05000306/LER-2011-002
| Prairie Island Nuclear Generating Plant Unit 2 | |
| Event date: | 05-09-2011 |
|---|---|
| Report date: | 06-30-2011 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 3062011002R00 - NRC Website | |
The Prairie Island Nuclear Generating Plant (PINGP) switchyard breakers1 use a selective isolation design. The relays2 are designed to isolate the breakers closest to a detected fault first with the intent of maximizing reliability while protecting the grid from a localized fault. Some PINGP substation relays utilize distance and directional-based sensing to determine the location of a fault. These relays enable selective tripping of the breakers closest to the fault.
Breakers 8H13 and 8H14 serve as Unit 2 Generator3 output isolations. Unit 1 Generator output isolations are 8H16 and 8H17. Breakers 8H15 and 8H14 isolate the Blue Lake transmission line4 from 345kV Buses 2 and 1 (respectively). Breakers 8H9 and 8H8 isolate the Byron transmission line from 345kV Buses 2 and 1 (respectively). In November 2010, NSPM implemented a modification to the breakers in the switchyard (under System Control Center (SCC) jurisdiction) to upgrade protective relaying on those breakers to a digital system. The modification was performed under Transmission System Operator (TSO) Work Order (WO) 11209851.
At approximately 07:22 CDT on May 9, 2011, thunderstorms in the vicinity of PINGP and other portions of Southeast Minnesota produced a lightning strike which contacted ground on the Byron transmission line. The strike occurred approximately 25 miles from the Byron station and 15 miles from PINGP. The strike created a grid disturbance and actuated PINGP protective relaying on breakers for the Unit 2 Generator, Blue Lake, and Byron Lines.
As a result, PINGP Unit 2 tripped from approximately 100% steady-state power as a result of a turbine trip from a generator lockout signal. At the time of the trip, Unit 1 was in a planned refueling outage in Mode 6. The Unit 2 steam plant and reactor protection systems responded properly to the turbine trip.
EVENT ANALYSIS
Based upon post event diagnostics, Xcel Energy System Relay Specialists determined that the relay ground potential circuit was missing a link (wire) between substation panels6 (from a latent wiring error) resulting in the loss of the reference ground potential to associated protective relaying in the Switchyard panels associated with the Unit 1 Generator, Unit 2 Generator, and the Blue Lake transmission line.
The loss of the reference ground potential was sufficient to "disorient" the distance and directional- sensing of the relays for the affected breakers; ultimately resulting in the relays detecting a "fault" on 1 EIIS Component Identifier: BKR 2 EIIS Component Identifier: RLY 3 EIIS System Code: EL 4 EMS System Code:
FK 5 EMS System Code: JC 6 EMS Component Identifier: PL the Blue Lake and/or Generator sides of the breaker when no fault existed. In essence, breakers 8H13, 8H14, and 8H15 tripped when a fault requiring relay actuation was not present, with the net effect of causing a generator, turbine, and reactor trip. This event is reportable under 10 CFR 50.73(a)(2)(iv)(A) since there was an automatic actuation of the Reactor Protection system (RPS) and the auxiliary feedwater system (AFW).
SAFETY SIGNIFICANCE
This event did not challenge nuclear safety as all plant systems responded as designed. Therefore, this event does not represent a safety system functional failure for Unit 2. However, the lightning strike and latent system installation flaws combined to create an initiating event which did challenge reliable operation. Additionally, the root cause investigation determined that the Unit 1 Generator output breakers would also have been affected if Unit 1 were online at the time (creating the potential for a dual-unit trip). Any unplanned reactor trip is a significant event.
The plant systems responded as designed so there were no radiological, environmental, or industrial impacts associated with this event. Therefore, this event did not affect the health and safety of the public.
CAUSE
The causal evaluation determined that the proximate cause of the relaying scheme failure was inadequate ground wire installation during the November 2010, modification to the substation equipment.
The root cause of the Unit 2 trip was that NSPM (Transmission and Nuclear) did not establish the appropriate standard for procedure quality with respect to work under SCC jurisdiction in the PINGP substation such that a means of effectively utilizing human performance tools to minimize errors during work which directly impacts the safe and reliable operation of nuclear plants was not in place.
A contributing cause was that the design of the protective relaying circuit includes a single point vulnerability whereby a single floating ground can result in misoperation of multiple breakers, thereby reducing transmission reliability.
Another contributing cause was that PINGP has, in the past, not rigorously implemented corrective actions from external assessments and recommendations, thereby resulting in vulnerabilities in oversight of substation work not being adequately addressed.
(NRC 10 LICENSEE EVENT REPORT (LER) -2010)M 366A FOR
CONTINUATION SHEET
U.S. NUCLEAR REGULATORY COMMISSION 05000 306 YEAR 2011 - 002
NO
- 00
CORRECTIVE ACTION
WO 430439 replaced the missing section of the reference ground circuit on May 9, 2011. Unit 2 was placed online on May 10, 2011.
In accordance with the Corrective Action Program (CAP), NSPM will implement a program to identify new installation and modification work under SCC jurisdiction that may impact nuclear plant reliability and implement procedural controls to enable human performance tool usage. This program will ensure that, prior to conduct of work, procedures of sufficient quality to enable human performance tool usage are in place.
In accordance with the CAP, NSPM will implement a modification to the ground circuit for protective relaying to remove the single point vulnerability.
In accordance with the CAP, NSPM will evaluate recommendations of industry documents against current procedures and practices. The evaluation will, at a minimum, address recommendations and describe how current practices and procedures support implementation or identify actions needed to address identified gaps.
PREVIOUS SIMILAR EVENTS
A LER search was conducted and no similar events at PINGP involving grid disturbances were identified in the last three years.