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 Report dateSiteEvent description
05000389/LER-2017-00318 December 2017Saint Lucie

On October 25, 2017, St. Lucie Unit 2 was in Mode 1 operation at 100 percent reactor power when the station discovered that both of the required flow transmitters (indication only) for the 2C steam driven auxiliary feedwater (AFW) pumps had been isolated since October 17, 2017. The transmitters were returned to service and extent of condition walkdowns were completed on the AFW pump flow transmitters for both St. Lucie Units 1 and 2; no other anomalies were noted.

This event was caused by human error because the personnel involved in the AFW flow calibration activities on October 17, 2017 did not adequately perform the system restorative steps in accordance with the governing procedure.

Based on the availability of diverse methods to verify AFW flow delivery to the steam generators, this condition had no effect on the health and safety of the public.

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 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.

Description On October 25, 2017, St. Lucie Unit 2 was in Mode 1 operation at 100 percent reactor power. Maintenance personnel were troubleshooting indication flow ‘spikes' from FT-09-2C1 (EIIS:BA:FT), the flow transmitter for the 2C steam driven auxiliary feedwater (AFW) pump (EIIS:BA:P) discharge. At 1910 hours, the operators declared the 2C AFW flow transmitter FT-09-2C1 inoperable as maintenance reported that the transmitter was isolated. FT-09-2C1 was promptly un-isolated, filled and vented, and restored to service at approximately 1915 hours. During the extent of condition walkdown, maintenance supervision discovered that flow transmitter FT-09-2C2 was also isolated; it was promptly unisolated, filled and vented, and restored to service at approximately 1925 hours.

By 2128 hours on October 25, 2017, the extent of condition walkdowns were completed for the remaining electric driven AFW pumps for Unit 2 and all AFW pumps for Unit 1; no anomalies were noted.

Cause of the Event

Investigation revealed that the individuals that performed an earlier calibration on October 17, 2017 did not properly perform the restoration lineup in accordance with the governing procedure.

Analysis of the Event

This event was reportable under 10 CR 50.73(a)(2)(i)(B) as any operation or condition that was prohibited by the Technical Specifications (TSs).

The AFW system consists of two electric driven pumps and one steam driven pump. Each electric AFW pump is normally aligned to its respective steam generator (SG) (EIIS:SB:SG), and the steam driven AFW pump can feed either SG.

The 2C steam driven AFW pump is provided with two redundant flow transmitters that are used to provide post- accident AFW flow indication. With both 2C AFW pump flow transmitters isolated, the minimum operable channel requirement of TS Table 3.3-10 was not met. Therefore Unit 2 was in the TS 48-hour completion and 6-hour shutdown action statement per TS 3.3.3.6 (Accident Monitoring Instrumentation) action (b). The 2C AFW pump flow transmitters were isolated on October 17, 2017, when maintenance personnel commenced loop calibrations of the Unit 2 AFW flow loops. When the condition was discovered on October 25, 2017, the 54-hour total completion and shutdown time had already been exceeded.

Safety Significance

The subject flow transmitters perform no automatic accident mitigation or control functions; they are used to monitor plant parameters during and following a design basis accident. From October 17 to October 25, 2017, the operators would not have the ability to directly monitor flow from the 2C AFW pump. However, the operators have sufficient diverse means to verify that AFW flow is getting to the SGs, such as SG level and condensate storage tank level trends as well as monitoring the effectiveness of decay heat removal via RCS temperature indication. Loss of the primary method to directly monitor the 2C AFW pump flow would not prevent successful mitigation of any design bases accident. Therefore, this condition had no effect on the health and safety of the public.

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 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.

Corrective Actions

1. The flow transmitters were immediately returned to service.

2. An extent of condition walkdown identified no other isolated transmitters in the AFW system.

3. The maintenance personnel involved with the earlier calibration that resulted in isolation of the 2C AFW flow transmitters were disqualified pending remediation.

Failed Components

ID: Flow Transmitter for Auxiliary Feedwater Pump 2C Discharge Tag Nos.: FT-09-2C1, FT-09-2C2 Manufacturer: Rosemount Model: 1153DB5

Additional Information

None.

05000389/LER-2017-00418 December 2017Saint Lucie

On October 26, 2017, at 0212 hours with St. Lucie Unit 2 in Mode 1 at 100% power, the reactor automatically tripped due to a loss of load following a failure within the turbine control system. The reactor trip was uncomplicated and all control rod assemblies fully inserted. Following the trip, one of the low power feedwater valves LCV-9005, did not properly maintain steam generator level which resulted in an actuation of the A-train auxiliary feedwater system. During the auxiliary feedwater actuation, one main feedwater isolation valve did not reposition closed as expected, but this did not impact heat removal. The main feedwater system remained available.

The failure within the turbine control system was caused by design deficiencies. Planned corrective actions include modifications to improve protective circuits, the addition of coolers and use of conformal coatings on printed circuit boards in the modules.

The problem with LCV-9005 was due to a latent design error that resulted in the setting of an incorrect stroke length for the control valve. This was corrected by adjusting the stroke length of the valve.

