Event Notification Report for April 29, 2005

SHIPMENT RECEIVED WITH EXTERNAL REMOVABLE CONTAMINATION


"A package [was received] that exceeded the limits for removable radioactive surface contamination. The package was received on Friday, April 29, 2005, by a permittee authorized under the master materials license issued to the Department of Veterans Affairs, NRC License 03-23853-01 VA. The permittee is the VA Medical Center, Durham, North Carolina. The permittee did not notify the NHPP [National Health Physics Program] until today, May 2, 2005 at approximately 1030 EDT.

"The basis for reporting is under 10 CFR20.1906(d)(1) in that the package, an ammo box being used to deliver radioactive materials, had approximately 840 DPM per square centimeter removable radioactive contamination on the outside.

"The contamination was limited to one small spot on the ammo box exterior. The interior of the box was not contaminated.

"The contamination was identified as Tc [-99m].

"The Cardinal Health Nuclear Pharmacy Services delivered the package.

"The permittee Radiation Safety Officer notified the vendor about the package."

The shipment was by an exclusive use vehicle. The ammo box contained 2 vials with 60.4 mCi Xe-133 and 35 mCi Tc-99m.

EMERGENCY HYDRO GENERATORS AUTO START - UNKNOWN CAUSE

"Event: At 01:05 on 4-29-05, Oconee Nuclear Station received an Emergency Start of both Keowee Hydro Unit emergency power sources. An investigation is in progress to determine the cause of the system actuation. Plant conditions currently do not indicate the need for actuation of the Keowee Hydro Unit emergency power sources. However, this system actuation is being conservatively reported until it can be positively determined whether a valid actuation occurred.

"Initial Safety Significance: Units 2 and 3 remain at 100% power with no issues following the Keowee Hydro Unit emergency start. Unit 1 remains in Mode 5 (refueling outage). No units were affected by the safety system actuation. Plant conditions currently do not indicate the need for actuation of the Keowee Hydro Unit emergency power sources. No other safety systems actuated or exhibited abnormal behavior. Therefore, the safety significance of this condition is LOW."

At the time of this notification, the Keowee units were still running unloaded.

The licensee notified the NRC Resident Inspector.

* * * UPDATE FROM L. GENTRY TO M. RIPLEY 0958 EDT 06/16/05 * * *

"This report is being made under § 50.73(a)(2)(iv)(A) INVALID SPECIFIC SYSTEM ACTUATION

"At 1:05 AM on 4/29/05 an unplanned emergency start of both Keowee Hydro Units occurred. These units are specifically called out in § 50.73(a)(2)(iv) (B) (8) as " hydroelectric facilities used in lieu of EDGs at the Oconee Station." Each Keowee Hydro Unit can supply emergency power to the three Oconee Units via either of two emergency power paths (Overhead path or Underground path).

"This event was initially reported as:
- 50.72(b)(3)(iv)(A) - VALID SPECIFIC SYSTEM ACTUATION
- Event Number: 41649
- Notification Date: 04/29/2005
- Notification Time: 05:22 [ET]
- Event Date: 04/29/2005
- Event Time: 01:05 [EDT]

"Unit status as stated in that notification:
- Unit 1: 0% RP, Mode 5 for a refueling outage
- Unit 2: 100% RP, Mode 1
- Unit 3: 100% RP, Mode 1

"Keowee Emergency Start Channel A actuated. By design, each Emergency Start Channel starts both Keowee Hydro Unit 1 and 2. Both Keowee units did respond and came to rated speed and voltage.

"It was determined from the alarms received and from direct visual inspection that the signal for the Keowee Units to emergency start came from the actuation of the KA relay located in Emergency Start Channel A cabinet. Investigation and troubleshooting of this event was unable to identify the actual cause of the actuation of relay KA. The investigation confirmed that no valid condition existed which would or should have resulted in an automatic signal and there is no evidence of intentional or unintentional actuation using manual actuation switches. Therefore the actuation is determined to be 'invalid'.

