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During a reactor startup on November 13, 2017 at 0136, while at approximately 1.5°o power (MODE 2), an Excore Power Range Nuclear Instrument (N-42) was declared inoperable due to lower than expected detector amps and indicated power. N-42 was reading approximately 0.4°0 lower power than the other three Power Range instruments. The malfunction was determined to be the result of a failed High Voltage (HV) cable center pin connector to N-42. The HV cable connector was installed during N-42 rescahng on November 10, 2017 in preparation for startup physics testing. N-42 provides an input signal to Channel 2 of the Over Temperature Delta Temperature (OTDT) Reactor Trip Signal. Prior to the discovery of the N-42 failure, Channel 3 of OTDT had also been declared inoperable and associated bistables tripped due to a failed Pressurizer Pressure transmitter. Therefore, it was determined that two channels of OTDT were inoperable longer than allowed by Technical Specification (TS) 3.0.3. This condition is reportable per 10CFR50.73(a)(2X1)(B).

The HV cable connector was repaired and all channels were OPERABLE on November 14, 2017 at 1000. The installation of the HV cable connector with the faulty center pin was attributed to human error. Corrective actions include procedure changes, training, and departmental communications related to maintenance fundamentals.

On October 31, 2017, while in Mode 6 at 00 0 power level, it was discovered that a Unit 2 pressurizer safety valve (PSV). which had been removed during the October 2017 refueling outage (2R25) and shipped offsite for testing, failed its as-found lift pressure test. The PSV lifted below the Technical Specification (TS) 3.4.10 allowable lift setting value. Setpoint drift of the PSV is the most likely cause of the failure.

It is likely that the PSV was outside of the TS limits longer than allowed by the Required Action Statement (15 minutes) during the previous operating cycle in all applicable modes of operation. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

The PSV was replaced during the October 2017 refueling outage.

On June 23, 2017, during continued troubleshooting of a jacket water (JW) leak on the 2B Emergency Diesel Generator (EDG), it was determined that the backup service water (SW) makeup flow path to the JW expansion tank would not pass flow. This troubleshooting was conducted to validate operability assumptions made on April 21, 2017, after recurrence of a leak from the JW keep warm pump.

Based upon the measured leak rate from the April 21st event, the 2B EDG would have been unable to meet its 7 day mission time without the use of makeup water to the JW expansion tank. Had the 2B EDG received a demand signal after March 3rd, the EDG may not have been able to perform its safety function during a design basis accident due to the JW leak rate and inability to makeup to the JW expansion tank.

Since the 2B EDG may not have met its mission time from March 3, 2017 to April 21, 2017, the station unknowingly operated in a condition prohibited by Technical Specifications which is reportable under 50.73(a)(2)(i)(B).

On November 12, 2015 at approximately 02:00 CDT, Farley Unit 2 was operating in Mode 5 at zero percent power in a planned maintenance outage when evidence from troubleshooting became available which led to the discovery that all of the Reactor Coolant System (RCS) Leakage Detection Instrumentation had been inoperable on August 7, 2015 for a period longer than allowed by Technical Specifications (TS).

Troubleshooting discovered that the A, B, and D channels of the Containment Cooling Level Monitoring System (CCLMS) had been inoperable since July 6, 2015. On August 7, 2015 the C CCLMS was tagged out at the same time as both the R11 and R12 Containment Radiation Detectors were taken out of service for a period longer than allowed by TS 3.4.15 Condition E and Limiting Condition for Operation (LCO) 3.0.3. This is a condition prohibited by Technical Specifications and is reportable in accordance with 10 CFR 50.73 (a)(2)(i)(B).

The cause of this event was an incorrect conclusion regarding the operating conditions of the four Containment Cooler Level Indicators. Corrective actions included the repair of the containment coolers' sensing lines for full restoration of the CCLMS. Repairs were also made to the components associated with the steam leak in containment N`RC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (It sots 19.."'.‘ I ) / LICENSEE EVENT REPORT (LER) APPROVED BY ()MD: NO. 3150.0104 EXPIRES: 10/31/2018 Reported lessons learned are incorporated into the licensing process and led back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Inform lion Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission. Washington DC 20555-0001, or by infernal e-mail to Infocollects.ResourceOnrc.gov, and to the Dal( Officer, Olice of Inlormalion and Regulatory Affairs, NEOB-10202. (3150-0104). Oka 01 Management and Budget.

Washington, DC 20503.11 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 lo respond to, the information collection.

Joseph M. Farley Nuclear Plant, Unit 2 05000 - 364

NO

A. REQUIREMENT FOR REPORT

For a period of seven hours and 54 minutes on August 7, 2015 all required Reactor Coolant System Leakage Detection Instrumentation monitors required by Technical Specifications (TS) 3.4.15 were out of service and the required action per TS 3.4.15 Condition E and Limiting Condition for Operation (LCO) 3.0.3 to place the unit in Mode 3 within 7 hours was not met. This is a condition prohibited by TS and is reportable in accordance with 10 CFR 50.73 (a)(2)(i)(B).