This report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) for system actuations of the reactor protection system and the auxiliary feedwater system.

During this event offsite power remained operable and energized. All other equipment responded to the event as expected per the existing plant conditions; therefore, this event had no impact on the health and safety of the public.

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 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.

Description On October 26, 2017, at 0212 hours with St. Lucie Unit 2 in Mode 1 at 100% power, the reactor automatically tripped due to a loss of load following a failure within the non-safety related turbine control system (TCS) (EIIS:TG:DCC). Based on initial investigation, it was determined that a TCS malfunction affected multiple testable dump manifold (TDM) solenoids (EIIS:TG:PSV). Ultimately, electro-hydraulic (EH) (EIIS:TG) system pressure was lost (i.e., turbine tripped) after two TDM 1 solenoids spuriously operated concurrently. All high pressure turbine governor and throttle valves (EIIS:TA:XCV) and all low pressure turbine intercept and reheat stop valves (EIIS:TA:SHV) repositioned closed as expected upon loss of EH pressure. The reactor trip was uncomplicated and all control rod assemblies fully inserted.

Following the reactor trip, the 15% bypass feedwater regulating valve, LCV-9005 (EIIS:JB:LCV), did not provide the expected feedwater flow to the 2A Steam Generator (EIIS:JB:SG). This resulted in lowering steam generator level and an actuation of the A train auxiliary feedwater actuation system (AFAS) (EIIS:JC). During the auxiliary feedwater actuation, one main feedwater isolation valve (MFIV) (EIIS:JB:ISV), HCV-09-1A, did not reposition closed as expected, but this did not impact heat removal as the redundant MFIV in series isolated main feedwater. The main feedwater system remained available.

Cause of the Event

The failure within the turbine control system was caused by design deficiencies. The TCS incorporates various features for fault tolerance, including the use of three separate trip circuits for each TDM, the 2 out of 3 hydraulic logic of the TDM design, and redundant datalinks provided for Remote I/O communications. The design is intended to ensure a single failure or malfunction will not result in turbine trip. Replaced modules were retained for analysis. Two sets were sent to the original equipment manufacturer. The third set was sent to an independent lab for forensic analysis. Based on the results of the forensic analyses, this report may be supplemented with additional causal factors as appropriate.

The problem with LCV-9005 was due to a latent design error that resulted in the setting of an incorrect stroke length for the control valve. The stroke length of LCV-9005 has been properly adjusted.

The problem with HCV-09-1A was caused by a failed solenoid, and the solenoid was replaced.

Analysis of the Event

This licensee event report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as “Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B).” This event included automatic actuations of the reactor protection system and the auxiliary feedwater system.

Testable Dump Manifolds The TCS has automatic control and trip devices necessary for operation and protection of the turbine-generator.

An automatic trip is provided to prevent any damage to the turbine-generator. The unit trips upon occurrence of conditions which are potentially hazardous to the turbine-generator or to other associated plant equipment. The TCS uses two headers to provide emergency turbine trip and overspeed protection. The emergency trip header has two testable dump manifolds (TDM 1 and TDM 2) and the overspeed protection header has one testable dump manifold (TDM 3). Each triple redundant electronic emergency trip system uses a TDM to interface with the control oil system. The 2-out-of-3 solenoid logic used to provide a protective trip also provides a means to test the system while on-line.

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 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.

Reviews of EH pressure data at each TDM showed that TDM 1 solenoid B was momentarily spuriously opening during the night prior to the event, and also that TDM 1 solenoid A and TDM 2 solenoid C had momentarily opened over the same time period. Approximately 30 minutes prior to the trip, TDM1 solenoid B opened and stayed open, putting TDM 1 into a continuous half trip state. The trip occurred after a second solenoid on TDM 1 spuriously opened.

Auxiliary Feedwater Actuation LCV-9005 and LCV-9006 are a pair of non-safety related 15% bypass feedwater regulating valves supplying main feedwater flow to the 2A and 2B SGs respectively with a predetermined set point and flow rate post trip. In 1997, LCV-9005 was replaced with what was intended to be a like for like valve replacement. However, the replacement LCV-9005 had different flow characteristics and a different stroke length that was not properly documented; therefore, not properly setup.

Prior to its replacement in 1997, LCV-9005 had a stroke length of 1.5 inches. The replacement valve had a stroke length of 2 inches. Stroke length is used to set up the control of the valve flow rate characteristics.

Therefore, the new model valve was only opening a percentage of a 1.5 inch stroke length instead of 2 inches.

This resulted in less flow than needed to automatically maintain flow to the steam generator without manual operation. A change in the plant conditions following implementation of a low power feedwater digital controller in 2013 compounded the effect of shortened valve stroke length that became apparent during this plant trip.

The opposite train valve LCV-9006 was determined to be operating with the proper stroke length, and main feedwater was used to feed the 2B Steam Generator post trip.

Safety Significance

The digital signals sent by the TCS to the TDMs during this event were reviewed and determined to be invalid and spurious. The turbine was not damaged or exposed to hazardous conditions during this event.

