:
C. J. Heltemes, Jr., Director, Office of Analysis and Evaluation of Operational Data FROM:
James G. Keppler, Regional Administrator, Region III
SUBJECT:
ABNORMAL OCCURRENCE REPORT TO CONGRESS FOR THIRD QUARTER CY 1986 As requested in your January 14, 1987, memo, we have reviewed the subject report. The write-up of the LaSalle 0-ring switch problem is significantly different from that which we submitted initially. It would appear to be much i
too complicated and detailed for a report aimed at a general audience.
In addition, we have identified some information which may not be completely accurate. Our comments on this report are attached as an enclosure. We would l
further suggest that the report be edited carefully tc eliminate unnecessary technical data and make it more readily understandable to a layperson.
Comments on the University of Cincinnati A0 Repcrt and on the Ferris State
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University are also in an enclosure.
I The update section on Davis-Besse (85-7) is now quite outdated and contains little information of consequence. We recommend deleting the update from the Third Quarter report, and including a closecut update in the Fourth Quarter report, since the plant resumed operation in December 1986.
l With consideration of these comments, we concur in the Third Quarter report.
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James G. Keppler Regional Admir.istrator
Enclosures:
As stated cc w/ enclosures:
H. R. Denton, NRR J. G. Davis, NMSS g7o9030002 O70020 1
l E. S. Beckjord, RES GORD0ht E
-377 l
W. C. Parler, GC J. J. Fouchard.PA i
G. W. Kerr', SP l
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ENCLOSURE 1 i
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86-14 Deficient Differential Pressure Switches Found in Safety Systems at LaSalle Facility (a Generic Problem).
1 Title and Paragraph 3 -- Delete deficient in both locations when describing i
the differential pressure switches. The switches are not necessarily deficient (after all, the NRC continues to permit their use); however, the operating i
characteristics of the switches were not fully understood, and therefore the calibration was not adequate. This paragraph should be revised to reflect this. The title could be: Differential Pressure Switch Problem in Safety Systems at LaSalle 1 and 2 (a Generic Problem).
Page 1, Paragraph 4 (Background) -- Add to last line:
if the pressure switches are not adequately calibrated (Rationale for change -- recent testing of LaSalle 50R switches indicated that they a_re reliable).
Page 2, first full paragraph, sixth line -- revise to read: " governor valve unexpectedly opened further, resulting in an increase in pump output and a corresponding rise in reactor water level."
Ninth line -- ran back (two words) the feedwater pump's speed in an attempt to restore the normal water level (delete the description -- 36 inches on the
- r. arrow range recorder, which is meaningless without context).
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Eleventh and Twelfth lines -- when the "B" reactor feedwater pump's control system was reset, the "B" feedwater pump controller automatically ran back (two words) the pump speed to zero.
(Delete "for no apparent reason" -- this was I
later determined to be a normal response.)
i Second paragraph, first and second lines -- Subsequently, separate reactor water level switches responded to the falline water... (this is not part of the reactor protection system).
Fourth line -- The level continued to fall for a few more seconds before the flow from the motor-driven pump began to raise the water level.
Sixth line through the first line of the fourth paragraph -- 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 i
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.
i As the water level was falling, one of the four switches ' tripped at I
approximately 10 inches; the other three did not actuate, and therefore i
no scram signal occurred. (With a switch tripped in iust one channel, the - ~
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condition is called a " half scram.")
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( (continued) 2 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 evaluate the water level drop and the failure of the differential pressure switches to actuate. Shortly after the subsequent shift change, however, the oncoming.....
Page 3, first partial paragraph --
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 50R, Incorporated, of possible malfunctions involving its Series 103 mechanical differential pressure switches. The Alert was terminated at 9:22 a.m., June 2,1986, when all control rods were inserted.
Third paragraph, Line 7 -- At the time of the incident, Unit I was shut down for its first refueling outage. Both units were kept in cold shutdown while...
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Fourth paragraph, beginning Line 5 -- It is inaccurate to describe the switch failure as a setpoint shift. Suggest deleting section, "On June 17... functional l
failure of the switch."
l Fif th paragraph, Line 10 -- shutdown should be two words: shut down.
l Fifth paragraph -- ruggest addi,9 the following parenthetical comment at end of paragraph:
( At LaSalle, however, changing the setpoint and increasing the surveillance testing of the switches has resulted in acceptable performance.),
Page 4 -- The section headed " problem areas" appears to be overly long and technical for an Abnormal Occurrence Report (although most likely appropriate for a document intended for a licensee or technical audience). Should you desire to retain the long discussion, a marked up copy of the draft text is attached to reflect specific Region 111 coments. However, we would suggest replacing the section with the following summary:
A review of the testing performed at LaSalle and discussions with the l
i manufacturer show that there are several potential problems that could account for the erratic behavior of the Series 102 and 103 switches. These problems include a shift of the setpoint caused by calibration under atmospheric pressure instead of actual operation pressures; a shift in setpoint which occurs as the switch is subjected to a constant pressure over a period of time; _
setpoint variation 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,"
that is to require a higher differential pressure to actuate the switch on the k
first actuation than on later actuations.
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( (continued) 3 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.
Page 5, fifth paragraph, Lines 3-5 -- delete "and uncertainties regarding...
corrosion / erosion effects)." This has not been postulated as a potential cause at LaSalle.
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Page 5, sixth paragraph, fourth and fifth lines -- delete: "in the interim" and "however."
Page 6, first paragraph -- revise to read:
" differential pressure switches could remain in service until the NRC reviewed the licensee's long-term plans.
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Attachment:
As stated
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NNN NN g MWR Wti4L K WMD 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 - Review of the testing perfonned at LaSalle, and discussions with the man ~ufacturer, show that there are several potentia's problems that could result in erratic behavior of Series 102 and 103 switches. These problem areas are discussed as follows.
r 6n G\\( OC Differential pressure switches are often calibrated in situ after isolatinal GM M) them from the reactor system. A test rig consisting essentially of4two fiottlesl each containing' water and 2 4-cr a4t Ogen are connected to the differential pressure switch with one bottle on either side of the diaphragm. The differen-tial pressure for calibration is establip,hed by adjusting the gas pressures hori the bottleN Often/ bgh p<egw<pressureWs at or near atmospheric pressure.
the lower Owched tc> ir sth c? 4 dhnhl presswe Nhh, When the 50R Model 103 differential pressure switch is calibrated to a setpoint at atmospheric pressure and then connected to a system operating at a staticg
'3 *,'ppgsure er h t E M pt 6 the actual setpoint shifts ia consh7vatITe} direction, -..
me, me:t c::: w n the pretture rc';uiMd to trip.
Irr min.,mm, c'ther c;n5, L Offs;t of setpci-t due to c!!ibration t EtmospherJc pres;urc hay been (cund te be " the Oppc;it: direction; The manufacturer has stated that each switch has unique characteristics and that switches with the same model number do not all behave in the same way.
It has been postulated that this may be caused by deformation or movement of the 0-rings on the cross shaft when system pressure is applied.
g the location of the lower instrument tap relative to the required setpoint,For M
j:below the tap.
offset may be so large that the switch will not actuate before the level drops c a
'g In this case, the switch would not actuate no matter how low the level dropped.
The manufacturer has indicated to the Staff that factory a, A tests showed an offset between behavior at atmospheric pressure and behavior at
, g cs system pressure and that this information is provided to all customers.
3 It has been the practice at LaSalle to calibrate at atmospheric pressure without com-wp I
pensating for errors due to static pressure effects. TM g on gg pc4 %
For minimum flow applications where it is necessary to open a valve in a me A -
by line to protect a pump in an emergency core cooling system, assurance is needed that offset will not delay that action and result in pump damage.
Testing of Series 103 differential pressure switches at LaSalle showed that application of a static pressure to the switch for a period of time also resulted in a significant shift in the setpoint of g prolonged pressure was generally in the Opp-,gt,h and that the shift due to oirection frem the shift due_
to th in'ti:1 ;ppi ketion -cf :tetic prcwe. mAfter being calibrated at atmo-spheric pressure, a static pressure of 1000 psig was maintained.
A recheck of the setpoint of one switch at the end of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> showed that the setpoint had shifted by a net amount that was nonconservative by about 10 inches.
Subsequent rechecks continued to show shifting but in lesser amounts. To be valid, it appears that calibration and tests would need to be rechecked after static pressure has been maintained for at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. S@@ucwTuswG 5%gp vsrtuw(
to ShriuG To V ccueum N N brzs.
Recent testing at LaSalle has also shown that the point at which trip occurs depends on whether the switch setpoint is being approached from low differential
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ENCLOSURE 2 86-17 University of Cincinnati Page 15, Line 6 -- the thyroid burden for iodine-125 is 720 nanocuries.
85-7 Ferris State Suggest add the following as an addition to the update information:
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, whic: permitted the licensee to authorize individual users of radioactive materials and to approve operating procedures, to a li.nited scope license which requires NRC approval of users and procedures.
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,. /[ga ucgo, UNITED STATES
[, g(/ o,j NUCLEAR REGULATORY COMMISSION
(,", s x.2)E WASHINGTON. D. C. 20sss I
JAN 14 Y MEMORANDUM TOR:
H. R. Denton, Director, NRR J. G. Davis, Director, NMSS E. S. Beckjord, Director, RES l
J. M. Taylor, Director, IE -
W. C. Parler, General Counsel J. J. Fouchard, Director, PA l
G. W. Kerr, Director, SP Regional Administrators FROM:
C. J. Heltemes, Jr., Director Office for Analysis and Evaluation of Operational Data
SUBJECT:
ABNORMAL OCCURRENCE REPORT TO CONGRESS FOR THIRD QUARTER CY 1986 Based on staff response to the AE0D' October 8,1986 memorandum to the Office Directors and Regional Administrators on this subject, we have prepared the enclosed draft Commission Paper (Enclosure 1), the letters of transmittal to
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Congress (Enclosure 2), the Third Quarter CY 1986 Abnormal Occurrence (AO)
Report to Congress (Enclosure 3), ar.d "Other Events Considered for A0 Reporting" (Enclosure 4).
' shows that there are four proposed A0s at the nuclear power plants licensed to operate, one at the other NRC licensees, and one for the Agreement States. There are eight items for Appendix. B (" Update of Previously Reported Abnormal Occurrences") and four items for Appendix C ("Other Events of Interest").
The differences between the items shown in Enclosure 1 and the items suggestec}
1 in our October 8, 1986 memorandum are described below.
i Abnormal Occurrences i
A0 86-17 ("Significant Deficiencies in Access Control and Physical Barriers at River Bend Station") is a new A0 proposed by Region IV. The deficiencies resulted in violations classified as Severity Level II and III and a proposed civil penalty of $65,000, which has been paid by the licensee.
A0 86-18 (" Therapeutic Medical Misadministration") is a new AO.
Region III provided a draf t writeup per request of Paul Bobe of my office. The event occurred during 1984 at the University of Cincinnati Medical Center. On September 26, 1986, the Commission requested the staff to reevaluate the event to determine whether it should be reportable under the requireinen'ts of i
10 CFR 535.41-35.45. On November 28, 1986, the staff concluded it should be classified as a medical misadministration.
It meets the guidelines for A0 reporting since it involved an unscheduled therapeutic dose to parts of the body.
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~ Multiple Addressees 2
A0 AS86-7 (" Therapeutic Medical Misadministration") is a new A0 submitted by an Agreement State (Iowa) to us via OSP. The event meets the guidelines for A0 reporting since it involved an unscheduled therapeutic dose to parts of the body.
In our October 8,1986 memorandum, we noted that Region IV still had an event at Pathfinder Mines Corporation under review for possible A0 reporting. In Region IV's October 24, 1986 reply to our memorandum, they state that since the violation was reduced from Severity Level II to III and the civil penalty was totally remitted, the item should te dropped from further consideration as a possible AO. We agree.
