Event Notification Report for December 16, 1999

AGREEMENT STATE REPORT - MEDICAL MISADMINISTRATION

The University of Texas Medical Branch at Galveston reported a misadministration to the State of Texas on 12/20/99. The misadministration involved the first patient for an I-131 anti B1 research protocol, sponsored by Coulter. The prescribed therapeutic dose was 55.4 mCi I-131 anti B1. It was discovered on the morning of 12/20/99 that the infusion bag contained a significant residual activity due to the bag apparently not being flushed into the patient. As a result the patient only received 46.7 mCi I-131; 84% of the intended dose.

The sponsor of the research project and the patients referring physician have been notified. Since this is a research protocol, it is not known what the significance of this under dosing will be to the patient's treatment.

AGREEMENT STATE REPORT - LOST P32

"On December 16, 1999, the Agency was notified by the Licensee that a vial of P-32 labeled ATP was missing from the Department of Microbiology. The vial, the inner package, of a shipping container was placed in a storage freezer on November 17, 1999. The vial contained 0.5 millicuries on November 17, 1999. As of December 16, 1999, it contained 0.123 millicuries. An initial search by the Licensee failed to locate the missing vial or its contents. The initial search included surveys of the research laboratory in which the material was stored. The loss was detected on December 15, 1999, when a technician prepared to use the material.

"ASU Department of Public Safety is investigating this incident. ...

"The Agency is investigating the radiation safety issues.

"The FBI and the U.S. Nuclear Regulatory Commission are being notified of this incident."

UNIT 2 SERVICE WATER PUMP 'C' MAY NOT HAVE BEEN CAPABLE OF PERFORMING DESIGN FUNCTION DURING A 7-DAY OUTAGE OF SERVICE WATER PUMP 'B.'

"Routine operations plant surveillance revealed, at approximately 0056 hours on 11/21/99, that the discharge metal expansion joint of Beaver Valley Power Station (BVPS) Unit 2 Service Water System (SWS) pump 2SWS*P21C was deformed outward. 2SWS*P21C was supplying the SWS 'B' Train, since approximately 0425 hours on 11/15/99, while the train normal supply pump, 2SWS*P21B, was out of service for replacement of the pump vacuum break check valve. Due to the unknown condition of the expansion joint, 2SWS*P21C was declared inoperable, and [the] required action of Technical Specifications (TS) 3.7.4.1 was entered. At approximately 0154 hours (same day), Standby Service Water System (SWE) Pump 2SWE*P21B was placed into service to supply [the] 'B' SWS Train, and 2SWS*P21C was removed from service. 2SWS*P21B was returned to service to supply [the] 'B' SWS Train, and the required action of TS was exited at approximately 0035 hours on 11/22/99.

"Investigation has determined that the subject expansion joint most likely deformed, at approximately 1149 hours on 11/09/99 due to water hammer of the 'B' SWS Train piping during safeguards protection system slave relay testing. Subsequent engineering assessment of the as-found condition of the expansion joint is indeterminate whether the capability of the SWS system to perform its intended function under all design basis events was significantly affected. Therefore, during the time frame that 2SWS*P21C was relied upon to maintain operability of the SWS (11/15/99 until 2SWS*P21B was placed into service to supply 'B' SWS Train), it cannot be assured that Unit 2 would have remained within the plant design basis with an additional postulated single failure of redundant SWS Train 'A' that would have prevented the train from mitigating a design basis accident. Throughout the time 2SWS*P21C was relied upon for SWS Train 'B,' the Unit SWE remained fully operable. This notification is applicable to the 1-hour non-emergency event reporting criteria of 10 CFR 50.72(b)(ii)(B), for having been 'in a condition that is outside the design basis of the plant'."

The water hammer which occurred on 11/09/99 was attributed to a failed vacuum break check valve which had corroded closed. The SWS Pump 'C' bellows has been replaced, and required maintenance will be completed by 12/24/99. The pump will be declared operable following post-maintenance testing.

The licensee informed the NRC Resident Inspector.

REACTOR CORE ISOLATION COOLING SYSTEM DECLARED INOPERABLE ON BOTH UNITS DUE TO UNDERSIZED THERMAL OVERLOADS INSTALLED ON THREE (3) VALVES WHICH MAY HAVE PREVENTED OPERATION UNDER WORST CASE CONDITIONS.