The auxiliary feedwater system is provided with complete sensor and control instrumentation to enable the system to automatically respond to a loss of steam generator inventory. Due to the incorrect setting of LCV- 9005 and the lowering water level in the 2A steam generator, the AFAS-1 actuation was valid. Once the mismatched 15% bypass feedwater regulating valve was isolated by AFAS-1, water level in the 2A steam generator was restored using auxiliary feedwater. 2B steam generator level was maintained post trip via LCV- 9006 and main feedwater.

During the auxiliary feedwater actuation, one of two MFIVs did not reposition closed as expected. There are two MFIVs in series on each feedwater train (A and B). The 2A train of main feedwater was automatically isolated by at least one MFIV. The Unit 2 UFSAR Table 7.3-12 describes failure modes and effects for the auxiliary feedwater actuation system. This analysis bounds the observation of the event described in this LER.

During this event offsite power remained operable and energized. Loss of turbine load events are bounded in the UFSAR as anticipated operational conditions. All other equipment responded to the event as expected per the existing plant conditions; therefore, this event had no impact on the health and safety of the public.

Corrective Actions

The corrective actions listed below are either completed or are being managed under the Corrective Action Program:

1. The three digital output modules controlling solenoids for TDM 1 were replaced, each consisting of an Electronics Module (EMOD), Personality Module (PMOD) and base assembly.

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 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.

2. The digital output module EMOD and PMOD for TDM 2 solenoid C was also replaced, as there was evidence that this solenoid had spuriously opened prior to the event.

3. The removed digital output modules were retained for analysis. Two sets (EMOD/PMOD/Base) from TDM 1 were sent to Emerson. The third set from TDM 1 was sent to an independent lab for forensic analysis.

4. Additional countermeasures measures were taken to further protect the TCS remote I/O cabinets from the environment. This included improving the remote TCS cabinets' environmental protection.

5. Actions are planned to install coolers for TCS cabinets.

6. Actions are planned to replace circuit card components in Remote I/O Cabinets.

7. Actions are planned to implement redundancy and diagnostics modifications to the TCS.

8. The stroke length of LCV-9005 was properly adjusted for a 2-inch stroke.

9. The failed solenoid on HCV-09-1A was replaced.

Failed Components Identified Turbine Control System Digital Output Module - Electronics Module (EMOD) Description: Digital Output 5-60VDC EMOD Manufacturer: Emerson Emerson Style Number: 1C31122G01 EMOD Serial Number: 3611019514 Emerson EMOD Module Revision 10 Turbine Control System Digital Output Module - Personality Module (PMOD) Description: Digital Output PMOD Manufacturer Emerson Emerson Style Number: 1C31125G02 PMOD Serial Number: T104316024 Emerson PMOD Module Revision 06 15% Bypass Feedwater Regulating Valve Manufacturer: Fisher Controls Co Inc. (Emerson) Valve Serial Number: 4” - 52A7148 Main Feedwater Isolation Valve Solenoid Description: valve:solenoid,3-way, 1/8" FNPT conn, carbon steel, 120 VDC,90 psi, normally closed Manufacturer: Parker Hannifin Part Number V5H71970 Cat ID322057-1

Additional Information

None

05000335/LER-2017-00313 November 2017Saint Lucie

During a reactor startup performed on September 12, 2017, the operators noted that the inoperable ‘B' channel reactor protection system (RPS) high startup rate (HSUR) trip did not occur as expected when reactor power exceeded the HSUR bypass removal setpoint. The ‘B' RPS HSUR channel was then manually tripped via the bistable removal method and plant startup continued.

Investigation revealed that the setpoint reduction method process used to implement the RPS HSUR channel trip did not account for subsequent nuclear instrumentation (NI) detector failures. Therefore the ‘B' RPS HSUR channel was not in the required tripped condition since the February 2017 failure of its wide range NI detector.

The setpoint reduction method was subsequently revised to ensure inoperable RPS HSUR channels tripped by the setpoint reduction method generate a trip with reactor power less than 15 percent reactor power. A procedure revision is in progress to implement these new rule-based instructions.

This event had no significant impact on the health and safety of the public based on system channel redundancy and procedural controls.

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 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.

Description On September 12, 2017, St. Lucie Unit 1 was in a reactor startup in Mode 2 operation. The ‘B' channel reactor protection system (RPS) high startup rate (HSUR) (EIIS:JC) channel was thought to be in the reduced setpoint tripped condition in response to earlier unpredictable operation of the ‘B' channel nuclear instrumentation (NI) detector (EIIS:IG:DET). At 1522 hours during the startup, the operators noted that the ‘B' channel RPS HSUR bistable (EIIS:JC) did not automatically trip as expected for the existing plant conditions. The operators placed the ‘B' channel of RPS HSUR in a tripped condition in accordance with procedures by removing the bistable from the trip unit assembly and entered Technical Specification (TS) 3.3.1.1, Table 3.3-1, Functional Unit 11, Action 2 with the ‘B' channel HSUR bistable in trip. The reactor startup continued with the channel in trip as allowed by the Technical Specifications (TSs).