Our memorandum also noted that Region III was having a medical consultant review a therapeutic medical misadministration at Washington University School of Medicine (St. Louis, Misscuri). I Region III's October 27, 1986 reply, they state that the consultant's review is complete and that no A0 threshold levels were met. We agree.
Appendix B Items A0 86-8 (" Emergency Core Cooling System Mini-Flow Design Deficiency"). This A0 was originally reported in NUREG-0090, Vol. 9, No. 2, under the title of l
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" Boiling Water Reactor Emergency Core Cooling System Design Deficiency." Since
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a similar problem has been noted in PWRs, NRR provided ar, update to include this information. The title of the A0 was changed since both BWRs and PWRs are involved.
Appendix C Items Item 4 (" Management Deficiencies at Turkey Point Nuclear Power Station") was proposed by us in our October 8,1986 memorandum as a possible A0.
In reply, Region Il took exception in their memorandum dated November 3,1986.
IE and NRR (including a separate memorandum from the NRR Project Manager for Turkey Point), also have taken exception.
We agree to report the item in Appendix C for the reasons we have included at l
the end of the writeup.
In sumary, it does not appear to represent a major breakdown in licensee corporate or plant management, or controls.
However, we would like to coment on some of the reasons for not reporting it as an A0 which were made either in the staff memorandum responses or in phone l
calls between AEOD personnel and others.
1.
The fact that a large civil penalty consists of several Severity Level III violations, each of which is assessed a relatively small civil penalty, is i
not necessarily germane for A0 reporting. The whole can be considerably more important than its individual parts if it indicates that there are significant management / procedural deficiencies at the plant in several major areas.
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Multiple Addressees 3
2.
The long timetable for the inspections involved, and the long time needed to issue an enforcement action, are not gemane for A0 reporting. An A0 l
should be proposed as soon as sufficient information is available to make i
the determination, regardless of when the events or inspections occurred.
3.
The fact that the licensee has already ta. ken considerable corrective l
l actions after discovery of a deficiency is not germane for determination of A0 deportability. A0s are detemined by the significance of the event or deficiency; the corrective actions would be discussed in the writeup under " Actions Taken to Prevent Recur:ence."
i 4.
In regard to "Perfomance Enhancement Programs," or equivalent, which may be installed at licensees, this could be the basis of an A0 (management /
procedural control deficiencies) if they were installed because of sig-nificant NRC concerns regarding the licensee's performance.
It would not be necessary for the NRC to explicitly require the licensee to install such a program. Items This item (" Degradation of an Emergency Core Cooling Subsystem at Trojan") was proposed as an Appendix C item by Region V.
Based on a discussion between
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Paul Bobe (AE0D) and J. Crews (Region V) on December II,1986, Mr. Crews agreed that based on the information now available, the item did not appear to
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meet Appendix C reporting guidelines. He agree'd the item would better be included in Enclosure 3 to the Comission Paper.
We request your review, coments and concurrence on thi_s memorandum and its enclosures no later than January 28, 1987. Please provide updating information, if necessary, for all of the items in Enclosures I through 4 to reflect any changes in status.
We plan to submit the report to the Comission by late January 1987.
If you have any questions, please contact Paul Bobe at 492-4494
.. O Jr., Director l
e for An ysis and Evaluation of Operational Data
Enclosures:
l As Stated l
l cc w/ enclosures:
J. Sniezek, DEDROGR J. Glynn, RES K. Murphy, Region I R. Whipp, SEC/ADM G. Sjobolm,IE L. Bettenhausen, Region I T. Dorian, OGC E. We.i s s, I E K. Landis, Region II G. Holahan, NRR J. Callan, IE P. Madden, Region II M. Caruso, NRR (3)
R. O'Connell, NMSS J..Strasma, Region III J. Lubenau, SP R. Gramman, NMSS D. Powers, Region IV S. Schwartz, IE R. Hall, TMI-2 CPD M. Emerson, Region IV E. Jordan, IE F. Ingram, PA J. Crews, Region V 1
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DRAFT r-For:
The Commissioners From:
Victor Stello, Jr.
Executive Director for Operations l
Subject:
SECTION 208 REPORT TO THE CONGRESS ON ABNORMAL i
OCCURRENCES FOR JULY-SEPTEMBER 1986 l
Purpose:
Approval of Final Draft l
Discussion: is a proposed letter to the Speaker of the House
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and the President of the Senate covering transmittal of the Section 208 report to Congress for the third quarter of CY 1986.
(. is a final draft of the quarterly report to Congress on abnormal occurrences (A0s). The report covers the period from July 1 to September 30, 1986. This draft incorporates the major comments obtained from staff review of a previous draf t.
The draft report is similar in format to the second quarter CY 1986 report (published as NUREG-0090, Vol. 9, No. 2).
i The draf t report contains five proposed A0s for NRC licensees.
The items are:
86-14 Deficient Differential Pressure Switches Found in Safety Systems at LaSalle Facility.
86-15 Abnormal Cooldown and Depressurization Transient at Catawba Unit 2.
86-16 Similar Significant Safeguards Deficiencies at Several Nuclear Power Plant Sites (Wolf Creek, Fort St. Vrain, and Arkansas Nuclear One).
86-17 Significant Deficiencies in Access Control and Physical Barriers at River Bend Station.
Contact:
Paul Bobe, AE0D X 24494 i
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f The Commissioners 2
86-18 Therapeutic Medical Misadministration (University of Cincinnati Medical Center; Cincinnati, Ohio).
Per the Commission's September 26, 1986 request, the staff reevaluated this 1984 event and recently determined that it should be classified as a medical misadministration).
In regard to A0 86-16, the event meets the Commission approved staff guidelines for selection of medical mis-administrations for A0s (i.e., Part II of NRC Appendix 0212). The event involved an unscheduled
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therapeutic dose to parts of the body.
l The draf t report contains one proposed A0 submitted by i
an Agreement State. The. item is:
l AS86-7 Therapeutic Medical Misadministration (University of Iowa Hospitals and Clinics; Iowa City, Iowa).
This event meets the Comission approved staff guidelines for selection of medical misadministration for A0s (i.e.,
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Part II of NRC Appendix 0212). The event involved an
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unscheduled therapeutic dose to parts of the body.
Appendix B of the draft report contains updating informa-tion for the following previously reported A0s:
j Nuclear Power Plants 1
i 79-3 Nuclear Accident at Three Mile Island - Further information is provided and the item remains open.
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l 85-7 Loss of Main and Auxiliary Feedwater Systems (Davis-Besse) - Further information is provided and the item remains open.
85-14 Management Deficiencies at Tennessee Valley Authority - Further information is provided and the item remains open.
85-20 Management Deficiencies at Fenni Nuclear Power Station - Further infonnation is provided and the item is closed out.
i 86-2 Loss of lategrated Control System Power and Over-
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cooling Transient (Rancho Seco) - Further infonnation is provided, including progress on the reassessment of B&W-designed plants, and the item remains open.
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The Commissioners 3
86-8 Emergency Core Cooling System Mini-Flow Design Deficiency - This item was originally reported in the previous A0 quarterly report and pertained to certain BWRs. The title has been changed and information regarding a similar problem in PWRs is described. The 1, tem remains open.
Fuel Cycle Facilities l
86-3 Rupture of Uranium Hexafluoride Cylinder and Release of Gases (Sequoyah Fuels Corporation; Gore, Oklahoma) - Further information is provided and the item remains open.
Other NRC Licensees 85-4 Unlawful Possession of Radioactive Material (John C. Haynes Company; Newark, Ohio). This previously closed A0 is reopened to provide additional.information. The item is then reclosed.
86-7
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Tritium Overexposure and Laboratory Contamina-tion (Ferris State College; Big Rapids, Michigan) - Further infongation is provided and the item is closed out.
The draft report contains four items for Appendix C
("Other Events of Interest")..The items are:
1.
BWR Scram Solenoid Pilot Valve Refurbishment Kit Problems at Vermont Yankee.
2.
Reactor Fuel Failures at McGuire Unit 1.
3.
Uncontrolled Withdrawal of a Single Control Rod at Grand Gulf Unit 1.
4.
Management Deficiencies at Turkey Point Nuclear Power Station.
When Commission approval is received, the report will be updated, if necessary, before it is published. The report will be designated as NUREG-0090, Vol. 9 No. 3.
There is one item for Enclosure 3 (i.e., items which were candidates for inclusion as A0s, but which in the staf f's judgment did not meet the criteria for A0 reporting after further study) to this Comission Paper. The item is:
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- The Commissioners 4
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Degradation of an Emergency Core Cooling Subsystem at Trojan.
l Recommendations: That the Comission:
1.
Approve the contents.of the proposed Third Quarter CY 1986 Abnormal Occurrence Report to Congress, and 2.
Note that upon approval and publication, forwarding letters to the Speaker of the House and the President i
of the Senate will be provided to the Chairman for signature. Congressional Affairs will then arrange for appropriate distribution to Congress. A Federal Register notice will be issued to announce the avail-1 ability of the quarterly report. In addition, a separate Federal Register notice (describing details of the events) will be issued for all of the A0s at NRC licensees. No press releases are planned.
Scheduling:
While no specific ~ circumstances require Comission action by a particular date, it is desirable to disseminate these quarterly reports as soon as reasonably possible.
It is
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expected that Comission action within two weeks of receipt of the draft would permit the publication and dissemination about three weeks later, if no significant revisions are required.
Victor Stello, Jr.
Executive Director for Operations
Enclosures:
1.
Proposed Letters to Congress 2.
Draf t of Third Quarter CY 1986 Abnormal Occurrence Report to Congress 3.
Other Events Considered for Abnormal Occurrence Reporting e.
Page 1 of 2
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DRAFT (Enclosure 1 of Commission Paper)
The Honorable Jim Wright Speaker of the United States House of Representatives Washington, DC 20515
Dear Mr. Speaker:
Enclosed is the NRC report on abnormal occurrences at licensed nuclear facilities, as required by Section 208 of the Energy Reorganization Act of 1974 (PL 93-438), for the third calendar quarter of 1986.
In the context of the Act, an abnormal occurrence is an unscheduled incident or event which the Commission determines is significant from the standpoint of public health or safety. The report states that for this report period, there were four abnormal occurrences at the nuclear power plants licensed to operate.
The events were (1) deficient differential pressure switches found in safety systems at LaSalle facility, (2) abnormal cooldown and depressurization cran-sient at Catawba Unit 2, (3) similar significant safeguards deficiencies at i
several nuclear power plant sites,' and (4) significant deficiencies ia access control and physical barriers at River Bend Station. There was one abnormal occurrence at the other NRC licensees; it involved a therapeutic inedical mis-f administration.
There was one abnormal occurrence reported by an Agreement
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State; it involved a therapeutic medical misadministration.
The report also contains information updating some previously reported abnormal occurrences.
In addition to this report, we will continue to disseminate information on reportable events.
These event reports are. routinely distributed on a timely basis to the Congress, industry, and the general public.
Sincerely, Lando W. Zech, Jr.
Chairman
Enclosure:
Report to Congress on Abnormal Occurrences (NUREG-0090, Vol. 9, No. 3)
Enclosuro a Page 2 ta 2 DRAFT '
(Enclosure 1 of Comission Paper)
The Honorable George H. W. Bush President of the Senate Washington, DC 20510
Dear Mr. President:
Enclosed is the NRC report on abnormal occurrences at licensed nuclear facilities, as requ red by Section 208 of the Energy Reorganization Act of 1974
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i (PL 93-438), for the third calendar quarter of 1986.
In the context of the Act, an abnormal occurrence is an unscheduled incident or event which the Commission determines is significant from the standpoint of public health or safety.