"On December 16, 1999, at 1248, the Reactor Core Isolation Cooling System was declared inoperable because the thermal overloads on three system valves were determined to be sized such that the affected valves might not operate during worst case conditions. The affected valves are: 1 (2)-E51-V8 (Turbine Trip and Throttle Valve), 1(2)-E51-F019 (Minimum Flow Bypass to Torus Valve), and 1(2)-E51-F046 (Cooling Water Supply Valve). Analysis also determined that 1(2)-E41-F059 (High Pressure Core Injection Cooling System Water Supply Valve) also contains inappropriately sized thermal overloads; however, the [High Pressure Coolant Injection] System has not been declared inoperable because this valve have been repositioned to its accident position (open), and administrative measures have been taken to maintain the valve in the open position."

"The Reactor Core Isolation Cooling system is a single-train system used to prevent overheating of the reactor fuel in the event of a reactor isolation accompanied by a loss of feedwater. The high pressure High Pressure Coolant Injection system (approximately ten times the flow rate as the Reactor Core Isolation Cooling System) remains operable. Plant technical specifications allow continued operation for 14 days with the Reactor Core Isolation Cooling system inoperable. The Reactor Core Isolation Cooling system is not considered an engineered safety feature at the Brunswick Plant although it is included in plant technical specifications. For these reasons, the safety significance of this event is considered to be low. Engineering calculations are currently in progress to confirm the operability of the [High Pressure Coolant Injection] System.

"Engineering and maintenance personnel are working to determine a corrective action plan at this time."

The licensee informed the NRC resident inspector.

********** UPDATE AT 1107 ON 01/14/00 FROM CHARLES ELBERFELD TO LEIGH TROCINE **********

The licensee is retracting this event based upon the following text which is a portion of a facsimile received from the licensee:

"On December 16, 1999, at 1248 hours, the Reactor Core Isolation Cooling (RCIC) system was declared inoperable because an analysis indicated that the thermal overloads (TOL) on three system valves were sized such that the affected valves might not operate as designed during worst case conditions. The affected valves for both Unit 1 and 2 were as follows:

E51-V8 (Turbine Trip and Throttle Valve)
E51-F019 (Minimum Flow Bypass to Torus Valve)
E51-F046 (Cooling Water Supply Valve)

"Analysis also indicated that the Unit 1 and 2 Cooling Water Supply Valves (E41-F059) for the High Pressure Coolant Injection (HPCI) system had TOLs which were inappropriately sized; however, the HPCI system for each unit was not declared inoperable because each affected valve was placed in its accident position (i.e., open) and maintained in the open position under administrative controls. Based on the declaration of RCIC system inoperability for both units, notification (Event Number 36517) was made to the NRC on December 16, 1999, at 1640 hours, in accordance with 10 CFR 50.72(b)(2)(iii).

"The affected valves were removed from service in accordance with plant technical specifications and procedures, and the appropriately sized TOLs were installed. Subsequent analysis of the effects of the previously installed TOLs indicate that neither the RCIC nor the HPCI systems were rendered inoperable.

"The analyses which initiated this issue stemmed from a question concerning the presence of holding coils in some direct current (DC) powered motor-operated valve (MOV) control circuitry and how the additional current draw from the holding coils affected TOL sizing. Methodology for programmatically determining TOL sizing has evolved over the years as industry knowledge increased due to activities related to assuring MOV performance. Although much conservatism was built in to the procedural guidance for TOL sizing, consideration was not given to some auxiliary loads such as the holding coils. When such consideration was given to the holding coils, in conjunction with the other conservative sizing assumptions; the initial conclusion was that the TOL sizing was inappropriate for design of the identified valves and that the valves/systems were inoperable. (i.e., The presence of the additional electrical load in the circuitry could cause the TOLs to actuate prematurely, preventing required valve stroking.)