B. UNIT STATUS AT TIME OF EVENT

Unit 2, Mode 1, 100 percent power

C. DESCRIPTION OF EVENT

On November 12, 2015 at approximately 02:00 CDT, Farley Unit 2 was operating in Mode 5 at zero percent power and was in a planned maintenance outage to investigate a leak ins'de of conta nment. A troubleshooting effort was initiated to investigate numerous maintenance issues that had been occurring with the A, B, and D Containment Cooler Level Indicators (EIIS Code LI). The troubleshooting work revealed that the A, B, and D Containment Cooler Level Indicators were inoperable and were considered to have been inoperable since July 6, 2015, when drainage into the containment sump had exceeded one gallon per minute. During this time frame the plant conducted extensive investigations into the source of the leakage, including multiple containment walkdowns and observations, maintenance troubleshooting activities, and detailed chemistry sample results of the containment sump, all of which led to the conclusion of a Service Water leak from the C Containment Cooler. The plant also prepared for a maintenance outage in the event that the leakage approached shutdown thresholds and implemented measures to protect the plant from the consequences of increased leakage.

During the November 2015 maintenance outage a steam leak was found in Containment and was verified as the cause of the Containment Cooling Level Monitoring System (CCLMS) alarms. The A, B, and D containment coolers' sensing lines were found to be clogged and therefore the level transmitters were unable to perform their function.

A subsequent review of operator logs showed that on August 7, 2015 the B and C Containment Cooler Level Indicators were declared inoperable to perform troubleshooting. On the same day, containment radiation monitors R11 and R12 were taken out of service for calibration surveillance. Since A and D CCLMS were discovered to have been inoperable, this created an unrealized entry into Tech Spec 3.4.15 Condition E (all detection inoperable) for a period of seven hours and 54 minutes, and the required action of immediate entry into Limiting Condition for Operation (LCO) 3.0.3 requiring the plant to be in MODE 3 in 7 hours was not met.

The CCLMS and the steam leak were repaired prior to exiting the maintenance outage.

Reported lessons learned are incorporated into the licensing process and led back to Industry Send comments regarcing 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.ResourceOnrc.gov, and to the Desk Officer, Office ot Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. II a means used to impose an irdormation 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 lo, the intonation collection.

Joseph M. Farley Nuclear Plant, Unit 2 05000 - 364

NO

D. CAUSE OF EVENT

The cause of the unrealized entry into Tech Spec 3.4.15 Condition E was an incorrect conclusion that the A, B, and D Containment Cooler Level Indicators, which had not been alarming, were operable, and that the C Containment Cooler Level Indicator was improperly alarming. This conclusion was reinforced by performance of multiple containment walkdowns and observations, maintenance troubleshooting activities, and detailed chemistry sample results of the containment sump that were strongly indicative of Service Water.

E. SAFETY ASSESSMENT

The leak in containment migrated to the containment sump which was monitored by radiation detectors.

The sump level was trended by a level monitoring indication. The site planned a maintenance outage to repair the leak. This condition had no significant effect on the health and safety of the public.

The loss of all CCLMS, along with a planned removal from service of R11 and R12 for calibration, represented an unplanned entry into Tech Spec 3.4.15 Condition E. The Condition requires an immediate entry into LCO 3.0.3 and entry into Mode 3 in 7 hours. The August 7, 2015 event lasted 7 hours and 54 minutes which exceeded the 7 hour time limit and therefore constitutes a condition that is reportable pursuant to 10CFR50.73 (a)(2)(i)(B), "Any operation or condition which was prohibited by the plant's Technical Specifications.

F. CORRECTIVE ACTION

During the November 2015 planned maintenance outage repairs were completed on the containment coolers' sensing lines for full restoration of the CCLMS. Repairs were also made to the components associated with the steam leak in containment.

G. ADDITIONAL INFORMATION

1) Failed Components: Level Indicator (LI) 2) Previous Similar Events: A search did not reveal any similar reported events for Plant Farley.

3) Energy Industry Identification System Code: Containment Leakage Control System (BD) 4) Other systems affected: There were no other systems, structures, or components that were affected by or contributed to the event.

5) Commitment Information: This report does not create any licensing commitments.

