Event Notification Report for April 07, 2000
U.S. Nuclear Regulatory Commission
Operations Center
EVENT REPORTS FOR
04/06/2000 - 04/07/2000
EVENT NUMBERS
3687336874368753687636877
Power Reactor
Event Number: 36873
Facility: FERMI
Region: 3 State: MI
Unit: [2] [] []
RX Type: [2] GE-4
NRC Notified By: S. MAREK
HQ OPS Officer: JOHN MacKINNON
Region: 3 State: MI
Unit: [2] [] []
RX Type: [2] GE-4
NRC Notified By: S. MAREK
HQ OPS Officer: JOHN MacKINNON
Notification Date: 04/07/2000
Notification Time: 17:15 [ET]
Event Date: 04/07/2000
Event Time: 14:00 [EDT]
Last Update Date: 04/13/2000
Notification Time: 17:15 [ET]
Event Date: 04/07/2000
Event Time: 14:00 [EDT]
Last Update Date: 04/13/2000
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(2)(i) - DEG/UNANALYZED COND
10 CFR Section:
50.72(b)(2)(i) - DEG/UNANALYZED COND
Person (Organization):
THOMAS KOZAK (R3)
THOMAS KOZAK (R3)
| Unit | SCRAM Code | RX Crit | Initial PWR | Initial RX Mode | Current PWR | Current RX Mode |
|---|---|---|---|---|---|---|
| 2 | N | N | 0 | Refueling | 0 | Refueling |
"C" MAIN STEAM LINE FAILS LOCAL LEAK RATE TEST DUE TO EXCESSIVE LEAKAGE
During Local Leak Rate Testing (LLRT) of the "C" Main Steam Line, the as-found leakage could not be quantified. Technical Specification surveillance requirement, SR 3.6.1.3.12 limit of less than 100 scfh combined MSIV leakage rate for all four main steam lines when tested at greater than 25 psig was exceeded. Fermi 2 Main Steam Lines are equipped with a Main Steam Line Isolation Valve Leakage Control System (MSIVLCS) which is designed to maintain pressure between the MSIVs slightly above that of primary containment. Since the leakage could not be quantified, it could not be demonstrated that the leakage did not exceed the capacity of the MSIVLCS.
The NRC Resident Inspector was notified of this event by the licensee.
* * * UPDATE ON 04/07/00 AT 1836 EDT BY S. MAREK TAKEN BY MACKINNON * * *
During LLRT of the "D" Main Steam Line, the as-found leakage could not be quantified. Technical Specification surveillance requirement, SR 3.6.1.3.12 limit of less than 100 scfh combined MSIV leakage rate for all four main steam lines when tested at greater than 25 psig was exceeded. Fermi 2 Main Steam Lines are equipped with a MSIVLCS which is designed to maintain pressure between the MSIVs slightly above that of primary containment. Since the leakage could not be quantified, it could not be demonstrated that the leakage did not exceed the capacity of the MSIVLCS. The "A" & "B" Main Steam Lines passed their LLRT.
The NRC Resident Inspector was notified of this update by the licensee. R3DO (T. Kozak) was notified.
* * * UPDATE AT 0931 ON 4/12/2000 FROM S. MAREK TAKEN BY STEVE SANDIN * * *
"During Local Leak Rate Testing (LLRT) of Main Steam Line drain valve, B2103F019, the as found leakage was 232.7 SCFH, the allowable leakage is 1.00 SCFH.
"The leakage through this penetration X-8 of 232.7 SCFH exceeds Technical Specification surveillance requirement, SR 3.6.1.3.11 Bypass Leakage Total limit of less than 0.04 La, (11.9) SCFH. The total containment leakage is 274.62 SCFH. which is less than 1.0 La of 297.30 SCFH.
"This report is being made in accordance with 10CFR 50.72(b)(2)(i), any event or condition found while the reactor is shutdown that, had it been found while the reactor was in operation, would have resulted in the nuclear plant, including its principal safety barriers, being seriously degraded or being in an unanalyzed condition that significantly compromises plant safety."
The NRC resident inspector has been informed of this update by the licensee. Notified R3DO (Hiland).
During Local Leak Rate Testing (LLRT) of the "C" Main Steam Line, the as-found leakage could not be quantified. Technical Specification surveillance requirement, SR 3.6.1.3.12 limit of less than 100 scfh combined MSIV leakage rate for all four main steam lines when tested at greater than 25 psig was exceeded. Fermi 2 Main Steam Lines are equipped with a Main Steam Line Isolation Valve Leakage Control System (MSIVLCS) which is designed to maintain pressure between the MSIVs slightly above that of primary containment. Since the leakage could not be quantified, it could not be demonstrated that the leakage did not exceed the capacity of the MSIVLCS.