Cause of the Event

This event was caused by inadequate processes used to implement the HSUR reduced setpoint trip method. The instruction used did not evaluate all potential failure conditions when setting the HSUR bistable. Investigation showed that the bistable did not trip because the setpoint reduction method (initially) internally tripped the bistable in the presence of an active NI signal. When the ‘B' wide range NI detector subsequently failed low in February 2017, the input signal to the Hi Rate bistable from the rate circuit changed and the bistable trip conditions were no longer satisfied. During power operation this latent condition was partially masked by the greater than 15 percent power automatic bypass signal applied downstream of the comparator output circuitry. Additionally, the automatic bypass of the bistable trip signal below 10-4 percent power was never automatically removed during the startup due to the NI detector being failed low.

Following this investigation, maintenance and engineering personnel determined that the correct method to internally trip the bistable was to set the setpoint to the maximum negative value. This would ensure a trip would occur regardless of NI detector health whenever reactor power was less than 15 percent. The HSUR bypass for affected channels would also continue to be bypassed above 15 percent reactor power. A procedure revision is in progress to implement these new rule-based instructions.

Analysis of the Event

This event is reportable under 10 CR 50.73(a)(2)(i)(B) as any operation or condition that was prohibited by TSs.

The RPS HSUR trip is developed from the nuclear instrumentation (NI) wide range channels, and the trip signal may be automatically bypassed below 10 E-4 percent and above 15 percent power. When the trip is not bypassed, a reactor trip is initiated prior to the reactor power rate-of-change exceeding 2.49 decades per minute as measured by any two of the four wide-range NI channels.

Plant procedures provide two methods for placing an RPS HSUR channel in the trip condition. The first method pulls the Hi Rate bistable from the trip unit assembly. This method can be implemented quickly by control room operators, but has the disadvantage of sealing in a channel trip signal above 15 percent power. The second method has maintenance personnel reduce the bistable setpoint such that the channel would be expected to generate a trip signal with the automatic removal of the bypass between 10 E-4 percent and 15 percent power. This method has the advantage of preserving the automatic RPS HSUR bypass below 10 E-4 and greater than 15 percent power.

Prior to this event, the ‘B' channel wide range NI detector signal had been experiencing unpredictable operation, and the ‘B' RPS HSUR channel was placed in trip using the setpoint reduction method in October of 2016. During the 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 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.

September 2017 plant startup, the ‘B' RPS HSUR channel did not trip as expected when reactor power exceeded the bypass removal setpoint of 10 E-4 percent power. The ‘B' wide range NI detector failed low on February 10, 2017.

The setpoint reduction method (used before the detector failed) was predicated on a baseline NI detector signal not a failed low detector signal; the setpoint reduction method did not account for the static failed detector voltage and its effect on the trip. Additionally, the failed low detector signal did not remove the bypass.

Safety Significance

The high rate-of-change of power trip is not credited in any of the Chapter 15 accident analyses. However, the trip is considered in the safety analysis, in that the presence of this trip function precluded the need for specific analyses of other events initiated from subcritical conditions (e.g., events not discussed in Chapter 15).

Subsequent to the ‘B' wide range detector failure on February 10, 2017, Unit 1 was within the HSUR bypass conditions with power greater than 15 percent. On September 11, 2017, Unit 1 was shutdown due to degrading switchyard environmental conditions caused by Hurricane Irma. The inadequately implemented reduced trip setpoint method had no effect during the evolution because the operating procedure used during this shutdown required that the reactor be tripped above 15 percent reactor power while the HSUR bypass was still in effect. In addition, the inoperative channel trip was detected in the subsequent September 12, 2017 startup and actions were taken as directed by the TSs; therefore the inoperative trip had no effect on the subsequent startup.

As previously stated, the HSUR bistable is required for operation during the reactor power ranges of 10 E-4 percent to 15 percent power. Per the design basis, the RPS has four independent measurement channels that monitor parameters and trip at TS prescribed setpoints. In addition, each RPS channel is required to be demonstrated operable by the performance of a successful monthly functional test. The RPS is designed to initiate a reactor trip when the two out of four coincidence logic is satisfied (i.e. high startup rate). Therefore, even with the ‘B' RPS HSUR channel in a nonconforming condition, there is reasonable assurance that the three remaining healthy HSUR channels would have performed the function of the RPS system to trip if TS prescribed setpoints were exceeded.

Based on the discussion above, this event had no significant impact on the health and safety of the public.

Corrective Actions

1. The ‘B' RPS HSUR channel was recalibrated, placed in trip using the new setpoint reduction method, and the bistable was re-inserted into the cabinet.

2. A procedure revision is in progress to implement the new rule-based setpoint reduction method.

Failed Components

Component: wide range nuclear instrumentation detector JI-002 Manufacturer: Sigma Model: 9222-00ED

Additional Information

None.

