05000483/LER-2015-003, Reactor Trip Caused by Transmission Line Fault
| Callaway Plant Unit 1 | |
| Event date: | 08-11-2015 |
|---|---|
| Report date: | 10-1-2015 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 4832015003R00 - NRC Website | |
1. DESCRIPTION OF STRUCTURE(S), SYSTEM(S) AND COMPONENT(S):
The main step-up transformers [EIIS system EL] take the generator output (25,000 VAC) and transform it to switchyard voltage (345,000 VAC). The main step-up transformers are located outside of the turbine building, across from the switchyard. The power from the main step-up transformers is transmitted to the offsite transmission network (grid) via the switchyard.
The main step-up transformers consist of three single-phase transformers. Each transformer is oil-filled and rated at 533.3 MVA. The low-voltage winding is connected in a delta configuration. The high-voltage winding is connected in a wye configuration with a solidly grounded neutral.
The main transformers were replaced during Refuel 19 (Spring 2013) by modification MP 09-0044.
2. INITIAL PLANT CONDITIONS:
Prior to the event, the plant was in Mode 1, at 100% power. There were no activities going on at that time that could have caused this event. There was no equipment out of service that would have had an impact on this event.
3. EVENT DESCRIPTION:
On August 11, 2015, at 01:39 an unexpected turbine trip occurred, followed immediately by a reactor trip.
The first-out alarm was 113F, "Unit Trip Turb Trip." Following the trip, enabling of the P-4 interlock coincident with a low T-Avg (564 F) condition caused a Feedwater Isolation Signal to be generated.
Subsequently, Motor Driven Auxiliary Feed Pump (MDAFP) actuation, Turbine Driven Auxiliary Feed Pump (TDAFP) actuation, and Steam Generator (SG) Blowdown Isolation signals were initiated.
Prior to the event, the Callaway plant was stable in Mode 1 at 100% power (3562 MWth, 1248 MWe).
On August 11, 2015, at 01:39 switchyard relays operated during a momentary fault on the MTGY-CAL 8 transmission line approximately 2 miles from the Callaway Plant. The transmission line breakers opened and reclosed automatically as designed. However, the operation of relays in the Callaway switchyard tripped the switchyard generator breakers open, which resulted in a turbine trip followed by a reactor trip.
Immediately after the trip, the transmission dispatcher called and reported that there was a phase-3 fault on the MTGY-CAL 8 line approximately 2 miles outside of Callaway, and that the transmission line breakers had reclosed.
The Callaway operating crew implemented the trip response procedures (E-0, "Reactor Trip or Safety Injection," and ES-0.1, "Reactor Trip Response,") to verify the plant's response to the reactor trip signal from 100% power.
The plant was stabilized in Mode 3 at 02:11.
The reactor trip was uncomplicated, as systems responded as expected. This included satisfactory operation of the Turbine Driven Auxiliary Feedwater Pump (TDAFP), which provided flow to all four steam generators.
For the "B" Motor Driven Auxiliary Feedwater Pump (MDAFP), discharge flow control valve ALHV0007 (MDAFP B to S/G A HV) initially responded as required (i.e., closed on demand). However, in response to a subsequent demand to open the valve, the valve remained closed and could not be manipulated from the control room using ALHK0007A, SG A MD AFP AFW CTRL. ALHV0007 was declared inoperable, and Condition C of Technical Specification (TS) 3.7.5, "Auxiliary Feedwater (AFW) System", was entered for the inoperable 'B' MDAFP train. An Operating Technician (OT) was dispatched to the valve, and the valve was manipulated locally by turning its handwheel. The valve was repaired prior to the end of the TS 72-hour Completion Time for Required Action C.1. Inoperability of this valve did not prevent the delivery of adequate auxiliary feedwater flow to the steam generators.
Event investigation revealed that jumpers were inadvertently included in the main transformer CT circuits, causing switchyard generator position differential relays to incorrectly operate, which in turn caused lockout relays to trip output breakers in the switchyard, thus causing the turbine and reactor trips. A field change notice (FCN) was generated to remove the incorrect jumpers from the main transformer CT circuits prior to plant startup.