On 11/15/2014 at 0348 CST while withdrawing control rods for reactor startup and low power physics testing with control bank C at approximately 50 steps and the reactor subcritical, Digital Rod Position Indication (DRPI) for one of the control rods (M12) changed to 90 steps. The control room operators stopped withdrawing rods and entered the Abnormal Operating Procedure (AOP) for Malfunction of the Rod Control System. The reactor trip breakers were opened at 0353 CST and all rods inserted as expected. Causal analysis determined that the DRPI signal for rod M12 was invalid due to a failure of the detector/encoder card associated with the M12 rod.

This notification is being made as required by 10CFR 50.73(a)(2)(iv)(A) due to a manual actuation of the reactor protection system occurring when the control room operators opened the Unit 2 reactor trip breakers via the main control board hand switch during reactor startup procedures. This was a valid actuation of the reactor protection system.

For corrective actions, the suspect DRPI detector/encoder card was replaced. The card will be sent to a vendor for failure analysis to determine the component on the card that actually failed. As an enhancement action, the AOP for Malfunction of the Rod Control System will be revised to assess rod position indication malfunction.

APPROVED BY OMB: NO. 315B-0104 EXPIRES: 01/31/20I7 R.:parted lessons teamed aro incorporated into the icansIng process and led back to Industry.

Send comments regarang burden esumate to the EOM, Pnvacy and Information Collections Branch (T-5 F53) US. Nuclear Regulatory Comrassoon, Washington, DC 20555.0001, or by Inland email to Infocollects.RE .sourceOnrcgov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOS1 0202, (3150-0104), Office of Air germ! and Budget, Washington DC 20503.11 a moans used to Impose an Information celestial does not display a currently valid OMB curitml numba, the NRC m“y not conduct or spori_orr, end a person is not required to respond to, the Information collodion.

On May 29, 2013, with Unit 2 operating in Mode 1 at 100% power, Engineering personnel performing a review of Unit 2 beginning-of-cycle power ascension data identified that 2C Steam Generator Steam Flow Transmitter FT-494 did not meet Technical Specification calibration accuracy requirements. Based on this information the steam flow instrument was declared inoperable and the required actions of the appropriate Technical Specification were performed.

However, since the data utilized in the engineering review was obtained on May 14, 2013, it is known that FT-494 has been inoperable since May 14, 2013. Consequently, the time limits of the applicable Technical Specification required action were not met. This represents a condition prohibited by Technical Specifications and is reportable under 10CFR50.73(a)(2)(i)(B). Steam flow transmitter FT-494 was re-calibrated and returned to service on June 1, 2013. This out-of- tolerance condition of FT-494 also occurred at the beginning of the previous fuel cycle. This supplemental report contains causal analysis and corrective action information that was not available for the original report.

Joseph M. Farley Nuclear Plant, Unit 2 05000 364

On July 30, 2011 at 23:04 while at 100% power, the Unit 2 Turbine Driven Auxiliary Feedwater Pump (TDAFWP) automatically tripped on overspeed during surveillance testing. Through subsequent investigation it was determined that Unit 2 was not in compliance with Technical Specification (TS) 3.7.5 in that the Unit 2 TDAFWP had been rendered inoperable on July 7, 2011 at approximately 10:44 as a result of an inappropriately planned maintenance activity to correct an apparent wiring discrepancy that impacted turbine governor speed control. Electrical leads were incorrectly identified as spares and erroneously removed per plant drawings that contained unknown legacy errors. In addition, on several occasions during the time the Unit 2 TDAFWP was unknown to be inoperable; a second train of Auxiliary Feedwater (AFW) was made inoperable to support routine scheduled maintenance of Emergency Diesel Generators (EDG) and a Motor Driven Auxiliary Feedwater Pump (MDAFWP). This resulted in two of three trains of AFW being inoperable. This represents a condition that could have prevented the fulfillment of a safety function because two out of the three trains of AFW are required to meet flow requirements for limiting design basis accidents (DBA). The Unit 2 TDAFWP wiring was restored to the correct configuration and subsequent surveillance testing was completed satisfactory on August 1, 2011 at 03:40.

NRC FORM See (10-2010)

On May 22, 2010 at 16:34, with Unit 2 at 100% power, the reactor was manually tripped due to 2C Steam Generator (SG) Feedwater Regulating Valve (FRV) failing closed. At approximately 16:34, the control room crew received multiple alarms associated with 2C SG level and a process cabinet failure.

The crew noted no feedwater flow and decreasing level in 2C SG. Manual control of the 2C SG FRV was attempted but there was no power or control capability of the main feedwater regulating valve. At approximately 40% narrow range level in the 2C SG, the crew manually tripped Unit 2 prior to the automatic trip setpoint of 28% narrow range level. All safety systems functioned as designed without complications.

Investigation revealed that the controller driver (NCD) card in the 2C SG FRV controller circuitry failed causing the 2C SG FRV to close. The failed NCD card was replaced. Unit 2 was restarted and returned to Mode 1 on May 23, 2010 at 17:12.