The report states that for this report period, there were four abnormal occurrences at the nuclear power plants licensed to operate.
The events were (1) deficient differential pressure switches found in safety systems at LaSalle facility, (2) abnormal cooldown and depressurization tran-sient at Catawba Unit 2, (3) similar significant safeguards deficiencies at several nuclear power plant sites,.and (4) significant deficiencies in access control and physical barriers at River Bend Station. There was one abnormal occurrence at the other NRC licensees; it involved a therapeutic medical ris-administration. There was one abnormal occurrence repor ted by an Agreement
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State; it involved a therapeutic medical misadministration.
The report also contains information updating some previously reported abnormal occurrences.
In addition to this report, we will continue to disseminate information on reportable events. These event reports are routinely distributed on a timely basis to the Congress, industry, and the general public.
Sincerely, Lancio W. Zech, Jr.
Chairman
Enclosure:
Report to Congress on i
i Abnormal Occurrences (NUREG-0990, Vol. 9, No. 3)
t NUREG-0090 Vol.'9. No. 3 DRAFT 4
(Enclosure 2 of Comiss, ion Paper)
REPORT TO CONGRESS ON ABNORMAL OCCURRENCES JULY - SEPTEMBER 1986 Status as of October 31, 1986 Date Published: February 1987
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Office for Analysis and Evaluation of Operational Data United States Nuclear Regulatory Conrnission Washington, D.C.
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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 f rom 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) deficient differential pressure switches f'ound in safety systems at LaSalle facility, (2) abnormal cooldown and depressurization transient at Catawba Unit 2, (3) similar significant safeguards deficiencies at several nuclear power plar ~ sites, and (4) significant deficiencies in access control and physical barr..-s at River Bend Station. There was one abnormal occurrence at the other NRC licensees; it involved a therapeutic medical misadministration. There was one abnormal occurrence reported by an Agreement State;.it' involved a therapeutic medical misadministration.
i The report also contains information updating some previously reported abnormal occurrences.
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CONTENTS Page ABSTRACT..........:..............................................
iii PEFACE..........................................................
vii INTRODUCTION.................................
vii THE REGULATORY SYSTEM......................................
vii REPORTABLE OCCURRENCES.......................
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AGREEMENT STATES........................~...................
ix FOREIGN INFORMATION........................................
x REPORT TO CONGRESS ON ABNORMAL OCCURRENCES, JULY-SEPTEMBER 1986..
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i NUCLEAR POWER PLANTS........................................
1 86-14 Deficient Differential Pressure Switches Found in Safety Systems at L Facility (a Generic Problem)aSalle l
I 86-15 Abnormal Cooldown and Depressurization i
Tra ns ien t a t Ca tawba Unit 2.......................
7 86-16 Similar Significant Safeguards Deficiencies i
j a t Several Nuclea r Power Plant Sites..............
10 86-17 Significant Deficiencies in Access Control and Physical Barriers at River Bend Station.......
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FUEL CYCLE FACILI11ES (Other than Nuclear Power Plants)..... 13 OTHER NRC LICENSEES (Industrial Radiographer, Medical Institutions, Industrial Users, etc.).....................
14 86-18 Therapeutic Medical Misadministration.............
14 AGREEPENT STATE LICENSEES...................................
16 AS86-7 Therapeutic Medical Misadminis tra tion.............
16 REFERENCES.......................................................
19 APPENDIX A - AENORMAL OCCURRENCE CRITERIA........................
21 APPENDIX B - UPDATE OF PREVIOUSLY REPORTED ABNORMAL OCCURRENCES..
23 NUCLEAR POWER PLANTS........................................
23 79-3 Nuclea r Accident a t Three Mile Island.............
23 85-7 Loss of Main and Auxiliary Feedwater Systems......
26 85-14 Management Deficiencies at Tennessee Valley Authority..................................
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85-20 Management Deficiencies at Fermi Nuclear Power Station.............................
31 86-2 Loss of Integrated Control System Power ti d Overcool ing Trans ient...................
34' 86-8 Emergency Core Cooling System Nini-Flow Design Deficiency.......................
34 FUEL CYCLE FACILITIES.......................................
36 86-3 Rupture of Uranium Hexafluoride C of Gases........................ylinder a nd Relea se i
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OTHER NRC LICENSEES....'.....................................
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i 85-4 Unlawful Possession of Radioactive Material.......
37 86-7 Tritium Overexposure and Laboratory Contamination...................................
38 APPENDIX C - OTHER EVENTS OF INTEREST.....~.......................
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REFERENCES (FOR APPENDICES)......................................
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PREFACE INTRODUCTION I
i The Nuclear Regulatory Comission reports to the Congress each quarter under provisions of Section 208 of the Energy Reorganization Act of 1974 on any abnormal occurrences involving facilities and activities regulated by the NRC.
An abnormal occurrence is defined in Section 208 as an unscheduled incident or i
event which the Comission determines is signi.ficant from the standpoint of l
public health or safety.
Events are currently identified as abnomal 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 j
i on February 24, 19/7 (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 abnomal occurrence with copies distributed to the NRC Public i
j 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 l
material, and other categories of information available to the NRC. The NRC has determined that only those events, including those submitted by the Agree-l
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ment States, described in this report meet the criteria for abnomal occurrence l
i reporting. This report covers the period from July 1 to September 30, 1986.
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Infomation 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 i
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 pemits; 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 -
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I and quality assurance criteria appropriate for the various activities licensed by NRC. An inspection and enforcement program helps assure compliance with the
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regulations.
Most NRC licensee employees who work with or in the vicinity of radioactive i
materials are required to utilize personnel monitoring devices such as film badges or TLb (thermoluminescent dosimeter) badges. These badges are processed periodically and the exposure results nomally 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 safcly. 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.
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For nuclear power plants, dedicated groups have been fomed 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-i ity, of reports required to be submitted, but also the method used to analyze i
I the cata.
Two primary sources of operational data are reports submitted by the licensees under the Licensee Event Report (LER) system, and under the i
Nuclear Plant Reliability Data (NPRD) system. The fomer system is under the control of the NRC while the latter system is a voluntary, industry-supported system operated by the Institute of Nuclear Power Operations (INPO), a nuclear utility organization.
Some fem 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, I
and/or in license provisions.
In order to more effectively collect, collate, store, retrieve, and evaluate the information concer. ting reportable events, the Atomic Energy Comission (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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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 i 50.73) was established by Commission rulemaking which modified and codified the former LER i
system. The purpose was to standardize the reporting requirements for all l
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-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 Comission's regulations was published in the Federal Register (48 FR 33850) on July 26, 1983, and is described in NUREG-1022. " Licensee Event Report Sy! tem,"
and Supplements 1 and 2 to NUREG-1022.
Also effective January 1,1984, the NRC amended its imediate notification re-quirements of significant events at operating nuclear power reactors (10 CFR 6 50.72). This was published in the Federal Register (48 FR 39039) on August 29, 1983, with corrections (48 TR 40882) pub 1Tshed on September 12, 1983. Among the changes unade were the use of terminology, phrasing, and reporting thresholds that are similar to those of 10 CFR 6 50.73. Therefore, most events reported under 10 CFR 6 50.72 will also require an in-depth follow-up report under 10 CFR 6 50.73.
The NPRD system is a voluntary program for the reporting of reliability data by nuclear power plant licensees. Both engineering and failure data are to be submitted by licensees for specified plant components and systems.
In the
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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 i
licensee participation are being made. The Comission considers the NPRD sys-tem to be a vital adjunct to the LER system for the collection, review, and l
feedback of operational experience; therefore, the Commission periodically moni-tors the progress made on improving the NPRD system.
l Information concerning reportable occurrences at facilities licensed or other-wise regulated by the NRC is routinely disseminated by the NRC to the nuclear industry, the public, and other interested groups as these events occur.
Dissemination includes special notifications to licensees and other affected or interested groups, and public announcements. In addition, infortnation 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 infortned of reportable events occurring in licensed facilities.
l AGREEMENT STATES Section 274 of the Atomic Energy Act, as amended, authorizes the Commission to enter into agreements with States whereby the Comission relinquishes and the ix
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I States assume regulatory authority over byproduct, source and special nuclear materials (in quantities not capable of sustaining a chain reaction). Compa ra-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 cuarterly abnormal occurrence reports to Congress; however, only domestic abnormal occurrences are reported.
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1 REPORT TO CONGRESS M ABNORMAL OCCURRENCES JULY - SEPTEMBER 1986 NUCLEAR POWER PLANTS 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 uf this report, the NRC had detennined that the following events were abnomal occurrences.
86-14 Deficient Differential Pressure Switches Found in Safety Tystems at L.aSalle Facility (a Generic Problen]
The following infortnation pertaining to this generic proolen is also oeing '
repor ted concurrently in the Federal Register.. Appendix A (see the second general criterien) of this report notes that major degradation of essential safety-related equipment can be, considered an abnormal occurrence. In addition, Exarrple 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 occurrence.
Date and place - 6 June 1,1986, LaSalle Unit 2 experienced a feedwater transient tEEE 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 Coun?.v Nuclear Power Station consists of two Units, each utilizing a General. Dectr'ic-designed boiling water reactor. The
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Station is operated by Commonwealth Edison Company (the licensee) and is located in LaSalle County, Illinois.
Subsequent investigation foured that the problem was caused by deficient mechani-cal differential pressure switches supplied by SOR, Incorporated (formerly Static "0" Ring Pressure Switch Company), and that similar switches have been installed in safety systems at many nuclear power plants.
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i Backaround - 10 CFR 550, Appendix A, General Design Criterion 21c(" Protection System Reliability and Testability") requires that the reactor, prttection D
system be highly reliable. Recent experience with. SOR mechanical qiff trential pressure switches at LaSalle'(3s described below)\\ end similar exp,erieda at Oyster Creek has strongly sugg;ested that this may not be the case.
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 EWR licensees tn review plant experience related to mechanical level indication equipment, indicated that analog trip units have better reliability and greater g-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 anclog level transmitters, s
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licensees predominantly as environmentally qualified electrical equipment impor-l tant to safety, as described in 10 CFR 650.49(b). The licensee for LaSalle i
Unit 2 installed SOR Series 103 differential pressure switches in mid 1983 as part of an environmental qualification modification which was perfonned 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 l
system.
l 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 U p "A", the turbine 1
govero valve opened further and caused pump speed and reactar water level to l
start increasing. 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 ranback feedwater pump speed in an attempt to restore water level to the nominal value (36 inches on the narrow range recorder). A i
few seconds later when the control system was reset, the "B" feedwater pump controller automatically ranback the pump speed to zero for no apparent reason, Reactor water level started falling at about 2 inches /second.
i Subsequently, the reactor protection system responded via separate level switches k
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 mo're seconds before turning around.
The minimum reactor scram setpoint required in the technical specification is 11 inches. The level channels are normally set to trip at 13.5 inches, and the operato" are trained to expect reactor scram by the time that the water level reaches 12.5 inche:,. As the level was falling, one of the four reactor scram level switches (the "D" switch) tripped at approximately 10 inches, causing a
" half scram."
As designed, this did not initiate control rod motion. None of the other three level switches tripped during this transient. No reactor scram-l occurred during this transient, either automatically or manually.
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1r. the BWR scram system logic, which is one-out-of-two-taken-twice, at least one instrument channel in each scram system must trip to generate a scram demand signal and thereby initiate control rod motion. Preliminary results of the investigation indicated that the reactor water level fell to a minimum value of about 4.5 inches on the narrow range instrumentation, which is several inches below the specified scram setpoint but still 13 to 14 feet above the top of reactor fuel. The period that the water level was below the specified scram setpoint value was approximately 2 seconds. After feedwater flow was properly controlled, the plant stabilized at a power level of about 45 percent. The "B" scram system half scram was manually reset about 30 seconds later. The power level was increased to 60 percent about 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later.