"At the time of the event, Oconee Unit 1 was in an outage and a routine Engineered Safeguard Actuation System (ES) Channel 2 surveillance test was in progress. By design ES Channel 2 initiates Keowee Emergency Start Channel B, so DC control power was removed from Keowee Emergency Start Channel B during that test to prevent an unnecessary Keowee Emergency Start signal. Troubleshooting confirmed that the start which occurred was not due to this test in progress. However, the test affected the event slightly in that ES channel 2 also provides a permissive signal which allows Breaker SK-2 to close to connect the underground path to Standby Bus 2. Following the unintentional start, breaker SK-2 closed as designed, which energized Standby Bus 2, as soon as the Keowee Unit connected to the Underground Path achieved adequate voltage. Because there was no actual loss of power on any of the Oconee Units, there was no demand signal to connect Standby Bus 2 to any unit's Main Feeder Bus.

"50.73(a)(2)(iv)(A) requires the following information:

(a) The specific train(s) and system(s) that were actuated - Keowee Emergency Start Channel A actuated. By design, each Emergency Start Channel starts both Keowee Hydro Unit 1 and 2. Both Keowee units responded and came to rated speed and voltage.
Each Keowee Hydro Unit can supply emergency power to the three Oconee Units via either of two emergency power paths (Overhead path or Underground path). They are aligned so that one unit will supply the overhead path and the other unit will supply the underground path.

(b) Whether each train actuation was complete or partial - Other systems, such as the Emergency Power Switching Logic system, must also actuate to automatically connect an emergency power path to a Main Feeder Bus and power Oconee loads. Since this was not a valid event, conditions did not require connection of emergency power to any loads. No complete power train/path alignment was established, therefore the actuation was considered partial.

(c) Whether or not the system started and functioned successfully - The Keowee Hydro Units both started and functioned successfully. As stated above, due to the existence of a signal during an unrelated test, one additional component, breaker SK2, was challenged and operated as designed. Therefore, all challenged components functioned successfully.

The licensee notified the NRC Resident Inspector. Revised the 10 CFR Section designation in the report header according to the update, and notified R2 DO (T. Decker)

REACTOR CORE ISOLATION COOLING FULL FLOW TEST LINE MAY NOT ISOLATE

"On 4/28/05 Grand Gulf provided a call in on an issue with [two] secondary containment isolation valves on the Main Steam Line drain system. [See EN-41645]

"A preliminary detailed review of similar valves has been completed. An additional concern with the Reactor Core Isolation Cooling (RCIC) full flow test line was noted. Specifically preliminary engineering evaluation indicates that during full flow test with flow to the Condensate Storage Tank concurrent with a high drywell pressure secondary containment isolation signal the differential pressure across the valves may prevent adequate design bases closure. Pending further evaluation this issue is conservatively considered reportable under 10CFR50.72(B)(3)(v)(d). Testing of Reactor Core Isolation Cooling with return to the Condensate Storage Tank has been suspended until resolution of this issue."

The licensee notified the NRC Resident Inspector.

MINIMUM SWITCHYARD VOLTAGE REQUIREMENTS NOT MET

"At 0732 [CDT] on April 29, 2005 Quad Cities Station was notified that the calculated post-LOCA switchyard voltage was below the minimum acceptable value required to ensure offsite power would remain available following a design basis accident. As a result, both offsite power sources were declared inoperable and the appropriate Technical Specification Actions were taken for both Units. The ability of the Emergency Diesel Generators to fulfill their design function was not affected by this condition. This event is being reported in accordance with 10CFR50.72(b)(3)(v)(D) as a condition that could have prevented the fulfillment of a safety function given the predicted post-LOCA switchyard voltage. The condition was exited at 0836 [CDT] on April 29, 2005.

"The required minimum post-accident switchyard voltage is 352.9 KV (Unit 1) and 351.0 KV (Unit 2) while the projected post accident voltage, which prompted this notification, was 347.9 KV. During this timeframe, actual switchyard voltage was approximately 358 KV."

The licensee notified the NRC Resident Inspector.

