05000306/LER-2010-001

LER-2010-001, Unit 2 Turbine Trip during Reactor Shutdown Resulting in a Reactor Scram

Docket Number
Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(iv)(A), System Actuation
3062010001R00 - NRC Website

At 19:04 on 4/16/2010, the Prairie Island Nuclear Generating Plant's (PINGP) Unit 2 reactor down power began in preparation for 2R26. At 22:37 with reactor power at approximately 13% power the turbines automatically tripped due to a greater than 2.5 inch Hg pressure differential between the A and B condensers` This caused an automatic trip of the turbine, and a subsequent automatic trip of the reactor. The steam plant and reactor protection system3 responded as expected to the initial event. After the reactor trip, operators responded in accordance with procedures, recovered vacuum, and continued with the Unit 2 shutdown.

EVENT ANALYSIS

The causal evaluation determined that at 19:04 on 4/16/2010, Unit 2 began a normal shutdown in preparation for 2R26. At approximately 13% power, the turbine automatically tripped due to a greater than 2.5 inch Hg pressure differential between the A and B condensers.

his was due to a partial opening of the Moisture Separator Reheater4 (MSR) safety valves caused by a lack of gland sealing steam to the MSR safety valves. Stagnant steam in the relatively cool piping on the 715 ft level of the Unit 2 turbine building condensed and collected at low points in the gland seal steam line to the MSR safety valves on the south side of the turbine. This condensation eventually blocked the flow of sealing steam.

As the MSR shell pressure became sub-atmospheric the lack of sealing steam to the MSR safety valves allowed the MSR safety valves to partially open and air to flow into Condenser A, rapidly decreasing its vacuum. Since the vacuum in Condenser B did not immediately drop, a differential pressure of greater than 2.5 in. Hg between the condensers developed. This caused an automatic trip of the turbine, and a subsequent automatic trip of the Unit 2 reactor.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) because of the automatic reactor scram while critical. The turbine condensers have no active safety function. Therefore, this event does not represent a safety system functional failure for Unit 2.

ENS System Code TA EMS System Code SG BIS System Code. JC EMS System Code. SB EMS System Code TC NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION 9 200 LICENSEE EVENT REPORT (LER)

CONTINUATION SHEET

1 FACILITY NAME 2. DOCKET NUMBER 6. LER NUMBER 3. PAGE

SAFETY SIGNIFICANCE

The operating crew responded to the reactor trip utilizing emergency operating procedures for reactor trip and reactor trip recovery and transitioned into normal shutdown procedures. Therefore, this event did not affect the health and safety of the public.

CAUSE

Root Cause

The causal evaluation determined that the root cause of the event was a build up of condensation that blocked the flow of sealing steam to the MSR safety valves. This allowed the MSR safety valves to partially open and caused condenser vacuum to decrease rapidly. This led to the chain of events that resulted in the Unit 2 reactor trip.

Contributing Causes 1. Inadequate procedural guidance associated with gland sealing steam and alarm responses were identified.

2. Degraded gland seal segments on Low Pressure Turbine (LP) 2 allowed more air into the condenser, creating more potential for a loss of vacuum, and could degrade air ejector performance.

3. Several of the actions identified for similar events in 2001 and 2003 were not completed or were not effective, allowing the same circumstances to be present to cause a repeat event.

CORRECTIVE ACTION

was adjusted to prevent water build up in that line. The slope of the other gland seal steam lines (including both sides of Unit 1), will be inspected for the appropriate slope.

Additional Corrective Actions:

1. Procedure Change Requests (PCRs) for Power, Shutdown and Alarm Response procedures have been initiated to address the procedural deficiencies.

2. The degraded LP1 and LP2 steam gland seal segments were replaced as part of the originally scheduled Unit 2 outage work. The Unit 1 turbine(s) gland seal segments were replaced in the prior Unit 1 outage.

3. Improvements to the Corrective Action Process were identified by a separate causal evaluation.