The NRC Resident Inspector was notified of this event by the licensee.
* * * UPDATE ON 04/07/00 AT 1836 EDT BY S. MAREK TAKEN BY MACKINNON * * *
During LLRT of the "D" Main Steam Line, the as-found leakage could not be quantified. Technical Specification surveillance requirement, SR 3.6.1.3.12 limit of less than 100 scfh combined MSIV leakage rate for all four main steam lines when tested at greater than 25 psig was exceeded. Fermi 2 Main Steam Lines are equipped with a MSIVLCS which is designed to maintain pressure between the MSIVs slightly above that of primary containment. Since the leakage could not be quantified, it could not be demonstrated that the leakage did not exceed the capacity of the MSIVLCS. The "A" & "B" Main Steam Lines passed their LLRT.
The NRC Resident Inspector was notified of this update by the licensee. R3DO (T. Kozak) was notified.
* * * UPDATE AT 0931 ON 4/12/2000 FROM S. MAREK TAKEN BY STEVE SANDIN * * *
"During Local Leak Rate Testing (LLRT) of Main Steam Line drain valve, B2103F019, the as found leakage was 232.7 SCFH, the allowable leakage is 1.00 SCFH.
"The leakage through this penetration X-8 of 232.7 SCFH exceeds Technical Specification surveillance requirement, SR 3.6.1.3.11 Bypass Leakage Total limit of less than 0.04 La, (11.9) SCFH. The total containment leakage is 274.62 SCFH. which is less than 1.0 La of 297.30 SCFH.
"This report is being made in accordance with 10CFR 50.72(b)(2)(i), any event or condition found while the reactor is shutdown that, had it been found while the reactor was in operation, would have resulted in the nuclear plant, including its principal safety barriers, being seriously degraded or being in an unanalyzed condition that significantly compromises plant safety."
The NRC resident inspector has been informed of this update by the licensee. Notified R3DO (Hiland).
Power Reactor
Event Number: 36874
Facility: HATCH
Region: 2 State: GA
Unit: [] [2] []
RX Type: [1] GE-4,[2] GE-4
NRC Notified By: BARRY COLEMAN
HQ OPS Officer: JOHN MacKINNON
Region: 2 State: GA
Unit: [] [2] []
RX Type: [1] GE-4,[2] GE-4
NRC Notified By: BARRY COLEMAN
HQ OPS Officer: JOHN MacKINNON
Notification Date: 04/07/2000
Notification Time: 17:56 [ET]
Event Date: 04/07/2000
Event Time: 16:15 [EDT]
Last Update Date: 04/07/2000
Notification Time: 17:56 [ET]
Event Date: 04/07/2000
Event Time: 16:15 [EDT]
Last Update Date: 04/07/2000
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(2)(ii) - ESF ACTUATION
10 CFR Section:
50.72(b)(2)(ii) - ESF ACTUATION
Person (Organization):
STEVE CAHILL (R2)
STEVE CAHILL (R2)
| Unit | SCRAM Code | RX Crit | Initial PWR | Initial RX Mode | Current PWR | Current RX Mode |
|---|---|---|---|---|---|---|
| 2 | N | N | 0 | Cold Shutdown | 0 | Cold Shutdown |
RECEIVED PARTIAL GROUP 1 (MSIVs) AND GROUP 2 (Primary Containment) OUTBOARD ISOLATIONS.
Received a partial Group 1 and Group 2 outboard isolation which caused 13 outboard isolation valves to close.
The following outboard isolation valves closed: 4 hydrogen and oxygen sample valves, 3 Fission Product Monitor sample valves, Drywell floor drain valve, Drywell equipment drain valve, Drywell Air Purge and Vent line valves, Primary Coolant Sample line valve, and a Main Steam Line drain valve. All the outboard valves belong to Group 1 except for the last two listed which belong to Group 2. Electricians were replacing covers on divisional separation wiring trays in the outboard isolation panel 2H11-P623. Insulation on a wire was damaged causing a fuse to blow. An evaluation is in progress to determined if the wire can be tapped or a new wire will be installed.
The NRC Resident Inspector was notified of this event by the licensee.
Received a partial Group 1 and Group 2 outboard isolation which caused 13 outboard isolation valves to close.