* * * RETRACTION FROM J. COX TO W. GOTT 1906 ET 08/09/05 * * *

"The purpose of this report is to retract ENS report #41652 (April 29, 2005), ENS report 41766 (June 11, 2005), and ENS report #41801 (June 27, 2005). The reports were made following notification that the switchyard predicted voltage was below the required value necessary to ensure that offsite power would remain available following a design basis accident. For each event, both sources of offsite power were declared inoperable, the appropriate Technical Specification required actions were taken for the units, and an ENS notification was made for a condition that could have prevented the fulfillment of a safety function.

"Each Quad Cities unit has two sources of off-site power. For a specific unit, one source is from the switchyard through the unit's Reserve Auxiliary Transformer (RAT) and the second source is from the switchyard through the opposite unit's RAT. Following further analysis of the loading on the RATs during an accident, it was determined that only one source of offsite power to each unit should have been considered inoperable. The analysis determined that because the RAT for the non-accident unit (i.e., the offsite source supplied through the opposite unit) would be carrying a much smaller load, it would not be subject to a degraded voltage condition and resultant isolation from the grid. Therefore, an accident on one unit would not affect the operability of the source of offsite power supplied through the opposite unit's RAT. As a result, only the source of offsite power supplied through the unit's RAT was inoperable. With one source of offsite power available at all times, there was no condition present that could have prevented fulfillment of a safety function, and therefore, these events are not reportable."

The licensee notified the NRC Resident Inspector. Notified R3 DO (R. Lanksbury)

MANUAL REACTOR TRIP - LOWERING STEAM GENERATOR LEVEL ON LOOP #1

"At 2155 EDT on 4/29/2005, Vogtle Unit 1 was manually tripped from 100% power due to lowering steam generator level on loop #1. The main feedwater regulating valve was in manual control and a repair plan was in progress to replace a controlling card which failed earlier in the day. The manual reactor trip caused an automatic aux. feedwater actuation of the motor driven and turbine driven feedwater pumps. All other equipment responded as expected on the trip."

At approximately 1600, the loop #1 main feed regulating valve had failed shut while in the automatic mode of operation. The operator shifted control to manual and opened the valve, preventing a reactor trip. At 2155 the recovery plan was being implemented using a plant procedure. While performing the procedure, the loop #1 feed regulating valve shut. The reactor was manually tripped on lowering steam generator level. All rods fully inserted after the manual reactor trip. Decay heat removal is to the main condenser with steam generator level being maintained using the motor driven aux. feedwater pumps. The plant is in its normal shutdown electrical lineup.

The licensee notified the NRC Resident Inspector.

INVALID SYSTEM ACTUATION

"This report is being made under 50.73 (a)(2)(iv)(A).

"On April 29, 2005, at approximately 0043 Mountain Standard Time, Palo Verde Nuclear Generating Station Unit 2 experienced an invalid 1/2 leg Engineered Safety Feature Actuation Signal (ESFAS) actuation (B train) when operations personnel prematurely implemented a tag out causing loss of vital power to the 'B' train ESFAS cabinet. The following alarms were received; Recirculation Actuation Signal B, Auxiliary Feedwater Actuation Signal-1B, Containment Spray Actuation Signal B, Main Steam Isolation Signal B, Containment Isolation Actuation Signal B, Safety Injection Actuation Signal B, Auxiliary Feedwater Actuation Signal-2B (all Leg 1-3), and Emergency Diesel Generator (EDG) Start Signal B. At the time of the event Unit 2 was in the 'B' train work window for refueling outage 2R12 and not all 'B' train equipment actuated - EDG B, Low Pressure Safety Injection B, Containment Spray B, and the B train Recirculation Actuation Signal sump valves were tagged out of service for maintenance. During the performance of the 'Inadvertent Plant Protection System - ESFAS Actuations' procedure, Operations personnel determined that all 'B' ESFAS equipment operated as expected considering the 'B' train equipment that was tagged out for maintenance."

The licensee notified the NRC Resident Inspector.