05000498/LER-2015-001
| South Texas Unit 1 | |
| Event date: | 12-21-2015 |
|---|---|
| Report date: | 02-18-2016 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 4982015001R00 - NRC Website | |
Reported lessons learned are incorporated into the licensing process and fed back to industry.
Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
I. Description of reportable event
A. Reportable event classification
This event is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual actuation of the Reactor Protection System and also as an event or condition that resulted in an automatic actuation of the Auxiliary Feedwater (AFW) system.
B. Plant operating conditions prior to event
On December 21, 2015, Unit 1 was operating in Mode 1 at 48 percent power. Unit 1 was returning to power operation following refueling outage 1RE19.
C. Status of structures, systems, and components (SSCs) that were inoperable at the start of the event and that contributed to the event There were no SSCs that were inoperable at the start of the event that contributed to the event.
D. Narrative summary of the event
On December 21, 2015, STP Unit 1 power ascension following a refueling outage was in progress and the reactor was at approximately 48 percent rated thermal power. At approximately 1450 hours0.0168 days <br />0.403 hours <br />0.0024 weeks <br />5.51725e-4 months <br />, Operators observed Reactor Coolant System (RCS) temperature fluctuations due to turbine load swings caused by an oscillating Main Turbine Governor Valve (GV), GV2.
At 1453, Main Turbine demand rose approximately 5 percent and GV2 continued to cycle.
At 1455 hours0.0168 days <br />0.404 hours <br />0.00241 weeks <br />5.536275e-4 months <br />, the Group 1 Steam Dumps opened for approximately 23 seconds. At 1456, Operators commenced load reduction on the Main Turbine to attempt to lower turbine demand. Operators observed power lowering but there was no effect on the GV2 oscillations.
At 1508 and 1510, the Group 2 Steam Dumps modulated open and closed while the Group 1 Steam Dumps remained closed due to a failure of the valve positioners.
At 1519, Operators manually tripped the Main Turbine. With reactor power less than 50 percent, as expected, the reactor did not automatically trip when the turbine tripped. When the Main Turbine Trip signal was received, the steam dump valve positioners were bypassed as designed and the Group 1, 2, and 3 Steam Dumps momentarily opened. Following the turbine trip, the steam dumps returned to a modulation mode of operation.
At 1524, a Main Feedwater Isolation occurred and the loss of feedwater resulted in lowering steam generator (SG) levels. This was due to the failure of the Group 1 Steam Dumps to modulate in response to the Main Turbine load changes, which resulted in a significant difference between steam flow and feedwater flow. Operators attempted to manually reduce feedwater flow but were not able to prevent the Main Feedwater Isolation.
South Texas Unit 1 05000498 Reported lessons learned are incorporated into the licensing process and fed back to industry.
Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. It a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
At 1529, all four SG Power Operated Relief Valves (PORVs) opened in response to the rise in steam pressure.
At 1530, Operators attempted to manually control the steam dumps but the Group 1 Steam Dumps would not modulate open.
At 1533, Operators initiated a manual reactor trip due to the lowering SG levels which is reportable under 10 CFR 50.73(a)(2)(iv)(A) as a valid manual actuation of the Reactor Protection System.
At 1533, approximately six seconds following the reactor trip, an AFW actuation occurred due to a SG low level signal; all four AFW pumps actuated. This event is reportable under 10 CFR 50.73(a)(2)(iv)(A) as a valid automatic actuation of the AFW system.
E. Method of discovery
The manual reactor trip and AFW actuation were self-revealing. Operators initiated the manual reactor trip in response to the Main Feedwater Isolation and the resulting lowering SG levels. The AFW system actuated automatically on a SG low level signal.
II. Component failures
A. Failure mode, mechanism, and effects of failed component
The component failures applicable to this Licensee Event Report (LER) are related to the LVDT wiring in GV2 and the Group 1 Steam Dumps.
The cause of the GV2 oscillations was an intermittent ground on the signal wire to the LVDT for GV2.
The cause of the intermittent ground was a small score in the insulation of the LVDT signal wiring.
This intermittent condition was the cause of the GV2 oscillations that resulted in Operators manually tripping the Main Turbine.
The aggressive fluctuations in steam flow due to the GV2 oscillations caused the spring clips in the Group 1 Steam Dumps to become dislodged, causing the valves to be unresponsive to modulation demands. The function of the spring clips is to provide air balance in the positioner required to modulate the valve to a controlled position. With the spring clips dislodged, the steam dumps could not modulate open; the steam dumps did maintain the ability to fully open as occurred following the turbine trip.
Total steam dump load reduction capability is 40 percent of full power. Along with 10 percent load reduction capability provided by rod control, this allows a 50 percent load reduction to occur without a reactor trip. The Group 1 Steam Dumps make up one-fourth of the steam dumps for Unit 1, so the inability of the Group 1 Steam Dumps to modulate translates to a loss of approximately ten percent load reduction capability. This condition, combined with concerns regarding SG level, resulted in Operators manually tripping the reactor.