Shortly after the subsequent shift change, the oncoming shift engineer's review indicated that the reactor ater level appeared to have fallen 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 2
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occurred. Based on this concern, the licensee declared an " Alert " shut the plant down, notif fed the NRC, and subsequently notified 50R, Incor,porated of possible malfunctirens in their Series 103 mechanical differential pressure switches. When all control roos had been inserted at 9:22 a.m. on June 2,1986, the licensee tenninated the " Alert."
On June 2,1986, the NRC determined that the incident warran'ted a thorough investigation. The Administrator for NRC Region Ill 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 level trip channels, the response of the reactor protection system, and related matters.
The licensee continued testing of the reactor scram water level nitches; the additional data demonstrated continued erratic behavior of switch setpoints.
As of June 9,1986, the licensee had also tested 50R 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 olant became suspect. The licensee declared all emergency core cooling systems in both units to be inoperable. Both units were kept in cold shutdown while the investigations continued.
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 l
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
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to the automatic depressurization system failed to function. On June 17, 1986, testing showed that the trippoint had shifted nonconservatively by 25 inches.
In this application, the relative locations of the instrument taps are such that the system could not produce sufficient differential pressure to actuate the switch. Therefore, this amount of shift constituted a functional failure of the switch. 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 differentf.1 pressure switches. A precrser 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 noncenservative setpoint drift, the licensee perfonned daily surveillance until about April 12 when the reactor was shutdown for a six month outage. Increased surveillance frequency did not resohe the problem.
SOR, Incorporated also manufactures 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 3
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- the public. raises serious concern regarding th'e safety and health of plant personnel and Such systems are designed and installed in plants to prevent the 4
occurrences, or ameliorate the effects, of serious accidents.
Problem Areas - Review of the testing performed at LaSalle, and discussions with the manufacturer, show that there are several potential problems that could result in erratic behavior of Series 102 and 103 switches. These problem areas are discussed as follows.
Differential pressure switches are of ten calibrated in situ after isolating them from the reactor system. A test rig consisting essentially of two bottles each containing water and air or nitrogen are connected to the differential pressure switch with one bottle on either side of the diaphragm. The differen-tial pressure for calibration is established by adjusting the gas pressures in the bottles. Of ten, the lower pressure is at or near atmospheric pressure.
When the SOR Model 103 differential pressure switch is calibrated to a setpoint at atmospheric pressure and then connected to a system operating at a static pressure of about 1000 psig, the act.ual setpoint shifts in most cases in the conservative direction toward less differential pressure required to trip. In other cases, the offset of setpoint due to calibration at atmospheric pressure Fas been found to be in the opposite direction. The manufacturer has stated that each switch has unique characteristics and that switches with the same model number do not all behave in ths 'same way.
It has been postulated that this may be caused by deformation or movement of the 0-rings on the cross shaft when system pressure is applied. For water level applications and depending on 6
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the location of the lower instrument tap relative to the required setpoint, offset may be so large that the switch will not actuate before the level drops below the tap.
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in this case, the switch would not actuate no matter how low the level dropped. The manufacturer has indicated to the Staff that factory 4
tests showed an offset between behavior at atmospheric pressure. and behavior at system pressure and that this information is provided to all customers. It has been the practice at LaSalle to calibrate at atmospheric pressure without com-l pensating for errors due to static pressure effects.
For minimo-flow applications where it is necessary to open a valve in a racir.
culation is to protect a pep in an emergency core cooling system, aturance is needed that offset will not delay that action and result in pump damage.
Testing of Series 103 differential pressure switches at LaSalle showed that application of a static pressure to the switch for a period of time also resulted in a significant shift in the setpoint of the switch, and that the shift due to prolonged pressure was generally in the opposite direction from the shift due to the initial application of static pressure. After being calibrated at atmo-spheric precure, a static pressure of 1000 psig was maintained. A recheck of the setpoint of one switch at the end of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> showed that the setpoint had shif ted by a net amount that was nonconservative by about 10 inches. Subsequent rechecks continued to show shifting but in lesser amounts. To be valid, it appears that calibration and tests would need to be rechecked after static pressure has been maintained for at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
Recent testing at LaSalle has~also shown that the point at which trip occurs depends on whether the switch setpoint is being approached from low differential 4
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pressure or high differential press'ure. This is particularly important for automated blocking valves in the recirculation lines which protect emergency core cooling pumps from damage when system flow is low.
When flow decreases to a value below the setpoint, the switches should actuate to open the valves.
Conversely, when flow increases, the switches should deactuate to provide maximum flow to the core.
In addition tt showing offset problems, sonie of the Series 103 switches evidence sticky behavior, i.e., a larger change in differential pressure is required to actuate the switch on the first demand than on subsequent operations and on subsequent tests actuation may be erratic. It is believed that starting friction j
and the condition of the cross shaft surfaces may cause these problems. If the 0-rings stick, then the torque that they apply is added to the torque applied by the calibration spring.
SOR, Incorporated is conducting a long range test with switches that have more highly polished finishes on those parts of the cross shafts that are in contact with 0-rings.
j It has been comon practice at LaSr.lle to actuate the switches several times and then to record the differential pressures required for the third or fourth actuation.
It appears that the licensee has not emphasized that the "as-found" i
I condition of the switch is the value of differential pressure required to actuate the switch during the first demand. It is this value that must b. used to determine whether the switch and its_ system would have performed their intended functions if called upon to do so.
The life of Series 103 switches has been said to be 20 to 40 years. However, C
the shelf life of the elastomeric material used in the 0-rings is considerably j
less than 40 years. The 0-rings may need to be, changed several times during the life of the plant.
Further, there is some concern for the effect of reactor water on the 0-rings, cross shaft surfaces bearing on the 0-rings, and on the diaphragm material, and possible corrosion of the cross shaft bearings.
Cause or Causes - The problems with the Series 103 ' switches at LaSalle appear to be associated with the licensee's procedures for testing them; a possible design deficiency resulting in occasional " sticky operation"; and uncertainties regarding the effective life of the switch components (e.g., shelf life of elas.
tomeric material, reactor water effects, and corrosion / erosion effects).
Actions Taken to Prevent Recurrence Licensee - Commonwealth Edison Company undertook an extensive testing program tn evaluae the nature of the 50R 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 in the interim.
Tne licensee, and the manufacturer, however, 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 w:s later dispatched to the site on June 2,1986, to eve 19 ate 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 i, Sat the SOR Series 102 and 103 5
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dif ferential pressure switches could remain in service until the end of calendar year 1986; however, use beyond that point would asquire additional technical justification on the part of the licensee. That justification has yet to be l
provided.
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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 Information Notice No. 86-47 (Ref. 3) was issued to inform licensees of the erratic behavior of SOR differen-i 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 information notice l
also announced a public meeting of representatives from HRC, General Electric Company, SOR, and interested licensees to discuss the application and performance i
of Series 102 and 103 switches in safety-related systems, which was held on June 12, 1986.
Since the 50R differential pressure switches were installed by many licensees predominantly as environmentally qualified electrical equipment important-to-l 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 50R switches in safety-related syst2ms were taking appropriate remedial actions.
Licensees with 50R switches installed were requested per the Bulletin to determine which of thore Switches are installed in systems which are subject to Limiting Conditions for Oprations
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of the plant Technical Specifications.
For 50R affferential switches that are not in systems subject to Technical Specifications, licensees were expected to g
review the information in the Bulletin and consider actions, if appropriate, i
3 to preclude problemc similar to those discussed in the Bulletin from occurring.
l For SOR dif ferential pressure switchu that were installed in systems subject j
to Technical Specifications, the Bulletin requested licensees to take certain i
actions to assure that these switches and systems will be capable of performing acceptably, if called upon during an actual plant transient or accident.
1 First, the Bullctin requests that each licensed reactor operator (and senior -
l reactor operator) on duty be made aware of the potential problem that may occur l
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 requests licensees to conduct special operability tests of each system that is subject to Technical Specifications that involve 50R 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.
I Lastly, the Bulletin requests licensees to determine what long-term corrective
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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 Gulletin.
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'c-future reports will be made as appropriate.
i maaaaaaa 86-15 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 it: mediate 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 9, 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 their Final Safety Analysis Report (FSAR).
The purposes of the test re to demonstrate:
That the plant can be brought to Hot Standby conditions from a moderate a.
power level (10-25%) using Auxiliary Shutdown-Panel (ASP) controls and following procedure AP/2/A/5500/17 (Loss of Control Roem).
b.
That the plant can be maintained at Hot Standby conditions for 30 minutes' from the ASPS.
That the plant can be brought to Hot Standby and maintained in that condi~
c.
tion with the minimum shift ren"4rements of Technical S cifications (five i
people).
d.
That the reactor coolant 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 crew available to Unit 2 operations) leaving the control room (since this was 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 switch reactor control to these panels and proceed with the test.
7
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Nature and Probable 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 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-l fer of control of steam generator (S/G) power operated relief valves (PORV) to 1
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 I
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 more minutes, pressure had dropped below 1845 psig generating an SI demand i
signal. After another three and one-half minutes of unsuccessful attempts to l
manage the situation from the ASPS and AFWPTCP, control was returned to the l
control room which was staffed by the regular operations shift. The transfer, which automatically initiated a SI, occurred at a pressure of 702 psig, pres-surizer level near 34 percent, and about 100 F subcooling. At this point the l
operators 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 safety. 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.
j j
NRC Resident Inspectors were on site witnessing the test. The NRC Region II i
Office was notified and an Augmented Inspection Team (AIT) was sent to the site i
from the Regional Office to investigate the event. The licensee began investi-gating 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 licen:;ee 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 per-sonnel, and equipment repair. On July 3,1986, Region 11 issued a Confinnation of Action Letter documenting the licensee's comitment to develop a detailed l
l 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 l
Test, af ter 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.
Causa 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 8
e 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 1
l reducing charging pump flow to the reactor coolant pump seals by the very attempts to increase flow.
I Although the main control room PORY controllers had been replaced with safety-releted controllers, the licensee chose not to replace or modify the AFWPTCP controllers. Also, no human engineering deficiency review was performed on j
the shutdown panels.
i Other contributing factors to this event included iriadequate training on the shutdown panel instruments and controls, inconsistencies in labeling of instru-ments and controls, lack of tennination test criteria, and reluctance by the control room crew to assist the shutdown panel crew for fear of invalidating I
the test.
1 Actions Taken to Prevent Recurrence Licensee I
Licensee - In accordance with the restart p~lan, the licensee has taken the l
following corrective actions:
l a.
A review of all Design Changes and Construction Department Shutdown Requests implemented af ter 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, l
Revisions were made to Operating and Abnormal Procedures to reflect changes c.
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.
An existing procedure, Controlling Procedure for Power Escalation, was e.
revised to include more thorough pre-transient test preparation and walk through:. This will include reviews of previous test results. Operating Procedures, At. normal Procedures, and Emergency Procedures, f.
Various problems were identified with Operator Aid Computer indication, The problems are being investigated.
i Personnel had difficulty controlling reactor coolant pump seal flow during 9
the event.
Additional labeling on the ASPS was added to clarify control requirements for 2NV-309, Seal Injection Flow Control Valve. Ti.e appro-l priate operations procedures were also revised to clarify use of the valve.
t.
2NV-148A, Ledtown Pressure Control Valve, failed open during the the event following transfer to the ASP. A poor electrical connection in the control l
9
e circuitry was found and corrected. The control circuit for the valve had I
maintenance perfonned 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 isulation bypass valves. The problem could not be recreated during inves-tigation. The associated Monthly Surveillance Test was performed successfully.