05000335/LER-2017-00228 September 2017Saint Lucie

On July 31, 2017, FPL determined that the proceduralized manual actions to mitigate postulated electrical single failures in the St. Lucie Unit 1 hot leg injection (HLI) flow path were inadequate. Manual actions previously developed based on failure modes and effect analysis (FMEA) failed to identify the need to override open permissive interlocks in the HLI flowpath. The procedures were revised to account for the oversight, and a detailed FMEA was performed and enhancement opportunities were identified to be evaluated under the site corrective action program.

The safety significance for the additional jumper scope was bounded by previous evaluations. Therefore, this event had no significant impact on the health and safety of the public.

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 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.

Description of the Event

On July 31, 2017, with St. Lucie Unit 1 in Mode 1 at 100 percent reactor power, it was determined that the proceduralized manual actions to mitigate postulated electrical single failures in the St. Lucie Unit 1 hot leg injection (HLI) flow path were inadequate. The existing procedures lacked actions to address the installation of jumpers required to defeat the reactor coolant system (RCS) pressure interlocks for valves V3481 and V3652 (EIIS:BP:V) when aligning the plant for HLI. The procedures were immediately revised to include the instructions necessary to restore power to the affected valves. The required 8-hour NRC ENS notification was completed at 1832 hours.

A more detailed failure modes and effects analysis (FMEA) was completed to assure no other issues; although enhancements to improve margin were identified, there were no further issues identified that would preclude HLI flow for all strategies.

Cause of the Event

The reason the HLI initiation procedures were inadequate was that the previous FMEA to open V3481 and V3652 to provide hot leg injection was incomplete. This cause is a legacy human performance error associated with the level of detail and rigor in the evaluation and documentation of the capability to provide hot leg injection. A contributing factor was that the control circuits for valves V3481 and V3652 are not typical; the interlocks that prevent opening the valves are not powered from the MCC for the valve actuator.

Analysis of the Event

Reporting Criteria This condition is reportable pursuant to 10 CFR 50.73(a)(2)(ii)(B) as any event or condition that resulted in the nuclear power plant being in an unanalyzed condition that potentially degraded plant safety.

Background

Long-term core cooling and boron precipitation was identified during the initial licensing of St. Lucie Unit 1. Because the St. Lucie Unit 1 original design did not provide dedicated hot leg injection paths, St. Lucie Unit 1 was licensed to develop HLI procedures that utilized the existing low pressure safety injection (LPSI) and/or high pressure safety injection (HPSI) flow paths for hot leg injection.

There are five potential paths for implementing HLI. The preferred HLI flow path is to direct the discharge of one LPSI pump (EIIS:BP:P) through the 2-inch shutdown cooling (SDC) warm-up line to the opposite pump's suction line, and "backwards" through the suction line into the hot leg. The cold leg injection is via the normal HPSI pump (EIIS:BQ:P) operation. This flow path requires the opening of two motor operated valves (MOVs) in series to be successful; each valve is powered from a different electric bus.

Valves V3481 and V3652 are the cross-train powered SDC return isolation valves for the respective 1A and 1B SDC cooling loops. Loss of power scenarios were 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 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.

mitigated by the contingency use and installation of staged electrical jumpers to provide power for these valves from the opposite train motor control center (MCC).

However, the previous FMEA failed to identify that these valves' control circuits contain open permissive interlocks to prevent subjecting the lower pressure portion of the SDC system to the higher reactor coolant system (RCS) pressure.

The FMEA performed for the 2011 LER failed to identify the need to defeat this interlock by installation of low voltage jumpers in the control room.

This condition is not applicable to St. Lucie Unit 2 as it has a dedicated HLI flow path as part of its original design.

Analysis of Safety Significance The mechanism for potential boron precipitation is described in Unit 1 UFSAR Chapter 6 Appendix C. For a hot leg break, the injection flow passes from the cold legs, through the core, into the hot legs, and out the break. For a hot leg break, core heat removal is via forced flow of the injection water. In contrast, for a cold leg break, after the reflooding is completed, the hydraulic balance will cause most of the injection flow to spill out of the break - the only flow into the core will be that required to make-up for the boil-off in the core that removes the core decay heat. The boron problem arises only during a cold leg break; as borated injection flow enters the core, and only pure water (as steam) leaves the core, the boron concentration in the core region will continue to increase. Once the boron concentration exceeds the solubility limit the boron will precipitate and potentially challenge long-term core cooling capability. The solution to the potential problem is to achieve subcooled flow through the core:

when boron in equals boron out, the concentration will not be increasing.

St. Lucie uses simultaneous hot and cold leg injection as the method to achieve forced flow through the core for long-term post-LOCA cooling. With simultaneous hot and cold leg injection, the recirculated sump fluid is injected into the hot legs as well as the cold legs. Regardless of break location, sufficient flow is delivered to provide heat removal and flush the core to prevent the concentration of boron from reaching the solubility limit.

The operators are procedurally required to initiate HLI within four to six hours post-accident.