South Texas Unit 1 05000498 Reported lessons learned are incorporated into the licensing process and fed back to industry.
Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
B. Cause of component failure
The cause of the GV2 failure was an intermittent ground on the signal wire to the LVDT for GV2 that was the result of a small score in the insulation of the LVDT signal wiring. This wiring was vendor supplied and there is no documented history of this wiring ever being replaced or reworked. The insulation was most likely damaged during the initial installation.
The aggressive fluctuations in steam flow due to the GV2 oscillations caused the spring clips in the Group 1 Steam Dumps to become dislodged, causing the valves to be unresponsive to modulation demands. The steam dumps regularly cope with changes in steam flow during normal operation; however, the aggressive steam flow fluctuations that the Group 1 Steam Dumps experienced in this event challenged the design of the Steam Dump system, resulting in the malfunction of the spring clips on the positioners.
C. Systems or secondary functions that were affected by failure of components with multiple functions The failed components described in the narrative, Steam Dump Group 1 and GV2, do not have multiple functions that affect other systems. The failures of these components contributed to the eventual Main Turbine trip and reactor trip.
D. Failed component information (Energy Industry Identification System (EIIS) designators provided in {brackets}) High Pressure Turbine Governor Valve Position Transmitter {ZT} Manufacturer: Westinghouse Electric Corporation Model: 677J444G21 Steam Dumps Valve Positioner {V} Manufacturer: Bailey Controls Model: AV112000 South Texas Unit 1 05000498 Reported lessons learned are incorporated into the licensing process and fed back to industry.
Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to Infocollects.Resource@nrc.goy, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
III. Analysis of the event
A. Safety system responses that occurred
The Reactor Protection System and AFW systems both responded to this event.
B. Duration of safety system inoperability
There were no SSCs that were inoperable at the start of the event that contributed to the event.
C. Safety consequences and implications
No Technical Specification LCOs were entered due to this event. Operators manually tripped the reactor following the Main Feedwater isolation.
For the Probabilistic Risk Assessment (PRA) analysis, the initiating event is classified as a Total Loss of Main Feedwater (TLMFW) — the isolation of main feedwater led to decreasing levels in the SG which would have inevitably resulted in an automatic reactor trip. The TLMFW event is a modeled initiating event, and no risk significant equipment was confirmed out of service.
The STP PRA was used to estimate the relevant metrics for a reactor trip, Conditional Core Damage Probability (CCDP) and Conditional Large Early Release Probability (CLERP), given that the TLMFW initiating event actually occurred. The CCDP and CLERP were determined to be 5.99E-07 and 3.36E-08, respectively, indicating very low risk significance.
The resulting risk of this event is well within the NRC acceptance criteria of less than 1E-06 events per year for the CCDP and less than 1E-07 events per year for the CLERP, as outlined in Regulatory Guide 1.174.
The event was of very low risk significance and no radioactive release occurred; therefore, there was no adverse effect on the health and safety of the public.
IV. Cause of the event
Prior to and following the manual trip of the Main Turbine, the Group 1 Steam Dumps did not respond as expected for the load shed, resulting in a Main Feedwater Isolation due to rising SG level. Operators then initiated a manual reactor trip due to lowering SG levels and the AFW system actuated automatically on a SG low level signal. There were no human performance errors that contributed to the event.
South Texas Unit 1 05000498 Reported lessons learned are incorporated into the licensing process and fed back to industry.
Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by Internet e-mail to Infocollectsftesource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
V. Corrective actions
As a corrective action, STP replaced the LVDT and the associated cables for GV2. Inspections were also performed on all Unit 1 governor and throttle valves following the reactor trip to ensure that the condition was limited to GV2. Inspections will be performed on the cables and wiring associated with the LVDTs and servo valves for the governor and throttle valves in Unit 2 during the next Unit 2 refueling outage.
Visual Inspections were performed on all Unit 1 Steam Dump Groups following the reactor trip. Repairs to the Group 1 Steam Dumps were completed on December 23, 2015 and the spring clips were verified to be within tolerance.
VI. Previous similar events
An Operating Experience review was conducted as part of the Cause Evaluation performed for this event.
Several failures of the High Pressure Governor valves due to loose or faulty connections, however, none of these failures resulted from insulation damage or shield grounding.
Several failures related to the steam dump valves were reviewed and none of these failures resulted from the spring clips being dislodged following a secondary transient. A similar event (Condition Report 08-4313) consisting of valve oscillations of HP Turbine GV1 led to perturbations in the secondary that cycled Electro-Hydraulic lines greater than six inches. There was no report of steam dump failures at that time.
One previous STP Unit 1 LER (2000-007-00) has been submitted related to governor valves and the steam dumps with a subsequent manual reactor trip. The cause of this event was a failed logic card and missing screw on the steam dump actuator hand wheel.
South Texas Unit 1 05000498