05000317/LER-2004-001, Regarding Reactor Trip During Scheduled Maintenance
| ML041450501 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 05/18/2004 |
| From: | Nietmann K Constellation Energy Group, Constellation Generation Group |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| LER 04-001-00 | |
| Download: ML041450501 (9) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 3172004001R00 - NRC Website | |
text
Kevin J. Nietmann Plant General Manager Calvert Cliffs Nuclear Power Plant Constellation Generation Group, LLC 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 410 495-4101 410 495-4787 Fax Constellation Energy Group May 18, 2004 U.S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION:
SUBJECT:
Document Control Desk Calvert Cliffs Nuclear Power Plant Unit No. 1; Docket No. 50-317; License No. DPR 53 Licensee Event Report 2004-001 Reactor Trip During Scheduled Maintenance The attached report is being sent to you as required under 10 CFR 50.73 guidelines. Should you have questions regarding this report, we will be pleased to discuss them with you.
Very truly yours, for Kevin J. Nietmann Plant General Manager KJN/ALS/bjd
Attachment:
As stated cc:
J. Petro, Esquire J. E. Silberg, Esquire Director, Project Directorate I-l, NRC G. S. Vissing, NRC H. J. Miller, NRC Resident Inspector, NRC R. I. McLean, DNR
Abstract
At 13:40 on March 20, 2004, Calvert Cliffs Unit 1 tripped from 100 percent power after Bus 1Y09 was grounded during scheduled maintenance. While replacing a chart recorder in a Control Room cabinet, a power lead feeding the recorder became pinched between the recorder and its case. The insulation on one of the power leads was cut, exposing the live power lead, and a short to case was experienced. This resulted in a loss of 11 Digital Feedwater Automatic Bus Transfer bus which in turn resulted in the deenergization of the 11 Main and 12 Backup Central Processing Units for the digital feedwater system. Mechanical binding of the 11 Feedwater Regulating Valve positioner selector solenoid valve resulted in a loss of signal to the 11 Feedwater Regulating Valve, which immediately began closing. The 11 Steam Generator water level lowered quickly, resulting in an automatic plant trip.
The root cause of the trip lies in Human Performance in the area of work practices and design control. Corrective actions include procedure changes to improve risk management of maintenance, on-line testing of components, and monitoring plans for trip sensitive components. Unit 1 was restarted and paralleled to the grid on March 22, 2004 at 01:03.
NRC FORM 366 (7-2001)
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Room to open the recorder feeder breaker at 1 Y09. At about this time the reactor tripped automatically. The breaker was then opened, removing the ground from 1Y09.
Root causes were identified as follows:
- 1.
Maintenance activities that affected the ungrounded 3-phase 120 VAC system, with known deficient conditions in the plant were not adequately managed.
- 2.
Maintenance work practices, including pre-job briefs, and supervisory oversight, did not meet management expectations for work inside of trip sensitive areas.
- 3.
The FRV positioner selector solenoid valve (1 -SV-1 111 B) failed to re-position to the de-energized state when AC power was removed from the coil.
Contributing Causes were identified as follows:
- 1.
During the procurement process for the FRV dual-positioner modification, not all critical design characteristics were provided to the vendor.
- 2.
The communications between Plant Engineering, Operations, and Work Management regarding compensatory measures to manage work that could affect 1Y09 or IY10 were verbal and ineffective.
- 3.
The current Maintenance Planning process does not preclude working Rover or Reference Maintenance Orders that have an engineering issue, parts issue etc. (uassist") open.
Ill.
ANALYSIS OF EVENT
The 11 FRV shut leading to an automatic reactor trip due to low steam generator level. All other parameters were normal for the trip and all alarms that were received during the transient were expected. There were no actual nuclear safety consequences incurred from this event.
Combined Core Damage Probability was calculated as 5.6E-6.
This event resulted in an automatic actuation of the Reactor Protective System and is, therefore, reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A). Immediate notification of this event (Event Number 40601) was made on March 20, 2004 in accordance with 10 CFR 50.72(b)(2)(iv)(B).
IV.
CORRECTIVE ACTIONS
A.
The varistors connected to ground have been removed from the Dixson indicators so they are no longer a potential problem for this system. There are no other varistors installed in the same configuration as that of the Dixson indicators.
(If more space is required, use additional copies of (if more space is required, use additional copies of (If more space is required, use additional copies of NRC Form 366A)
- 2.
Licensee Event Report 318/2003-03 On May 28, 2003, Calvert Cliffs Unit 2 experienced an automatic reactor trip from 100 percent power. The automatic reactor trip was initiated by the Reactor Protective System due to the high pressurizer pressure condition that resulted from the rapid loss of load. The rapid loss of load occurred when the main turbine governor valves shut unexpectedly during planned troubleshooting on the main turbine controls in a Turbine Auxiliaries Electro-Hydraulic Control Cabinet. A short-circuit created during the troubleshooting induced a loss-of-voltage to the valve position limiter causing the governor valves to shut unexpectedly. The short-circuit was caused by incorrect use of test equipment during planned troubleshooting; therefore, the root cause of the trip lies in Human Performance in the area of Work Practices. Also, contributing causes in the area of verbal communications and procedure clarity were identified.
Corrective actions included awareness training on the event, its causes and recommendations, procedure changes, and also initial and continuing training on appropriate work practices when using test equipment.
Corrective actions from the May 28, 2003 event included reinforcing Management's expectations for supervisory oversight during troubleshooting activities. However, the corrective actions did not address other maintenance activities. Broadening the corrective actions from the May 28, 2003 event to address scheduled maintenance activities may have prevented the subject event of March 20, 2004.