Following the above, tne 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 1001 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 We 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 purpose of this report.
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86-16 Similar Significant Safeguards Deficiencies at Several Nuclear Power Plant Sites The following information pertaining to this event is al'so 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 1
security, such as access control, that significantly weakened the protection against theft, diversion, or sabotage, can be considered an abnormal occurrence.'
l Date and Place - On July 7, 1986, NRC Region IV issued enforcement letters to the licensees of three nuclear power plant stations for serious deficiencies in plant The licensees are:
(1) Kansas Gas and Electric
)
Conpany (physical barriers.KG&E), operator of the Wolf Creek Generatin I
designed pressurized water reactor located in Coffey County, Kansas; (2) Public Service Company of Colorade (PSC), operator of Fort St. Vrain, a General Atomic Corporation-designed high-temperature, gas-cooled reactor located in Wld County, Colorado; and (3) Arkansas Power and Light (AP&L), operator of Arkansas Nuclear One located in Pope County, Arkansas. Arkansas Nuclear One consists of two pressurized water reactors: Unit I was designed by Babcock and Wilcox and Unit 2 was designed by Combustion Engineering.
Nature and Probable Consequences - The July 7, 1986 letters identified serious
'f ailures of the licensees to comply with NRC regulatory requirements pertaining to physical barriers.
in the most serious example, it was detennined at the Wolf Creek Generatino Station that multiple uncontrolled access paths existed l
1 i
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from the Owner Controlled Area (OCd) 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 safegu Nds specialist during reactive inspection No. 50-482/85-44 (Ref. 9). At the Fort St. Vrain Nuclear Station, NRC inspectors identified during routine inspection No. 50-267/85-22 (Ref. 10) two uncontrolled access paths from the OCA to the PA and VA.
In this situation, each access has a barrier installed, but each was evaluated to be inadequate and not capable of preventing an intruder from defeating it easily. At the Arkansas Nuclear One facility, NRC inspectors identified during routine inspections Nos. 50-313/85-26 and 50-368/85-27 (Rei. 11) one uncontrolled access path from the OCA to the PA.
The barrier inside the PA had been secured at one tine but was found broken at i
the time of the inspection and routine surveillance patrols had failed to l
discover this condition.
In all three examples, conditions existed whereby an intruder could have obtained u_ 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 all three plants for a minimum of six to seven months.
Cause or Causes - The cause of these occu ~ences was a failure in management control. At the Wolf Creek Generating Stu. ion and the Fort St. Vrain Nuclear Station, this included design oversight during the system planning stages, construction deficiencies, and the failure of the startup testing / surveillance program to identify these deficiencies. At Arkansas Nuclear One, management oversight failed to ensure that adequate surveillance patrols were performed
(
to identify such conditions. 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 Licensee - In each case identified, the licensee took imediate corrective action to post compensatory guards and install appropriate barriers. At Arkansas Nuclear One, the barrier inside the PA was reinstalled, and a routine surveil lance was initiated to check this and other similar barriers. At Fort St. Vrain l
Nuclear Station, the affected piping was secured with adequate barriers 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 l
and VA to identify all possible points of vulnerability. This work is being conducted by a KG&E Security Passive Barrier Task Force that was formed to review all penetrations M passive barriers to assure that no further problems exist.
All licensees have modified engineering / design change Focedures 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 freek Generating Station identified this condi-
'tTon, NRC Region IV initiated calls to all the Region IV liceasees and to the other NRC Regional Offices to alert them to the possible generic implications of this finding.
11
e On July 7,1986, Region IV issued enforcement letters to the three licensees 1
involved as follows:
j A Notice 'of Violation and Proposed imposition of Civil Penalty in the amount a.
of $40,000 to KG&E (Ref. 12).
b.
A Notice of Violation and Proposed Imposition of Civil Penalties in the amount of $65,000 to PSC (Ref. 13).
i A Notice of Violation to AP&L (Ref.14).
c.
Enforcement conferences were held at the Region IV office on November 25, 1985, with KG8E and January 6, 1986, with PSC to discuss these issues and the correc-tive actions undertaken by the licensee. The specific corrective actions described by the licensees have been evaluated by the NRC.
The NRC has inspected each of these three 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.
86-17 Significant Deficiencies in Access Control and Physical Barriers 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.15), the NRC issued to Gulf States Utilities (GSU), licensee for the River Bend Station, a Notice of Viola-tion and Proposed Imposition of Civil Penalties in the amount of $65,000 for identified deficiencies in the plant's safeguards program pertaining to access control and physical barriers. River Bend Unit 1 is a General Electric-designed boiling water reactor located in West Feliciana Parish, Louisiana.
Nature and Probable Consequences - The August 7,1986 letter identified a Severity Level II violation with four examplee of inadequate access control, and a Severity Level III violation with two examples of inadequate vital area physical barriers. The first violation identified four examples of a failure to adequately control the access of personnel to vital areas. In the most serious example, the licensee incorrectly devitalized the plant auxiliary build-in 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 unde
- 2cted access into vital areas from either the protected area or other 12
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 second violation identified two examples of inadequate vital area physical barriers. Both examples described man-sized openings that had existed since the construction and start-up phase of the facility. This allowed unguarded openings to exist that would have permitted an intruder unauthorized and undetected access into vital areas.
Details of these six items that constitute the. two violations described above are contained in NRC Inspection Reports 50-458/86-11 and 50-458/86-17 (Refs.16 and 17, respectively).
Cause or Causes - The cause of these deficiencies was the failure of management to exercise effective personnel access en~'rol and to recognize and correct plant design deficiencies as they relatet
.o implementation of the security program.
1 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 safegutwis implications of work performed by maintenance / operations personnel. Marking: h4 haen placed on ali piuy>,
hatches, etc., that form part of the vital ar's > ?? cit r to alert personnel to notify Security before removal. The licensee. f.emented an engineering review and walkdown to identify any barrier openingr that existed. B ceptable barriers have been installed to prevent unauthorized access thro ~ ugh 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 undertaken by them. The NRC has inspected the site since the violations were identified and is continuing to review the licensee's corrective action to ensure that the issues are resolved satisfactorily.
This item is ccnsidered 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 occu_rrences.
13
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l l
l OTHER NRC LICENSEES (Industrial Radiographer, Medical Institutions, 1
Industrial Users, etc.)
l There are currently more than S,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 radiographer, medical institutions, and byproduct material
- users, j
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 detennined that the following event was an abnormal occurrence.
86-18 Therapeutic Medical Misadministration The following information pertaining to this event is also being reported concurrently ir. the Federal Register. Append e A (see the general criterion) of this report notes that an event involv % a moderate or more severe impact l
on public health or safety can be consideied an abnormal occurrence.
Date and Place - On September 4, 1984., NRC Region III was notified by the University of Cincinnati Medical Center, Cincir.nati, Ohio, that an iodine-125 radiation source, which had been implanted in a patient, had leaked, causing an unintended radiation exposure of 2,087 rad to the patient's thyroid. The
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leaking radioactive source was one of eight implanted in a patient August 27, f 1984, for treatment of a brain tumor. The eight sources were removed on September 1, 1984 1
The event has not been previously veported as an abnormal occurrence because at the time of the incident it was not classified as a medical misadministration as defined in 10 CFR 935.41-35.45. 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 abnorm.. occurrence, because i
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, j
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 implar,ted in the brain of a terminally ill patient. The next day, iodine-12S contamination was detected in the brachytherapy source storage room (BSRJs 91oassay results showed that the technicians who had worked with the iodine-125 c eds had measurable uptakes of iodine. When the seeds were removed from the patient on September 1, a radiation survey cf 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 F deposition would result in a radiation dose to the thyroid of 2,087 rad.
14
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(A rad is a standard measure of radiation exposure.) Such an exposure would be expected to result in some diminished thyroid function. Drugs are available to compenstte 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-i missible thyroid burden for iodine-125 is 500 nanocuries. The 209 nanocuries l
was received by one of the technicians involved in preparing the iodine-125 l
seeds, and would result in a thyroid dose of about 0.8 rad. This dose would not be expected to result in any clinically de'tectable effects. The doses received by the other people were all considerably less than that received by this technician.
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, The hospital personnel who received iodine uptakes included those who had i
handled cr 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 existed for several days following the discovery of contamination in the BSR.
This positive pressure contributed to the airborne migration of the iodine-125 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 iodine-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 were 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.
Although t!2 contamination of the BSR was extensive, wipe surveys and air samples revealed that the contamination wcs 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 adioining areas showed no detectable radioactivity.
safe) were found to have some residual contamination; they were covered inSome 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 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 reconrnended that the use of the higL intensity iodine-125 seeds be discontinued for this type of raatation therapy, pending a thorough review of the health physics aspects of their 15
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f " N ' >h -
The hospital also constructed a new radiation source storage room with a use.
greater distance between the storage area and the source preparation area. A fume hood was also installed in the room.
N_RC - 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 twrs violationL, 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. 18).
j Followup inspections have been conducted to determine the adequacy of the I
licensee's corrective actions.
j On September 30, 1986, the NRC issued Inspection and Enforcement Information Notice No. 86-84 (Ref.19) to all NRC medical institution licensees to infonn them of this event.
The NRC's Office of Nuclear Naterial Safety and Safeguards, and the NRC's Region 111 Office, are evaluating what additional measures should be taken by the manuf as turer and medical licensees to improve handling procedures for iodine seeds.
The NRC Office for Analysis ar.d Evaluation of Operational Data undertook a review of the incident to deterrrine if there was a generic problem associated with the reuse of high activity iodine-125 seeds in brachytherapy implant proto-
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cols, and to assess any associated health and safety problems. The findings,
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and recommendations for action by various NRC offices, were issued in AE0D/C601 1
during August 1986 (Ref. 20).
This incident is considered closed for the purposes of this report.
AGREEMENT STATE LICENSEES i
Procedures have been developed for the Agreement States to scre w unscheduled i
incidents or events using the same criteria as the NRC (see Appendix A) and report the events to the NRC for inclusica 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 abnonnal occurrence.
Date and Place - On September S,1986, the Iowa Radiol:gical 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.
16
Nature and Probable Consequences - A 60-70 year-old sale, 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 a.1d down into the bronchus tube. The plastic tube was of specific length and was placed at an exact tumor loca. tion in the bronchus tube. After l
the tube was in place a radiation oncologist after-loaded 34 millicuries of iridium (Ir)-192 sealeo seeds.
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.fa., 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.
Imme diately 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 s
the patient's room, when the source was out of the patient, would not have i
received more than 80 mr.
All individuals entering the patient's room during i
(
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 j
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
)
J the source came to rest on his chest.
It is further surmised that the patient I
was unaware of his actions.
Actions Taken to Prevent Recurrence I
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 treatmer.t was to establish standing I
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 patit.nt.
State Agency - No actions are planned by the State Agency.
This item is considered closed for the purpcdes of this report.
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REFERENCES 1.
NRC Generic Design Letter No. 84-23, " Reactor Vessel Water Level Instrumentation in BWRs," from Darrel G. Eisenhut, Directoe Division of 3
)
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 Projects, 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 Infonnation Notice No. 86-47, " Erratic Behavior of Static "0" Ring Differential Pres-sure Switches," June 10, 1986.*
4.
U.S. Nuclear Regulatory Comission, Inspection and Enforcement Bulletin No. 86-02, " Static "0" Ring Differential Pressure Switches," June 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-i ment, Duke Power Company, Docket No. 50-414, June 30,1986.*
i l
6.
Confirmation of Action Letter, from J. Nelson Grace, Regional Administrator,
(
NRC Region 11, 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. B. lucker, 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.*
i 8.