If the loss of an electrical bus required the use of the proceduralized jumpers, the emergency response organization (ERO) problem solving teams in the technical support center (TSC) and emergency operation facility (EOF) would most likely diagnose and mitigate the open permissive interlock and initiate HLI within the required timeframe. The 2011 LER evaluated the safety significance for the use of knowledge-based instead of rule-based jumper installation, and the additional low voltage control circuit jumper scope identified in this LER does not materially affect the conclusions of the previous LERs. Based on these considerations, this event had no significant impact on the health and safety of the public.

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 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.

Corrective Actions

The corrective actions listed have been entered into the site corrective action program (CAP). Any changes to the actions below will be processed in accordance with the CAP.

1. The additional jumper scope was added to the proceduralized manual actions for bypassing the de-energized interlocks for SDC suction valves.

2. A more detailed FMEA was completed and additional enhancements to improve margin were identified. These enhancements are being tracked in CAP.

Identified Failed Components None

Additional Information

St. Lucie Unit 1 LERs 2011-003-00 (ADAMs accession number ML12023A003) and 2011- 003-01 (ADAMs accession number ML12081A282) reported the use of unproceduralized manual actions to accomplish HLI.

05000389/LER-2017-00214 July 2017Saint Lucie

On May 15, 2017, at 1800 hours, the St. Lucie Unit 2 2A3 4.16 KV Bus undervoltage protection relays actuated resulting in a loss of power to the bus. The 2A emergency diesel generator (EDG) did not respond to this event as this EDG had been properly removed from service for pre-planned maintenance. The 2A3 4.16 KV Bus was restored to service at 2340 hours.

The 2A3 4.16 KV Bus was de-energized when an internal fault within the 2A EDG local voltmeter blew fuses that removed power from the undervoltage relays that resulted in the loads powered from this bus being stripped.

Corrective actions included replacing the fuses and replacing the susceptible local EDG voltmeter, as well as the interim use of caution tags on the susceptible voltmeter selection switches until modifications to remove the vulnerability are complete.

During this event the B train safety related electrical busses remained operable and energized. All other equipment responded to the event per the existing plant conditions and the unit remained at 100% power. The A train safety related electrical bus was restored to service well within the Technical Specification allowed outage time. Therefore, this event had no significant impact on the health and safety of the public.

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 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.

Description On May 15, 2017, St. Lucie Unit 2 was in Mode 1 at 100 percent reactor power. The 2A emergency diesel generator (EDG) (EIIS:DG) was removed from service due to planned maintenance. At 1800 hours, the 2A3 4.16 KV Bus undervoltage protection relays (EIIS:27) actuated resulting in a loss of power to the bus (EIIS:SWGR). However, the 2A EDG did not respond to this event as this EDG had been properly removed from service for pre-planned maintenance. The troubleshooting team identified blown potential transformer (PT) fuses (EIIS:FU) in the 2A EDG metering circuit. The failed fuses were replaced and the 2A3 4.16 KV Bus was repowered at 2340 hours. The required NRC ENS notification for the system actuation was completed by 0017 hours on May 16, 2017. During this event the B train safety related electrical busses remained operable and energized and the unit remained at 100% power.

Cause of the Event

The direct cause of the bus de-energization was determined to be failed secondary side PT fuses which provide power to the under voltage/degraded grid sensing circuity. The root cause was an internal failure within the local 2A EDG GE AB40 voltmeter (EIIS:MTR) causing a phase to phase short across the variable resistor. This condition resulted in the failure of the secondary PT fuses, resulting in the actuation of the 2A3 4.16 KV Bus UV relays. A contributing cause to this event was a latent design deficiency from original construction; the meter circuit did not have isolation fuses from the PT fuses. This allows an internal fault of the meter to open the protective circuit fuses and subsequently de-energize the UV relays.

Analysis of the Event

Even though the 2A EDG did not respond to the loss of the 2A3 bus because it was properly removed from service, the 2A3 4.16 KV bus UV protection relays did respond to the event and their actuation is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A).

Two conditions contributed to the plant response to the event:

1. The local voltmeter selector switch was in the 1-3 position. This position allowed the meter fault to be simultaneously communicated to both phases of the PT fuses. These fuses provide sensing power to the UV relays which provide electrical isolation to the safety related 2A3 4.16 KV bus. Upon sensing the loss of power to the onsite power system, the safety portion of the system is automatically isolated from the non- safety portion of the system by the operation of circuit breakers on the lines between non-safety and safety related buses.

2. The 2A EDG was out of service for the on-line preventive maintenance period. This precluded the 2A EDG from starting and assuming the loads of the 2A3 4.16 KV bus. Section 8.3 of the UFSAR, Table 8.3-6 4.16 KV Safety Related System – Failure Modes and Effects Analysis describes the consequences of loss of offsite and EDG power to the 2A3 or 2B3 bus. The analysis states that the loss of an EDG in this case will result in the loss of a one safety related bus, however, the redundant safety system remains to supply the redundant safety related loads. Additionally, DC control power in this event remained unaffected, and the A side instrument inverters remained powered throughout by the A side DC battery.