"Each of the identified valves was further analyzed with regard to design and actual functional requirements under postulated accident conditions, to better understand the impact of the previously installed TOLs. As found testing of the TOLs indicated that actual performance was significantly better (i.e., longer times to trip) than conservatively assumed from the performance curves. A review of the actual stroke time histories for each valve was performed to identify the longest times for each. The actual running currents for each valve were reviewed. The above listed information was analyzed and factored together to determine the number of strokes available for each valve. These numbers were then compared to the actual number of strokes required during the various accident scenarios for each valve. In all cases, the valves would have met the functional requirements for system operability. The results of the additional analyses concluded that, although the TOL sizing was not optimum for the identified valves, the valves would have performed their functions for the required postulated conditions, and the operability for the RCIC and HPCI systems was not adversely affected by the previously installed TOLs.

"Based on the results of the additional analyses of each of the identified valves, Carolina Power &
Light Company has determined that this event does not meet the 10 CFR 50.72 or 10 CFR 50.73
reporting criteria, and the notification for Event Number 36517 is retracted.

"Supporting information:

"10 CFR 50.72(b)(2), Four-hour reports. If not reported under paragraphs (a) or (b)(1) of this section, the licensee shall notify the NRC as soon as practical and in all cases, within four hours of the occurrence of any of the following: (iii) Any event or condition that alone could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition, (B) Remove residual heat, (C) Control the release of radioactive material, or (D) Mitigate the consequences of an accident.

"10 CFR 50.73(a)(2). The licensee shall report: (v) Any event or condition that alone could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition, (B) Remove residual heat, (C) Control the release of radioactive material, or (D) Mitigate the consequences of an accident."

The licensee notified the NRC resident inspector. The NRC operations officer notified the R2DO (Haag).

24-HOUR REPORT INVOLVING POSSIBLE VIOLATION OF CONDITION OF LICENSEE

"Preliminary investigations indicate that during the preceding operating cycle, the Perry Plant potentially exceeded its rated power level. A GE software change disabled feedwater temperature compensation (FWC). Perry plant uses the 3D MONICORE output in subsequent calculations for power indication. Perry plant reduced power to 98% as a precaution, while Reactor Engineering confirms the power calculation error. A corrective action response team has been assembled, and the scope of the software change is being reviewed for any other possible effects on the plant.

"In February of 1999, during plant coastdown to RFO7, and during subsequent removal of the '6B' feedwater heater, a condition was created in which the plant was operated at 100% power while at a reduced feedwater temperature. Preliminary investigations indicate that the plant could have violated its Operating License during this 2-day period of time.

"This condition is being reported as a possible violation of the Operating License, and accordingly, it is required to be reported (24 hour, and Licensee Event Report) under the Perry Operating License section 2.F."

The licensee plans to inform the NRC Resident Inspector.

* * * UPDATE AT 2040 EST ON 12/16/99 BY S. SANDIN * * *

"The 3D MONICORE did not have a problem. The problem was the 'databank.' This databank has cycle-specific data to support 3D MONICORE calculations.

"The revision of 3D MONICORE was baseline 94 installed in 1996. There were NO changes to the MONICORE programs.

"The databank was the BOC7 databank installed in October 1997."

A value in the databank was set to zero following instructions from the vendor. The licensee did not recognize, and the vendor was unaware, that this data was utilized by another program. This resulted in incorrect temperature compensation during coastdown between 02/07 through 02/09/99 when the "6B" feedwater heater was removed from service.

UNIT 1 CABLE SEPARATION INSIDE CONTAINMENT IS NOT AS DESCRIBED IN THE NRC SAFETY EVALUATION REPORT (SER) SUBMITTED FOR AN EXEMPTION GRANTED IN 1985.

"Description of Condition:

"FPL has identified inconsistencies between FPL's original exemption request for cable separation inside containment (K1) and the NRC SER for Unit 1 Appendix R. The 1985 NRC SER granted approval stating cables were routed on separate elevations, approximately 25 feet apart. However, the NRC 1987 SER granted approval stating cables were separated vertically by at least 25 feet. FPL's original submittal never stated that the cables were vertically separated by 25 feet but that the design was that redundant cables were routed at separate containment elevations. Although the 1987 NRC SER changes appear to be editorially based, it resulted in FPL not being in strict compliance with the latest NRC SER.