The following outboard isolation valves closed: 4 hydrogen and oxygen sample valves, 3 Fission Product Monitor sample valves, Drywell floor drain valve, Drywell equipment drain valve, Drywell Air Purge and Vent line valves, Primary Coolant Sample line valve, and a Main Steam Line drain valve. All the outboard valves belong to Group 1 except for the last two listed which belong to Group 2. Electricians were replacing covers on divisional separation wiring trays in the outboard isolation panel 2H11-P623. Insulation on a wire was damaged causing a fuse to blow. An evaluation is in progress to determined if the wire can be tapped or a new wire will be installed.
The NRC Resident Inspector was notified of this event by the licensee.
Power Reactor
Event Number: 36875
Facility: LIMERICK
Region: 1 State: PA
Unit: [1] [] []
RX Type: [1] GE-4,[2] GE-4
NRC Notified By: RAYMOND L. LANDIS
HQ OPS Officer: JOHN MacKINNON
Region: 1 State: PA
Unit: [1] [] []
RX Type: [1] GE-4,[2] GE-4
NRC Notified By: RAYMOND L. LANDIS
HQ OPS Officer: JOHN MacKINNON
Notification Date: 04/07/2000
Notification Time: 17:54 [ET]
Event Date: 04/07/2000
Event Time: 14:05 [EDT]
Last Update Date: 04/07/2000
Notification Time: 17:54 [ET]
Event Date: 04/07/2000
Event Time: 14:05 [EDT]
Last Update Date: 04/07/2000
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(2)(ii) - ESF ACTUATION
10 CFR Section:
50.72(b)(2)(ii) - ESF ACTUATION
Person (Organization):
JACK MCFADDEN (R1)
JACK MCFADDEN (R1)
| Unit | SCRAM Code | RX Crit | Initial PWR | Initial RX Mode | Current PWR | Current RX Mode |
|---|---|---|---|---|---|---|
| 1 | N | N | 0 | Refueling | 0 | Refueling |
BLOWN FUSE CAUSED A PARTIAL SYSTEM ISOLATION
A partial system isolation occurred on the containment instrument gas system and the drywell chilled water system. The cause of the partial isolation is a blown fuse.
At the time of this event, Unit 1 was in Operational Condition 5 undergoing refueling. There was no release of radiation or loss of vessel inventory or shutdown cooling. Proper system response is being verified. The fuse will be replaced and all valves will be placed back in their proper position.
The NRC Resident Inspector was notified of this event by the licensee.
A partial system isolation occurred on the containment instrument gas system and the drywell chilled water system. The cause of the partial isolation is a blown fuse.
At the time of this event, Unit 1 was in Operational Condition 5 undergoing refueling. There was no release of radiation or loss of vessel inventory or shutdown cooling. Proper system response is being verified. The fuse will be replaced and all valves will be placed back in their proper position.
The NRC Resident Inspector was notified of this event by the licensee.
Power Reactor
Event Number: 36876
Facility: SOUTH TEXAS
Region: 4 State: TX
Unit: [] [2] []
RX Type: [1] W-4-LP,[2] W-4-LP
NRC Notified By: JOHN MILLIFF
HQ OPS Officer: JOHN MacKINNON
Region: 4 State: TX
Unit: [] [2] []
RX Type: [1] W-4-LP,[2] W-4-LP
NRC Notified By: JOHN MILLIFF
HQ OPS Officer: JOHN MacKINNON
Notification Date: 04/07/2000
Notification Time: 18:07 [ET]
Event Date: 04/07/2000
Event Time: 10:14 [CDT]
Last Update Date: 04/07/2000
Notification Time: 18:07 [ET]
Event Date: 04/07/2000
Event Time: 10:14 [CDT]
Last Update Date: 04/07/2000
Emergency Class: NON EMERGENCY
10 CFR Section:
10 CFR Section:
Person (Organization):
JEFF SHACKELFORD (R4)
JEFF SHACKELFORD (R4)
| Unit | SCRAM Code | RX Crit | Initial PWR | Initial RX Mode | Current PWR | Current RX Mode |
|---|---|---|---|---|---|---|
| 2 | N | Y | 100 | Power Operation | 100 | Power Operation |
POWER EXCURSION TO 104% OF THERMAL RATED POWER
Power excursion to 104% occurred when a deaerator level channel was improperly removed from service for calibration and caused a loss of deaerator level and pressure control. This resulted in an increase in feedwater and steam flow to the deaerator, which in turn caused reactor power to increase above rated values. Operators took action to terminate the transient and stabilized Unit 2 at 99% power. The length of the excursion was approximately 3 minutes.
The NRC Resident Inspector was notified of this event by the licensee.