FPL performed extent of condition/extent of cause reviews for AC voltage metering circuits containing the GE AB40 voltmeter, as well as other voltmeters, for both units' safety related 4160 and 480 volt buses. The review determined that, with one exception, all remote voltage indication associated with the reactor turbine generator board (RTGB) voltmeters are all fused providing isolation of the metering circuit from their respective protective functions. The exception involves the Unit 2 local EDG voltmeters. The U2 EDG local metering circuits were determined to be the only safety related 4160 and 480 volt metering circuit whose failure could initiate a 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 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.

protective function (e.g., blown PT fuses resulting in the de-energization of its associated bus UV relays). These reviews also identified several metering circuits that were not fuse protected; however, in these cases any proposed meter failure would only annunciate with no corresponding automatic protective function.

Safety Significance

The 2A EDG received a start signal from the under voltage condition on the 2A3 bus, but did not start as the EDG had been properly removed from service for preplanned maintenance. Upon a loss of indicated power to the potential transformers, the 2A3 4.16 KV bus responded appropriately for the existing plant conditions (e.g., the under voltage circuit relays actuated, the incoming breaker to the 4.16 KV bus opened, and a start signal was provided to the associated 2A EDG which was properly removed from service). Although the safety related 2A3 loads were lost during this event, the redundant loads serviced by the 2B3 train 4.16 KV safety related electrical bus remained unaffected by the event and the unit remained at 100% power.

Normal power was restored to the 2A3 4.16KV bus within 6 hours of the event, well within the allowable 8-hour Technical Specification action statement for restoring the 2A3 4.16 KV bus. Therefore, this event had no significant impact on the health and safety of the public.

The Unit 2 UFSAR section 8.3 describes Failure Modes and Effects for the 4.16 KV safety related system. This analysis bounds the observation of the event described in this LER.

Corrective Actions

EDG voltmeter selector switches directing that the switches not be left in the 1-3 position.

2. The local voltmeter for the 2A EDG was replaced.

The following corrective action is being managed under the Corrective Action Program:

3. The local voltmeter for the 2B EDG will be replaced.

4. FPL is developing a modification to the 2A and 2B EDG metering circuit to install coordinated fuses between the metering circuit and the PT fuses to isolate the metering circuit from the UV relays in the event of a voltmeter fault.

Failed Components Identified General Electric AB40 voltmeters

Additional Information

None

05000335/LER-2017-0012 May 2017Saint Lucie

On January 31, 2017, while St. Lucie Unit 1 was shut down in Mode 3, technicians identified reactor coolant pressure boundary leakage within the 1B2 reactor coolant pump (RCP) lower seal heat exchanger. At 1200 hours, St. Lucie Unit 1 entered Technical Specification 3.4.6.2 Action a. and the plant was maneuvered to Mode 5 to affect repairs.

The most probable cause was determined to be a deficiency in the lower seal heat exchanger design which permitted stresses that approached or exceeded the yield strength of the assembly tubing during torqueing of the CCW flanges.

The resultant plastic deformation and associated flaw formation caused low stress high cycle fatigue failure of the weld joint.

The flaw was removed and the weld repair was completed. St. Lucie Unit 1 was subsequently returned to service on February 7, 2017.

All remaining in-service and a spare RCP lower seal heat exchangers have since been inspected and no defects have been found. This event had no impact on the health and safety of the public.

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 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.

Description On January 31, 2017, St. Lucie Unit 1 was shut down in Mode 3 for a maintenance outage to investigate and repair the source of reactor coolant system (RCS) (EIIS:AB) leakage coming from the vicinity of the 1B2 reactor coolant pump (EIIS:P) (RCP) seal (EIIS:SEAL) package. At 1200 hours, technicians determined that the leak was located in the RCP lower seal heat exchanger (EIIS:HX) and that the leakage was classifiable as reactor coolant pressure boundary leakage. St. Lucie Unit 1 entered Technical Specification (TS) 3.4.6.2 Action a. and the plant was maneuvered to Mode 5 to affect repairs. The 10 CFR 50.72(b)(3)(ii) notification was made at 1539 hours.

The flaw was removed and the weld repair was completed. St. Lucie Unit 1 was subsequently returned to service on February 7, 2017.

Cause of the Event

The most probable cause was determined to be a deficiency in the lower seal heat exchanger design which permitted stresses that approached or exceeded the yield strength of the assembly tubing during torqueing of the CCW flanges. The resultant plastic deformation and associated flaw formation caused low stress high cycle fatigue failure of the weld joint.

All of the in-service and spare St. Lucie Unit 1 and 2 RCP lower seal heat exchangers have been inspected.

These inspections did not find any deficiencies.

Analysis of the Event

This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by TSs, and 10 CFR 50.73(a)(2)(ii)(A) as a degraded or unanalyzed condition. Remote video analysis at power was inconclusive whether the leak was RCS pressure boundary. However, close visual inspection following unit shutdown determined the leak to be a small flaw in a RCS pressure boundary component (i.e. RCP seal cooler) which was a degraded condition prohibited by Technical Specifications.