The problem encountered with ALHV0007 was reflective of a condition determined to exist for both the ALHV0007 valve and the ALHV0005 valve (MDAFP B to S/G D HV). No problem with valve movement for ALHV0005 occurred at the time the ALHV0007 problem was revealed; however, this condition has been separately evaluated for reportability and will be addressed in Licensee Event Report (LER) 2015-04-00.
4. ASSESSMENT OF SAFETY CONSEQUENCES:
Except as noted for the ALHV0007 valve, safety systems responded as required during this event. The reactor protection system functioned as necessary to shut the reactor down and maintain it in a safe condition.
All safety functions, including reactor core decay heat removal, were satisfied.
This event was evaluated with the Callaway PRA model. The evaluation determined the incremental conditional core damage probability (ICCDP) of this event was less than 1E-6; therefore, this event was of very low risk significance.
5. REPORTING REQUIREMENTS:
This LER is submitted pursuant to 10 CFR 50.73(a)(2)(iv)(A) to report a reactor protection system actuation while critical and an auxiliary feedwater system actuation.
Specifically, 10 CFR 50.73(a)(2)(iv) states in part, "The licensee shall report:
(A) Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section ...
(B) The systems to which the requirements of paragraph (a)(2)(iv)(A) of this section apply are:
(1) Reactor protection system (RPS) including: reactor scram or reactor trip ....
(6) PWR auxiliary or emergency feed water system.
The RPS was actuated on August 11, 2015, at 01:39, during normal power operations (from 100% power).
This fulfills the reporting requirement of 10 CFR 50.73(a)(2)(iv)(A) by actuation of the system specified in 10 CFR 50.73(a)(2)(iv)(B)(1).
A valid auxiliary feedwater system actuation was received as a direct consequence of the turbine and reactor trip. This also fulfills the reporting requirement of 10 CFR 50.73(a)(2)(iv)(A) by actuation of the system specified in 10 CFR 50.73(a)(2)(iv)(B)(6).
6. CAUSE OF THE EVENT:
This event was caused by inadvertently installed main transformer CT jumpers that were installed as part of Main Transformer Replacement Modification 09-0044 implemented in Refuel 19 (Spring 2013). Following the event, the CT jumpers were removed consistent with the intended configuration, and the plant was successfully restarted after making the corrections.
The preliminary root cause of the incorrect main transformer CT wiring was failure to update or revise drawing E-23MA02, "Generation System - Three Line Metering & Relaying Diagram," which was missing information on connections to switchyard protective relays and included optional jumpers that were not supposed to be installed. The jumpers had not actually been installed for the original transformers, which was the correct and intended configuration. However, the noted drawing had not been revised to reflect that configuration.
Consequently, the jumpers were inadvertently installed in the CT circuits of the new transformers as part of the replacement modification. The post-modification testing performed by System Relay Services did not detect the improper jumpers.
It should be noted that the root cause investigation for this event is ongoing. The results of the investigation, including a final root cause determination, will be provided in a supplement to this LER.
7. CORRECTIVE ACTIONS:
The corrective actions to prevent recurrence are to incorporate a design and a testing review by System Protection personnel to ensure the design is correct and testing is adequate for future relay designs.
Construction Supervisors will be required to review jobs related to at-risk modification FCNs to ensure changes are made if they are impacted. Finally, from an extent-of-condition review, design drawings that have similar error traps such as incorrect and missing information will be identified and corrected.
8. PREVIOUS SIMILAR EVENTS:
No previous plant trips have occurred at Callaway due to incorrect response to a transmission line fault by transformer bus differential relaying. However, in 2010, a jumper shown on a design drawing was found to not be installed, and in 2012, a jumper was found left in a circuit that was not shown on drawings. These previous events are included as internal Operating Experience in the Root Cause Analysis for the current event.
Corrective actions for these events included additional programmatic guidance, training, and coaching of responsible personnel.