Letter from J. Nelson Grace, Regional Administrator, NRC Region II, t~
H. B. Tucker, Vice President, Nuclear Production Department, Duke Powu 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 revised 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 Insp&ction 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 Peport No. 50-267/
85-32, Dociet No. 50-267, April 7, 1986..
- Available in NRC Public Document Room, 1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fec).
.Nonsafeguards version available in NRC Public Document Room,1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).
19
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1 ll. Letter from J. E. Gagliardo, Chief, Reactor Projects Branch, Division er e
3 Reactor Safety and Projects, NRC Region IV, to Gene Campbell, Senior i
Management Representative, Arkansas Power and Light Company, forwarding Inspection Report No. 50-313/85-26; 50-368/85-27, Docket Nos. 50-313 t.r4 i
50-368, May 8, 1986..
- 12. 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..
- 13. 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, Decket No. 50-267 July 7, 1986..
- 14. Letter from Robert D. Martin, Regional Administrator, NRC Region IV, to John M. Griffin, Senior Vice President - Energy Supply, Arkansas Power and Light Company, forwarding a Notice of. Violation, Docket Nos. 50-313 and 50-368, July 7,1986..
- 15. Letter from Robert D. Martin, Regional Administrator, NRC Region IV, to William J. Cahill, Jr., Senior Vice President, Gulf States Utilities, 1
Docket No. 50-458, August 7, 1986..
i
- 16. Letter from J. E. Gagliardo, Chief, Reactor Projects Branch, Division of Reactor Safety and Projects. NRC Region IV, to William J. Cahill, Jr.,
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Senior Vice President, Gulf States Utilities, forwardir:g Inspection j
Report 50-458/86-11, Docket No. 50-485, June 4, 1986..
- 17. 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, C3cket No. 50-458, June 4, 1986..
- 18. 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.*
19.
U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 86-84, " Rupture of a Nominal 40-Millicurie Iodine-125 Brachy-j
)
therapy Seed Causing Significant Spread of Radioactive Contamination,"
September 30, 1986.*
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20.
Case Study Report, " Rupture of an Iodine-125 Brachytherapy Source at the University of Cincinnati Medical Center," AE0D/0601, 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).
.honsefeguards version available in NRC Public Document Room,1717 H Street, NW, Washington, DC 20555, for inspection and copying (for a fee).
20 I
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1 1
APPENDIX A-ABNORMAL OCCURRENCE CRITERIA The following criteria for this report's abnormal ott.urrence detenninations 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 j
reduction in the degree of protection of the public health or safety. Such an i
event would involve a moderate or more severe impact on the public health or I
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 Comission; 2.
Major degr6dation 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
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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 620.403(a)(1)),
or equivalent exposures from internal sources.
2.
An exposure to an individual in an unrestricted area such that the whole-body dose received exceeds 0.5 rem in one calendar year (10 CFR 520.105(a)).
3.
The release of radioactive material 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 620.403(b)).
4 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.
i 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 s3botage of a facility.
7.
Any substantiated loss of special nuclear material or any substantiated inventory discrepancy which is judged to be significant relative to 21 e.
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nomally expected performance 'and which is judged to be caused by theft I
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 670.52(a)).
- 10. A major deficiency in design, construction, or operation having safety implications requiring imediate 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 Comercial Nuclear Power Plants 1.
Exc-eeding a safet limit of license technical specifications (10 CFR 550.36(c).
2.
Major degradation of fuel integr'ity, primary coolant pressure boundary, or primary containment boundary.
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3.
Loss of plant capability to perform essential safety functions such that a potential release of radioactivity in excess of 10 CFR Part 100
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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 tu 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 650.36(c)).
2.
A major condition not specifically considered in the safety analysis report or technical specifications that requires immediate remedial acti_on.
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3.
An event which seriously compromised the ability of a confinement system to perfom its designated function.
22 L
4 t
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-The referenced Congressional abnonnal occurrence reports below provide rences.
the initial and any updating information on the abnormal occurrences discussed.
Those occurrences not now considered closed will be discussed 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 Abnor, mal 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 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,
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video inspection, core drilling, bulk defueling, and end fitting removal.
i 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 i
total of 10 sampling penetrations were made. These full-length samples of the reactor core (approximately 21/2" 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 mt.ss of material.
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 23
o activities. On August 12, 1986, bulk defueling of the reactor vessel comenced, 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 microorga'nisms 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 microorganism 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.
f 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 42 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 Demineralized 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-11 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 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 i
ar.nulus area between the reactor building and the AFHB. Assembly and start-up testing of the sludge transfer system was also conducted during the period.
24
o e
r Proposal for Disposing Accident Generated Water On July 31,1986, the licensee submitted a proposal for disposing of 2.1 million pilons 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 TVI 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 ifcensee 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 ' vater to the Susquehanna River. However, recognizing the political and public concerns that unique health risks are associated with that disposal methcd, the licensee considers the proposed forced evaporation method as the most desirtble 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 Comission for its considera tion.
THI-2 Enforcement Actions
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On September 29, 1986, the NRC issued a Notice of Violation (NOV) and Proposed
/ Impositio') of Civil Penalty to General Public Utilities Nuclear Corporation (GPUNC), the licensee for TMI-2 (Ref. B-1). A chil 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 Werk 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 penalty 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 fonner 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 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 <as held before an administrative law judge who, in consultation with the parties, scheduled an evidentiary hearing for Spring 1987.
'25-
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TMI-2 Advisory Panel Neeting The Advisor," Panel for the Decontamination of Three Nile 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 proposal 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.
l 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. No. 2.
It is further updated as follows:
The full ACRS Comittee met on Davis-Besse restart on July 11, 1986. The l
Comittee has written a letter supporting restart. The Commission was briefed on July 24,1986, on the plant status by Toledo Edison Company representatives and on the NRC Staff's evaluation of corrective actions. The Comission will be briefed again prior to restart.
i As of mid-October 1986, the current schedule for' criticality is November 23, 1986. Reactor coolant pump shaft replacement is complete. However, reinstalla-tion of motors, testing, and replacement of other equipment which was removed i
for pump access remains to be done. Raychem splice inspection and replacement is ahead of schedule and no longer appears to be'the critical item controlling restart. Critical items include reactor coolant pump testing'and completion of certain maintenance work orders.
Future reports will be made as appropriate.
85-14 Management Deficiencies at Tennessee Valley Authority This abnormal occurrence was originally reported in NUREG-0090, Vcl. 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 as follows:
The NRC Staff, led by a senior management team, has id ntified 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 September 12, 1986. TVA sub-mitted Revision 2 to their Corporate Nuclear Perfonnance Plan and Revision 1 to the Sequoyah Nuclear Performance Plan on July 17, 1986.
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26
~
T l
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Corporate Activities 1
The Staff review of the Corporate Nuclear Performance Plan is essentially complete and the NRC Safety Evaluation of the Corporate Plan will be issued within a few weeks.
The TVA Corporate Plan is generally acceptable to the Staff, subject to their review cf TVA implementation in the coming months.
Conflict of interest issues in connection with TVA's arrangements with Stone and Webster, Bechtel, and others remain unresolved.
The TVA Inspector General (TVA IG) and General Counsel are investigating this matter in response to the
)
U.S. Office of Government Ethics concerns. Related to this satter is a reduc-tion in Bechtel staff level effort on the resolution of employee concerns.
i The ACRS issued its report on TVA and recommendations to the Comission on l
i August 12, 1986. The ACRS agreed with the TVA diagnosis of their management prcblems, believed that immediate technical and management issues are being I
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, providing 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, 19o6) regarding certain discriminatory acts. TVA paid the civil l
l pena?ty and stated their corrective actions, including Mr. White's (TVA's Fanager of Nuclear Power) strong position against H & I.
The Staff is reviewing I
these responses.
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 comunica-tions between the individual and the TVA IG. Arrangements for direct contact between concerned individuals do responded to the Staff and the TVA IG are in,
Selected H & I cases have been transferred from the NRC Office of process.
Investigations (01) to the TVA IG.
O! will monitor the TVA IG's investigation of these issues, j
Sequoyah TVA submitted Revision 1 of the Sequoyah Nuclear Perfomance Plan on July 17, i
1986.
As part of that submittal, Mr. White stated that S c,nected to complete actions necessary for the restart of Sequoyah Unit 2 earlier than ti.c announced date of January 1987.
}
Fajor Issues are described below:
}
l o
Employee Concerns Program On August 29, 1986, TVA submitted their revised program for management of employee concerns received prior to February 1,1986, including ' hose applicable to Sequoyah.
The first group of Sequoyah employee concerns i
27
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,ti
,4 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 prcgram is generally acceptable but that resolution of many individual issues riay impact the Sequoyah restart. Staff technical review teams are ass.gned, 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 Tebruary 1,1986. The Staff l
believes this program is generally acceptab*e, subject to their review of 1
TVA implementation in the coming months.
l o
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 l
j tray supports. This item may impact Sequoyah restart, depending on the l
l progress of TVA implementation and the extent of corrective actions.
o Welding
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TVA and Staff activity in this area are nearing completion. Notwithstanding their innocuous nature, the number of weld discrepancies found during TVA reinspection (and not identified during the original construction) has
(
led the 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 ASM.-scope piping, pipe i
supports, and major component supports.
Techfiical Specification Surveillance Requirements o
NRC inspection efforts identified deficiencies regarding the adequacy of l
the licensee's surveillance test program. TVA acknowledged these concerns.
and has developed a program to reassess tFe adequacy of Sequoyah surveil -
lance procedures and their perfomance. 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.
o 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 j
accident situations. TVA and the Staff are evaluating the adequacy of the isolation provisions to detemine if any corrective measures are required prior to restart. This configuration also exists at Watts Bar, i
I and may exist at other similar Westinghouse facilities.
28
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Watts Bar i
Based on informal discussion with TVA, Watts Bar Unit 1 is not expected to be ready for licensing before May 1987.
pletion of the Design Baseline and Licensing Verification ProPacir.g items are exp of piping and supports, and resolution of employee concerns. gram, reanalysis Fonnal schedules Bar portion of the Nuclear Performance Plan remains uncertain.regar TVA also believes their inability to hire sufficient contract personnel may result in delays to j
their internal schedules.
I Pajor issues are described below:
Design Baseline and Licensing Verification Program o
i 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 confinn 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 reedy 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 iten, to licensing, I
Employee Concern Prcgram o
I As discussed under Sequoyah issues, changes to the employee concern program have been made and TVA is in the process of evaluating Watts Bar 1
The level of effort by TVA contractor staff personnel has been -
l concerns.
impacted by the conflict of interest and contractual matters between TVA and Bechtel.
Periodic inspections of TVA progress are ongoing.
o Weldina 1
TVA continues to reinspect welds at Watts Bar.
Although their data is incomplete TVA expects to expand the scope of the weld inspection effort in the structural area by about 1200 components and is evaluating the need for further expansion in different population groups on the basis of dis-
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crepancies found in the initial sample (the initial sample involved about 1700 components in various systems). TVA is expected to respond to Staff 1
questions regarding the Watts Bar program within the next few weeks.
NRC Region I non-destructive evaluation van has been onsite, and Staff and The consultant inspections of TVA weld activities are ongoing.
l 29
j 1
o 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:
l i
Cable tray supports in the Control Bay area, Diesel Generator Building, and Reactor Building improperly designed with respect to seismic criteria.
l l
Failure to correct deficiencies involving overfilled cable trays and diesel generator maintenance in a timely snanner 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 the first unit to be ready (Suraner 1987).
PJor issues are described below:
O Probabilistic Risk Assessment (PRA) l The Staff met with TVA regarding the (undocketed) draft PRA performed by l
TVA and their contractor in the early 1980s.
