05000364/LER-2024-001, Manual Reactor Trip Due to Rising Steam Generator Levels

Manual Reactor Trip Due to Rising Steam Generator Levels

ML24011A217
Person / Time
Site:	Farley
Issue date:	01/11/2024
From:	Dean E Southern Nuclear Operating Co
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
NL-24-0001 LER 2024-001-00
Download: ML24011A217 (1)

LER-2024-001, Manual Reactor Trip Due to Rising Steam Generator Levels

Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(iv)(B), System Actuation
3642024001R00 - NRC Website

text

--t,, Southern Nuclear Edwin Dean Ill Joseph M. Farley Nuclear Plant Vice President - Farley 7388 North State Hwy 95 Columbia, Alabama 36319 334.661.2100 tel 334.661.2512 fax

EDDEANII@southcmco.com January 11, 2024

Docket No.: 50-364 NL-24-0001 -

U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001

Joseph M. Farley Nuclear Plant - Unit 2 Licensee Event Report 2024-001-00 Manual Reactor Trip due to Rising Steam Generator Levels

Ladies and Gentlemen:

In accordance with the requirements of 10 CFR 50.73(a)(2)(iv)(A), Southern Nuclear Company is submitting the enclosed Licensee Event Report for Unit 2.

This letter contains no NRC commitments. If you have any questions regarding this submittal, please contact Gene Surber, Licensing Manager, at (334) 661-2265.

Respectfully submitted, U&~

Edwin Dean Ill

Vice President-Farley

ED/rgs/cbg

Enclosure: Unit 2 Licensee Event Report 2024-001-00

Cc : Regional Administrator, Region II NRR Project Manager - Farley Nuclear Plant Senior Resident Inspector - Farley Nuclear Plant RTYPE: CFA04.054 Joseph M. Farley Nuclear Plant - Unit 2 Licensee Event Report 2024-001-00 Manual Reactor Trip due to Rising Steam Generator Levels

Enclosure

Unit 2 Licensee Event Report 2024-001-00

Abstract

On November 14, 2023, Farley Nuclear Plant (FNP) Unit 2 was performing an initial reactor startup following Refueling Outage 29 (2R29). With reactor power at approximately 10%, steam generator (SG) levels began to rise while in automatic control.

Operators took manual control of the main feedwater regulating and main feedwater regulating bypass valves but were unable to control the rise in SG levels. At 1041 CST the operators initiated a manual reactor trip prior to reaching high SG level setpoint. All equipment responded as expected. NRC was notified in accordance with 10 CFR 50.72(b)(2)(iv)(B) due to reactor scram and 10 CFR 50.72(b)(3)(iv)(A) for a specified system actuation via ENS 56852.

The cause of the event was determined to be Ovation steam and feedwater flow signal errors resulting in the automatic feedwater controls transferring to 'high power mode ' at a lower reactor power level than designed (10% versus 20%). This resulted in rising SG Levels and led the operators to manually trip the reactor. Following correction of Ovation signal errors post trip, operators were able to complete the reactor startup and reached full power on November 19, 2023.

INITIAL PLANT CONDITIONS

On November 14, 2023, while in Mode 1 and 10% reactor power, Farley Nuclear Plant (FNP) Unit 2 was returning to power following Refueling Outage 29 (2R29). During 2R29, the feedwater control system [EEIS:JB] was upgraded. The newly upgraded system is a digital-based Emerson Ovation System. This system operates in two modes: low-power and high-power. The transition between the two modes is automatic and based on the measured loop feedwater flow exceeding a predefined threshold. Both control modes operate the main feed regulating valves (MFRVs) and the MFRV bypass valves

[EEIS: SJ-FCV], as appropriate. No systems, structures, or components (SSCs) were inoperable that contributed to the event.

EVENT DESCRIPTION

At 1041 CST on November 14, 2023, FNP Unit 2 reactor was manually tripped due to rising Steam Generator (SG) [EEIS:

SB / SG] water levels. Prior to the reactor trip, control room personnel had raised power from approximately 3% to 7%

power and had entered Mode 1. Operators stabilized power at 7% to troubleshoot an issue related to the newly-installed modification. Operators had established a control limit of 20% power while troubleshooting continued and began a power ascension to 12%. Although SG level control was initially stable in automatic, operators observed that SG levels began to rapidly rise at 10% reactor power.

As SG levels increased, operators took manual control of the MFRVs and MFRV bypass valves to stabilize levels.

However, during the transient the SG levels rose above a predetermined manual reactor trip criteria based on SG level.

Operators tripped the reactor prior to reaching any automatic reactor trip setpoint. At the current power level and Reactor Coolant System temperature an automatic feedwater isolation occurred per design. During restoration after the trip, the operators restored feedwater capability by manually initiating Auxiliary Feedwater (AFW).

BASIS FOR REPORTABILITY AND SAFETY ASSESSMENT

There were no safety consequences as result of this event. The operating crew responded appropriately to the event.

This event was within the analysis of the UFSAR Chapter 15. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to the automatic actuation of the Reactor Protection System (RPS) and AFW system as listed in 10 CFR 50.73(a)(2)(iv)(B).

FNP Unit 1 was not affected during this event.

CAUSE

The cause of the event was determined to be the Ovation steam and feedwater flow signal errors resulted in automatic feedwater controls to transfer to 'high power mode' at low reactor power. This resulted in SG levels rising forcing the operators to initiate a manual reactor trip.

It was determined that during the design change, process errors were introduced which were not identified during testing.

Steam flow and feed flow inputs to the Ovation system were higher than actual control board indications. The Ovation system performs an automatic swap to high-power control at 20% feedwater flow_ With the higher Ovation feedwater flow signals, the swap to high-power flow control occured at approximately 10% reactor power. It was identified that there was a flow correction duplication in Ovation. This flow correction was already present in the Control System. A contributor to this event was inadequate communication surrounding the signal errors between plant departments and the Outage Control Center due to the lack of adequate team structure.

CORRECTIVE ACTIONS

• Corrected U2 inaccurate Ovation signals which resulted in the early transfer to Feed Regulating Valve operation.

• Develop a Modification Acceptance Test procedure for Ovation project to ensure field devices are checked through Ovation engineering values and/or logic.

• Conduct teaching and learning sessions with Engineering, Operations, Maintenance, and Site Projects first line leaders and above related to risk management and communications.

PREVIOUS SIMILAR EVENTS

• None