Power excursion to 104% occurred when a deaerator level channel was improperly removed from service for calibration and caused a loss of deaerator level and pressure control. This resulted in an increase in feedwater and steam flow to the deaerator, which in turn caused reactor power to increase above rated values. Operators took action to terminate the transient and stabilized Unit 2 at 99% power. The length of the excursion was approximately 3 minutes.
The NRC Resident Inspector was notified of this event by the licensee.
Power Reactor
Event Number: 36877
Facility: SAN ONOFRE
Region: 4 State: CA
Unit: [] [] [3]
RX Type: [1] W-3-LP,[2] CE,[3] CE
NRC Notified By: BILL CONKLIN
HQ OPS Officer: JOHN MacKINNON
Region: 4 State: CA
Unit: [] [] [3]
RX Type: [1] W-3-LP,[2] CE,[3] CE
NRC Notified By: BILL CONKLIN
HQ OPS Officer: JOHN MacKINNON
Notification Date: 04/07/2000
Notification Time: 19:11 [ET]
Event Date: 04/07/2000
Event Time: 15:33 [PDT]
Last Update Date: 04/07/2000
Notification Time: 19:11 [ET]
Event Date: 04/07/2000
Event Time: 15:33 [PDT]
Last Update Date: 04/07/2000
Emergency Class: NON EMERGENCY
10 CFR Section:
50.72(b)(1)(i)(A) - PLANT S/D REQD BY TS
10 CFR Section:
50.72(b)(1)(i)(A) - PLANT S/D REQD BY TS
Person (Organization):
JEFF SHACKELFORD (R4)
JEFF SHACKELFORD (R4)
| Unit | SCRAM Code | RX Crit | Initial PWR | Initial RX Mode | Current PWR | Current RX Mode |
|---|---|---|---|---|---|---|
| 3 | N | Y | 100 | Power Operation | 74 | Power Operation |
TECHNICAL SPECIFICATION SHUTDOWN DUE TO A DROPPED CONTROL ELEMENT ASSEMBLY (CEA).
On April 7, 2000, around 1319 PDT, an alarm was received for a control element drive mechanism control system timer. In response to this alarm, plant operators began moving control rod subgroup 20 to the "hold" bus (4 rods on the hold bus). Shortly thereafter, CEA #84 (a full length CEA and part of shutdown bank B) dropped into the reactor core. Technical Specification (TS) 3.1.5, "Control Element Assembly Alignment" requires all full length CEAs to be aligned to within 7 inches of all other CEAs in its group. If this requirement can not be met within 2 hours, Action B of TS 3.1.5 requires Southern California Edison to initiate a plant shutdown.
Plant operators initiated actions to realign CEA #84 with the remainder of its group. However, to minimize potential adverse affects to the fuel, reactor engineers have recommended a CEA withdrawal rate which will not allow CEA #84 to be realigned with the remainder of its group within 2 hours allowed by TS 3.1.5. Consequently, at 1533 PDT, Southern California Edison initiated a power reduction of San Onofre Unit 3.
At 1557 PDT, CEA #84 was realigned to within 7 inches of the remainder of its group before completion of plant shutdown.
Southern California Edison believes there is no safety significance to this event as all system operated as required. The cause of this event is under investigation.
The NRC Resident Inspector was notified of this event by the licensee.
On April 7, 2000, around 1319 PDT, an alarm was received for a control element drive mechanism control system timer. In response to this alarm, plant operators began moving control rod subgroup 20 to the "hold" bus (4 rods on the hold bus). Shortly thereafter, CEA #84 (a full length CEA and part of shutdown bank B) dropped into the reactor core. Technical Specification (TS) 3.1.5, "Control Element Assembly Alignment" requires all full length CEAs to be aligned to within 7 inches of all other CEAs in its group. If this requirement can not be met within 2 hours, Action B of TS 3.1.5 requires Southern California Edison to initiate a plant shutdown.
Plant operators initiated actions to realign CEA #84 with the remainder of its group. However, to minimize potential adverse affects to the fuel, reactor engineers have recommended a CEA withdrawal rate which will not allow CEA #84 to be realigned with the remainder of its group within 2 hours allowed by TS 3.1.5. Consequently, at 1533 PDT, Southern California Edison initiated a power reduction of San Onofre Unit 3.
At 1557 PDT, CEA #84 was realigned to within 7 inches of the remainder of its group before completion of plant shutdown.
Southern California Edison believes there is no safety significance to this event as all system operated as required. The cause of this event is under investigation.
The NRC Resident Inspector was notified of this event by the licensee.