TVA and the Staff agreed to I
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 i
j severe accident characteristics will be submitted prior to the restart of any of the Browns Ferry units. On August 15, 1986, TVA was requested to provide the draft PRA for Staff review. This effort is consistent with and will support the NRC Office of Nuclear Reactor Regulation (NRR) ini-tiative on improvement of BWR containment performance.
1 o
Configuration Management / Design Control l
All but a few facility modifications have been suspended pending system-walkdown and verification that the design drawings reflect the as-built plant components. Walkdown activities for the baseline program, which had i
i been suspended pending review of procedures, are expected to resume in l
30 _
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September. Delays in this program, ii turn, could impact some modifications
(
and the program to revise operating and surveillance procedures. The whole baseline program is being re-evaluated for purpose and deptn, and TVA has not briefed the NRC Staff on the Browns Ferry program.
o Weld Inspections Staff-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 considering options for replacement or permanent weld overlay and will meet with the Staff prior to submitting a recommended course of action for Staff review.
l The reinspection of other system piping and structural welds is near com-l pletion. The Staff is planning on a team inspection of the current TVA I
activities in about two months.
l o
Fire Protection Representatives of the NRC Offices of NRR, Inspection and Enforcement, and Region 11 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 i
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.
85-20 Management Deficiencies at Fermi Nuclear Power Station This abnormal occurrence was originally reported in NUREG-0090, Vol. 8, No. 4 l
" Report to Congress on Abnormal Occurrences: October-December,1985," and updated in NUREG-0090, Vol. 9, No. I and Vol. 9, No. 2.
It is further updated as follows.
On Jf.v 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, and 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 l
its startup testing program. Further power level escalation will be permitted following successful completion of the testing activities and NRC review of the licensee's performance.
l i
31 l
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4 Region III established a Restart Tec.n which, together with the NRC resident t
inspectors, have been closely monitoring the ifcensee's performance.
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 July 23-29, 1985, two of the plant's four emergency diesel generators end 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 i
portions of the ECCS systems were not affected by the cutoff of the equip-
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ment cooling water flow.
2.
During the period June 21 through September 2,1985, a valve 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 atmosphere in the reactor's i
primary containment. In addition, a device used to control the buildup of hydrogen in the reactor containment was found to have greater than permitted leakage on August 28, 1985, a condition existing since June 21, 1985.
This would also represent a potential small leakage pathway from the reactor containment into the surrounding reactor building.
j k
3.
The cooling system for the room containing portions of the ECCS was shut off from July 23-24, 1985. Having the room cooler out of service rendered the ECCS equipment technically inoperable. Other ECCS systems remained in service.
l This item is considered closed for the purposes of this' report.
86-2 Loss of Integrated Control System Power and Overcooling Transient I
This abnonnal 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 updated 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 3,1986, and Staff review of the program was initiated.
The week of August 25, 1986, personnel from the NRC Office of Nuclear Reactor Regulation (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 32
1 j
the Integrated Control System (ICS)/Non-Nuclear Instrumentation (NNI) and other instrumentation that resulted from the December 26, 1985 event and the l
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 25, 1985 event, the Emergency Feedwater Initiation and Control System (EFIC) installation and the licensee's performance improvement program. The licensee submitted Amendment No. I to the Rancho Seco Action Plan on September 15, 1986. Primarily, the amendment confinns 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 estimated 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 l
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.
1 Future reports will be made as appropriate.
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Annex i
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 THI-2 accident there has been a growing realization of the sensitivity of B&W plants to operational j
transients. By letter dated January 24, 1986, the NRC Executive Director for Operations infonned the Chairman of the B&W Owners Group (BWOG) that a number j
t 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 NPC Staff subsequently developed a plan for this re-examination and forwarded a i
copy to the Commission on March 21, 1986 (Ref. B-8).
Subsequent to the development of the plan, the Staff encouraged the BWOG to j
take the leadership role in the reassessment of E8W plants. The BWOG comitted 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. On August 29, 1986, the BWOG provided i
Revision 1 to the document incorporating the results of the program to date.
In light of the BWOG commitment'to assume the leadership role in the reassess-ment program, the Staff updated its plan to reflect the BWOG activities.
l The object of the generic evaluation of B&W plants is to reassess the basic requirements and operational cha.acteristics 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 33 i
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operational occurrences, and thereby improve the overall safety of B&W plants, will be identified.
To achieve the objectives, a multi-faceted approach is baing used by the BWOG and the NRC Staff.
Included as part of the reassessment ere:
(1) review of operational transients which have occurred on B&W plants: (2) feedback from j
operational and maintenance personnel, along with the views of NRC Regional 1
personnel and Resident Inspectors; (3) deterministic assessments; (4) prob-abilistic assessments; and (5) computer simulations.
I Tht NRC Staff is actively reviewing the results of the BWOG efforts. Unrking level meetings between the BWOG and the Staff have been held to discu-tne i
system review tasks, the sensitivity study being performed by MPR Associates, and the BWOG Recommendation Tracking System. The system reviews being performed include the Integrated Control System /Non-Nuclear Instrumentation (ICS/NNI),
the'Hain Feedwater (MFW) system, the Emergency feedwster/ Auxiliary Feedwater (EFW/AFW) system, the Secondary Plant Relief systems, and the Instrument Air system. The Staff has concluded that the B.WOG is generally pursuing a broad-based examination of these systems. However, further discussions on the scope of the MFW system review are necessary before the Staff concludes that it is l
I adequate.
l l
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 Comittee meeting on July 11, 1986. Following the full Comittee meeting, the ACRS comented, in a letter dated July 16, 1986 on the B&W plant reassessment program and expressed
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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 Comittee 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.
j Future reports will be made as appropriate.
1 86-8 Emergency Core Cooling System Mini-Flow Design Deficiency Ti.is abnomal occurrence was originally reported in NUREG-0090, Vol. 9, No. 2
" Report to Congress on Abnormal Occurrences: April-June 1986," under the title 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-ities. The following update describes a single failure vulnerability of some pressurized water reactor (PWR) safety injection (SI) systems due to 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 abnonnal occur-rence has been changed to indicate that both certain BRWs and PWRs are affected.
34
e On July 24, 1985, Wisconsin Clectric 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.
i At Point Beach, the discharge lines for each of the SI pumps are conracted to a comon recirculation header to provide a test flow path and a recirculation flow path 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 c)ooling 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 l
valves are designed to fail closed when their control circuits lose electrical power or control sir 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 j
flow recirculation path for the SI pumps at H. B. Robinson. On June 20, 1986, l
Rochester Gas and Electric discovered a similar design deficiency at the Ginna i
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 I
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 would 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 er.sure 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 Enforcement Compliance Bulletin No. 86-03 (Ref. B-9) was issued by the Office of Inspection and Enforcement to inform addressees of recent reports regarding the 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 short-tem corrective actions taken are currently under review by the NRC staff. Reports regarding 35
,e A
longer-term corrective actions will not be received by the staff until after
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January 1,1987, per the requirements of the Bulletin.
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 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 re., air. Reducing these inventories would also allow SFC to resume decontamination activities which had been stopped because of lack of storage sp6ce 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 Comission's decision on restart.
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Region IV is monitoring these operations which have been uneventful to date.
NRC 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 UF, 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 l
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 Pay 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 autho?ize 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 f,r shipment of UF cylinders. The NRC determined that implementation of comitments made by the licensee is essential g
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 hulth impacts of the accident on licensee personnel who were exposed to uranium.
36
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Furthemore, the NRC detemined that additional oversight of facility operations is necessary to provide reasonable assurance that the licensee will be in l
conpliance with Commission requirements if the facility is pemitted to resume operations. Therefore, the Order includes provisions requiring SFC to obtain the servicos of an independent oversight organization and have personnel from i
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 oY 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 NRC-identified violations that reflected a serious breakdown in management controls.
On October 16, 1986, the Commission, in an open meeting, voted 5-0 to authorize the NRC staff to proceed with restart actio.ns. Withdrawal of the NRC restric-tion o,n operations at the facility may take place in the latter part cf 1986, followed by the resumption of production operations.
i 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, j
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 illega7 possession of byproduct (radioactive) materials (americium-241).
Hr. 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, Nr. Haynes is to make restitution of $129,580 l
toward the cost of cleanup of the facility and to no longer deal with nuclear materials.
This item is closed for the purposes of this report.
i 37 i
3 86-7 Tritium Overexposure and Laboratory Contamination l
This abnomal occurrence, involving Ferris State College, Big Rapids, Michigan, I
was originally reported in NUREG-0090, Vol. 9, No.1. " Report to Congress on Abnomal 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 l
20 times the permissible limit. This resulted in the individual receiving a l
calculated whole-body dose of 21 rem. This event is of particular concern be-I cause the individual perfonned an experiment using curie quantities of tritium in liquid fonn 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 af ter urinalysis tests, perfonned 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 i
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event and therefore decided not to inform the Radiation Control Office. NRC l
holds licensees responsible for acts such as this because licensees are responsible to properly train their employees and monitor their work activities.
l t
Item III described additional violations that resulted from inadequate surveys and evaluations, inadequate training and supervision of individuals that used I
licensed material, failure to take. adequate corrective action after radiological hazards were identified, failure to follow procedures, and failure to maintain adequate records.
l 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.
This item is considered closed for the purposes of this report.
l 38 l
.i APPENDIX C 1
OTHER EVENTS OF INTEREST The following items are described below because the by the public to be of public health significance. y may possibly be perceived 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 abnomal occurrences.
1.
BWR Scram Solenoid Pilot Valve Refurbishment Kit Problems at Vemont 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). Yemont Yankee is a General Electric-designed boiling water reactor (BWR) located in Windham County, Vemont.
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 prcblems:
(a) in the SSPV associated with the failure to scram, the
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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 i
assembly was installed in the valve.
During the outage that preceded Vemont Yankee's single rod scram time tests, all 178 SSPVs were refurbished with replacement kits supplied by the General Electric Company (GE). Evaluation of l
the above failed SSPVs revealed that five of the six were refurbished with defective replacements kits.
l 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 issued Service Infomation 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 tc 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 Infomation Notice No. 86-78 dated September 2, j
l 1986 was issued to ensure that all licensees were aware of this problem and of l
the appropriate corrective actions (Ref. C-1).
39
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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 smsil 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 eristing scram air header backup scram valves.
i I
1 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 I reactor core
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baffle plate near core location P-3, while performing the Reactor Core Verification procedure following the Unit I reactor core reload. McGuire Unit I 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 teactor core confirmed the presence of four whole fuel pellets and some pieces of fuel pellets near core location P-3.
Unit I 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 fuel pellets, pieces of fuel pellets, and other debris found in the reactor core were placed in a container and stored in the spent fuel pool.
Face 1 of fuel l
assembly D-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 reactor baffle joints (gaps) near reactor core location P-3 were measured.
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. Fellowing the inspections of the reactor core area and fuel assemblies, the reactor core was loaded starting on July 27, and was completed on July 31.
Based on the indications of iodine activity in the Unit I reactor coolant i
I system, it has been concluded that the fuel damage to fuel assembly 0-03 l
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40 1
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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 i
end of core cycle 2 into core cycle 3.
There were an estimate'i five leaking fuel rods present during core cycle 3.
These consisted of three damaged fuel rods in fuel assembly 0-03 and two additional fuel rods (based on assumed core average power level) with well developed defects, most likely carried over fr,om core cycle 2.
During core cycle 3. fuel assembly D-03 was located in reactor core location P-3.
A subsequent inspection of corner baffle gaps at reactor core location P-3 revealed four baffle gap measurements of 0.005 inches, one baffle gap l
ineasurement of 0.003 inches and three baffle gap measurements of 0.005 inches.
l Reactor core location A-5 had one baffle gap measurement of approximately 0.006 l
inches. Reactor core location E-1 had one baffle gap measurement of 0.003 inches and another of 0.005 inches. All other baffle gap measurements were less than 0.003 inches. The initial instal,lation baffle gaps were less than i
1 0.003 inches per vendor specifications.