"FPL has concluded that its original bases for the Unit 1 inside containment K1 Appendix R exemption remain valid The probability, magnitude, and consequences of a fire in these areas inside containment is extremely low for the following reasons:

1. The containment has a large volume with a high ceiling, which would dissipate the hot gases from a fire to the upper area of containment away from the affected area.

2. The cables in the effected cable tray are self-extinguishing which will minimize fire propagation along the cables.

3. The bottom cable trays are designed with solid bottoms, which effectively act as a radiant energy shield.

4. The main source of combustion inside containment is the oil in the RCP motors. However, the RCP motors are not in the vicinity of the affected cable trays. The affected cable trays are separated from the RCP motors by the biological shield.

5. The combustible loading in this portion of containment is low and in the area where the lack of separation occurs consists of mostly cable insulation, which has a high ignition temperature.

6. There are no fire hazards or ignition sources in the area.

7. All non-IEEE 383 cables are covered with a fire retardant coating.

8. This area has fire detectors, which would provide prompt notification of a fire to the control room.

9. The containment is inspected prior to operation for items that could impact sump operability; therefore, the potential for transient combustibles is precluded. In addition, the containment is a radiation control area with very limited access during power operation. The possibility of introducing new transient combustibles is very small.

"FPL concludes that non-compliance with the NRC approved Unit 1 Appendix R exemption K1 does not constitute an operability concern. The original bases for FPL's exemption request provides reasonable assurance that a fire inside containment would not prevent the loss of any safe shutdown function.

"Immediate Corrective Actions:

1. A containment loose debris inspection is performed following each containment entry during Modes 1-4.

2. If containment entry is being provided for maintenance purposes, an inventory of all material, tools, and other items intended to go into containment is performed.

3. All cable trays on the 18 foot and 23 foot elevations were verified to be free of debris and other fire hazards prior to heatup from the previous refueling outage.

"The NRC resident inspector has been informed of this notification by the licensee."

STATE OF FLORIDA NOTIFICATION INVOLVING RESCUED LOGGER HEAD SEA TURTLE

"[An] endangered Logger Head Sea Turtle was rescued at the Crystal River (CR-3) intake area. The turtle was injured but is expected to live. The Turtle was transported to Florida Power Corp. Mariculture Center. The Florida Department of Environmental Protection was notified at 2047 EST on 12/26/99."

The licensee also informed the NRC Resident Inspector.

AUTOMATIC STARTING AND LOADING OF AN EMERGENCY DIESEL GENERATOR FOLLOWING A LOSS OF OFFSITE POWER TO THE TRAIN 'A' RESERVE AUXILIARY TRANSFORMER RESULTING IN A LOSS OF SPENT FUEL POOL COOLING FOR APPROXIMATELY 38 MINUTES

The following text is a portion of a facsimile received from the licensee:

"[At 2052 on 12/16/99, the] Unit 1 Train 'A' [emergency diesel generator (CD EDG)] automatically started and loaded following [a] loss of offsite power to the 4-kV safeguards buses on Train 'A.' The apparent cause was the trip of the Unit 2 Train 'A' reserve feed transformer (201CD) sudden overpressurization relay. Trip of the 201CD sudden overpressurization relay resulted in opening of breaker 12CD which feeds the Unit 1 reserve feed transformer (101CD) as well as 201CD."

"[Both] units were defueled at the time of the event with the Unit 1 [spent fuel pit (SFP)] pump in service. The loss of offsite power in Unit 1 caused the in-service SFP pump to be de-energized. The Unit 2 SFP pump was [manually] started at 2130 hours. SFP temperature remained constant at 85°F throughout this event."

"The 201CD sudden overpressure relay was defeated, and offsite power was restored to the 101CD transformer. The CD EDG will be unloaded once offsite power is made available."

"Actuation of the 201CD reserve transformer sudden overpressure relay was a result of filling the transformer with dry nitrogen following [planned] corrective maintenance activities."

The licensee stated that both units were defueled with fuel in the common SFP. At the time of this event, offsite power to Unit 2 was being supplied by the normal auxiliary transformer (backfeed). All systems functioned as required, and there was nothing unusual or not understood. At the time of this event notification, the licensee was in the process of removing the CD EDG from service and restoring the Train 'A' reserve feed transformer as the offsite power supply for Unit 1.

The licensee plans to notify the NRC resident inspector.