Fuel assembly D-03, located in reactor core location P-3, during core cycle 3, was damaged on the face of the fuel assembly parallel to the baffle plate.
i 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 l
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 fuel 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 fuel rod failure to 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 effect on public safety or the environment and did not result in radioactivity levels or effluent releases 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 abnonnal occurrence.
Similar fuel damage in certain Westinghouse-designed plants have been reported previously in the NUREG-0090 quarterly abnonnal 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, Jtem 3 of NUREG-0090, Vol. 6 No.1, discussed fuel degradation at Farley Unit I 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 s
On July 30, 1986, while Grand Gulf Unit I was operating at 69% power, a single ccr. trol rod continued drif ting out of the core after receiving a single notch 41
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t' withdrawal command. The rod failed to insert on demand and continued to withdraw to the full-out position. Operators reduced reactor power, inserted the rod fully, and hydraulically disamed it.
Grand Gulf Unit 1, operated by Mississippi Power and Light Company, utilizes a BWR-6 designed by General Electric Company (GE). The ;lant is located in Clairborne County, Mississippi.
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 Drift" and
" Rod Block" alarms occurred and the operator observed that rod 20-45 was at notch position 12 and continuing to withdraw. The operator pressed the insert 4
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 cratrol rod took 3 minutes and 10 seconds to travel from position 08 to 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 Alam 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
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and withdrawn back to position 48 to test the Rod Withdrawal Limiter. The rod was declared inoperable, fully inserted, and hydraulically disarmed, k
Inspections and bench checks were perfomed on the withdraw control valve, valve C11-F422. The valve demonstrated no sign'of abnormal operation, and no
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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 dri've piston downward.
The C11-F422 valve, manufactured by Automatic Switch Company (ASCO), GE Part No. 10506025P1, 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 Infomation Letter (SIL) #292 had been issued in July 1979 addressing this situation and providing additional recommended operator actions to be taken should this occur. Appropriate additional operator instructions have been added to the Off-Nomal Event Procedure for Control Rod / Drive Malfunctions based on recommendations from SIL #292. The procedure revisions included the
,1 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
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I compromise fuel preconditioning limits. The apparent valve malfunction did not affect the ability of the rod to scram.
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 and is effectively mitigated by the single failure proof rod withdrawal limiter (RWL) mode of the rod control and information system (RCIS). In this t
analysis, the RWL mode limits the extent of rod (or gang) withdrawal by I
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 l
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 drif t to a full-out location. Even so, such an event is considered to be a low frequency incident based on overall BWR operating experience.
l It should be noted that even with the exceeding of the MCPR safety limit, the l
consequences are significantly less ' severe than the limiting control rod i
related event analyzed under the category of reactivity and power distribution l
dnomalies, namely the control rod drop accident (FSAR 15.4.9).
t 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 l
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 l
control deficiencies (Ref. C-3).
Turkey Point Units 3 and 4 are Westinghouse-
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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 the periods l
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, fai-lures 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.
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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.
Item I of the NOV involved significant weaknesses identified in the design
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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.
l drawings, system descriptions, and design basis documents. Most of these violations affected the AFW and back-up nitrog'en systems. The WRC 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 lead to degradation or complete loss 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 saf,ety evaluations were not perfomed for the effects of: (1) changes made which could lead to AFW steam supply vent l
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 i
could have overloaded the emergency efiesel generator supplying that bus. These
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examples are considered significant because of the repetitive weaknesses 1
demonstrated in this area including three previous escalated enforcement actions I
involving 10 CFR 6 50.59 review deficiencies. It is apparent that the previous
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corrective actions taken in this area were not adequate.
Item III of the NOV involved two " gnificant violations of Technical Specification (TS) Limiting Condiuons for Operation (LCOs). On January 2, 1986, radiography personnel identified three AFW steam supply stop check valves as unacceptable per the acceptance criteria of Test Request 001-86.
These valves were then inoperable and the system should have been declared
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inoperable. The operability of the valves was n;t 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 LCO 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 taen 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.
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.
44
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O Item V of the NOV involved the failure to conduct adequate load capacity 1
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 preoperational testing did not demonstrate the operability of the batteries 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 i
NRC.
Inadequate corrective actions were taken with regard to: (1) the adjustment of cooling water flow to heat exchangers due to low flow problems j
without an evaluation of the resulting change in flow to other components also J
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 1
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 compor.ent 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 I
Unit 3 CCW system operated with sufficient redundancy when Unit 4 was operating and Unit 3 wi.: 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
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under certain conditions. These examples indicate that although the licensee has shown great initiative in identifying potential safety problems, they must l
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
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major systems, e.g.; switchyard design change.; auxiliary feedwater system i
upgrades; and instrument power supply replacement and upgrade.
In early 1984, I
the utility embarked on a massive performance enhancement program. The program l
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 perfomance; a new simulator being ordered; submittal of updated Technical Specifications which is i
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-j dition where significant transients are rare and of smaller magnitude with fewer intersystem interactions.
The licensee recently responded to the Notice of Violation with enhancements j
in the design control process, engineering, and the maintenance procedure area as well as numerous additional specific corrective actions.
j The NRC recognizes that the licensee had initiated extensive actions to examine j
eli safety systems and to identify and correct problems at Turkey Point. Indeed, i
1 45 1
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6 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 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 ifcensee's phase 1 and phase 2 selected safety system reviews, the operator requalification program, accelerated requalification training, emergency operating procedures, emergency diesel generator (EDG) loading safety evaluations, EDG load modifica-tion, and several preoperational tests.
The licensee submits quarterly reports on programs and meets with Region 11 management at least quarterly. These will continue for the duration of the Confirmatory Order.
l Region II has augmented the standard inspection program. This will continue l
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
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further supported by:
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(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 l
consultant to oversee licensee management, and/or (c) issue a 10 CFR 6 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 i
violation was issued. The licensee's management was already taking strong l
corrective actions that had already produced positive 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.
46 1
i REFERENCES
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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 l
Civil Penalties (Investigation Report Nos. H-83-002 and I-84-029),
Docket No. 50-320, September 29, 1986.*
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 l
No. 50-320, March 4, 1986.*
l l
B-3 Letter from J. Nelson Grace, Regional Administrator, NRC Region II. to S.A. White, Nanager 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.*
1 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.*
i B-5 Letter from James G. Keppler, Regional Administrator, NRC Region III, to l
[
B. Ralph Sylvia, Group Vice President - Nuclear, The Detroit Edison Company, forwarding a Notice of Violation and Proposed Imposition of y
Civil Penalties, Docket No. 50-341, July 29,1986.*
B-6 Letter from John B. Martin, Regional Administrator, NRC Region V, to William K. Latham, Acting Genercl Manager Sacramento Municipal Utility District, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties, Docket No. 50-312. October 22, 1986.*
B-7 Letter from Victor Stello, Jr., NRC Acting Executive Direct'or 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 Reassessment,"
March 21, 1986.*
1 1
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-Operated 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).
47
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n y
5 (s
B-10 U.S. Nuclear Regulatory Comission, 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.*
l 8-11 Letter from William L. Fisher, Chief, Radiological and Safeguards Branch, NRC Region IV, to J.C. Stauter, Director, Nuclear Licensing and j
Regulation, Sequoyah fuels Corporation, forwarding NRC Inspection Report No. 40-08027/86-08, Docket No. 40-08027, September 4, 1986.* Correction j
issued by letter dated October 23, 1986.*
B-12 Letter from Richard L. Bangart, Director, Division of Radiation Safety and Safeguards, NRC Region IV, to J. C. Stauter, Director, Nuclear 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 0'ffice of Inspection and Enforcement, to J. G. Randolph, President, Kerr-NcGee Center, Sequoyah Fuels Corporation, forwarding an Order Modifying License, Docket No. 40-08027, 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 Fuels Corporation, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties," Docket No. 40-08027, October 14, 1986.*
j B-15 Letter from James G. Keppler, Regional Administrator, NRC Region III,
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to J. W. Wenrich, President, Ferris State College, forwarding a Notice of Violation and Proposed Imposition of Civil Penalties, Docket No. 30-08783,
/
July 11, 1986.*
C-1 U.S. Nuclear Regulatory Commission, Inspection and Enforcement Information Notice No. 86-78 " Scram Solenoid Pilot Valve (SSPV) Rebuild Kit Problems,"
j September 2, 1986.*
C-2 U.S. Nuclear Regulatory Commission, inspection and Enforcement Information Notice No. 86-89, " Uncontrolled Rod Withdrawal Because of a Single Failure,"
October 16, 1986.*
C-3 Letter from Jsmes M. Taylor, Director, NRC Office of Inspection and Enforcement, to C. O. Woody, Group Vice President, Nuclear Energy Department, Florida Power and Light Company, forwarding a Confirmatory Order and Notice of Violation and Proposed Imposition of Civil Penalties, Docket Nos. 50-250 and 50-251, August 12, 1986.*
'Available in NRC Public Document Room, 1717 N Street, NW, Washington, DC 20555, for inspection and copying (for a fee'.
48
1 4-
.=
1 I
l i,
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h The safety consequences of the March 31, 1986 event were minimal, therefore the
(
event is considered below the threshold for abnormal occurrence reporting. The j
event was thqn considered for inclusion in Appendix C (Other Events of Interest") of the quarterly report. However, it did not appear to meet the staff guidelines for Appendix C reporting as contained in Part III of NRC Appendix 0212.
l e
9
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i 3-2
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I i
.a n
,f (Enclosure 3 to the Commission Paper)
OTHER EVENTS CONSIDERED FOR ABNORMAL OCCURRENCE REPORTING
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The following incident is a sample of the incidents seriously considered for abnormal occurrence reporting. The incident is briefly discussed and the reasons why it is not being reported are stated. The incident was judged not i
to have involved any major reduction in the level of protection provided for l
public health or safety.
l l
This enclosure is provided to the Commission per Commission comments on i
SECY-76-471, dated December 2, 1976; the enclosure is not intended to be a part l
of the published report.
1.
Degradation of an Emergency Core Cooling Subsystem at Trojan l
l l
On March 31, 1986 a subsystem of the emergency core cooling system of the Trojan Nuclear Power Plant (Trojan) was observed by an NRC Resident Inspector te be degraded contrary to requirements of the Technical Specifications.
Trojan, operated by Portland General Electric Company (the licensee), is a
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Westinghouse-designed pressurized water reactor plant located in Columbia County, Oregon.
For a one hour and ten minute period on March 31, 1986, a valve in the residual heat removal (RHR) system was closed for preventive maintenance, blocking flow to two of four required injection points while the reactor was in operation.
The RHR system serves principally as a system for removing heat from the fuel when the reactor is shutdown; however,.it also provides a method of low pressure water injection to the reactor core in the event of a loss of coolant accident (LOCA). The RHR system is required to have two separate, redundant trains, each train capable of injecting water at four points.
The isolation of two injection points, which occurred in this instance, would not have resulted in a loss of the RHR system function in the event of a LOCA; however, the violation did result in a significant degradation of the system.
On October 15, 1986, the NRC forwarded to the licensee a Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $50,000.
Apparently, the plant staff had an incomplete understanding of the design basis of the system, and did not realize that all four injection points were required to constitute an operable train. The NRC Staff recognized that the licensee had already initiated programs to improve design bases documentation and to assure that the plant staff understands the design bases when the March 31 violation occurred. These programs were developed by the licensee as corrective action in respons_e to a violation first observed in February 1986 involving a failure to maintain the control room ventilation system in an operable status due to an apparently similar incomplete understanding of that system's design basis.
3-1
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