The rotating assembly, the pump cover, and integral lower seal heat exchanger for the 1B2 RCP had been replaced during the previous refueling outage in the fall of 2016. The 1B2 RCP has an integral tube-in-tube heat exchanger which is permanently attached to the pump cover. This heat exchanger surrounds the labyrinth seal and provides cooling of the RCS water prior to entering the seal. This heat exchanger is comprised of two rows of six coils circling the RCP seal. The inner tube of the tube-in-tube configuration carries the high pressure RCS water. The outer tube carries the low pressure component cooling water (CCW) (EIIS:CC). RCS fluid enters the coils at the bottom of the assembly and exits the coils at the top of the assembly (one from the inside coil and one from the outside coil). The outlet of the coils is directed thru a machined elbow fitting welded to a short length of 1.5 inch diameter pipe, which carries the RCS flow to the seal housing and seal cartridge The leak was located in the tube material near the toe of the partial penetration weld that joins the seal cooler inner tube and ring.

A review of the Unit 1 containment atmosphere particulate monitor and reactor cavity leakage flow instrument data indicates that RCS leakage from the 1B2 RCP lower seal heat exchanger was initiated on November 9-10, 2016, approximately 1 week after the 1B2 RCP had been started during startup from the fall 2016 refueling outage. The Unidentified RCS leak rate was closely monitored while a maintenance outage was planned to repair or replace the newly installed RCP seal package.

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 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.

Safety Significance

This condition was determined to be of very low safety significance for the following reasons:

  • The maximum Unidentified RCS leak rate of 0.17 gpm was well within the capacity of the three charging (EIIS:CB) pumps (44 gpm each) (EIIS:P) which make up water volume to the RCS. RCS leak balances are normally calculated at once per day. Real time RCS leakage indications are detected through containment particulate radiation monitoring and cavity sump detection and may drive more frequent leakage calculations.
  • The indication of RCS leakage approximately one week after pump start indicates that fatigue crack initiation and propagation through the inner tubing (0.125-inch min wall) occurred quite rapidly after pump start. Crack propagation appears to have slowed or arrested quickly as the total flaw length had only reached 15% of the inner tube's outer circumference approximately three months later. Such fatigue crack behavior is consistent with the postulated reduction in fatigue strength due to the presence of a residual stress. As the crack propagated, the residual stress was relieved and the positive mean stress reduced or eliminated. The applied cyclic loads associated with pump operation were insufficient to support continued crack propagation across the entire tubing cross section. The Unidentified RCS leak rate plateau during this period of time validates this observation. A Finite Element Analysis calculation was performed to confirm that the observed through wall crack would not propagate and leakage would remain within the capacity of the charging pumps.

Therefore, this event had no impact on the health and safety of the public.

Corrective Actions

1. The 1B2 RCP lower seal heat exchanger leak was repaired during the maintenance outage.

2. All remaining St. Lucie Unit 1 and 2 RCP lower seal heat exchangers were inspected and no other flaws were identified.

3. FPL is developing methods to reduce the stress on the RCP lower seal heat exchanger tubing during installation activities.

Failed Components Identified Flowserve supplied RCP lower seal heat exchanger

Additional Information

The weld repair required relief from ASME Code requirements, and those details are documented in FPL letter L-2017-017 dated Feb 2, 2017, titled “In-service Inspection Plan Fourth Ten-Year Interval Unit 1 Relief Request No. 14, Revision 0,” ADAMS accession number ML17033A151.

05000389/LER-2017-00127 April 2017Saint Lucie

On March 1, 2017, Unit 2 was in a defueled condition during a refueling outage and transitioned to a single operable train of the control room emergency air cleanup system. While in this condition, movement of irradiated fuel is prohibited by Technical Specifications. Approximately 100 minutes after transitioning to the single operable train of the control room emergency air cleanup system, control room operators were informed that irradiated fuel inspections in the Fuel Handling Building were in progress.

Operators immediately placed the control room emergency air cleanup system on recirculation to comply with Technical Specifications.

The cause of this event was inadequate procedure instructions for the coordination of fuel handling activities in the spent fuel pool. Corrective actions included revising procedure instructions for the coordination of fuel handling activities.

This licensee event report is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications. This event had no impact on the environment or onsite personnel.

This event had no effect on the health and safety of the public.

05000335/LER-2016-00320 October 2016Saint Lucie

On August 21, 2016, during Unit 1 restart following a maintenance outage, an unexpected actuation of the Main Generator Inadvertent Energization Lockout Relay caused the main generator to trip, resulting in an automatic reactor trip. The generator lockout prevented the automatic transfer of station auxiliaries to the available startup transformer power, requiring the emergency diesel generators to start and power the safety related buses.

Reactor coolant pumps normally powered through the non-safety buses were deenergized, and decay heat removal was via natural circulation and Auxiliary Feedwater. The lockout relay actuation was caused by a latent error introduced during a 2013 design modification where a wire was inadvertently removed from the circuit.

Corrective actions included restoration of the affected circuit and implementation of procedure guidance to verify the inadvertent energization relay state and to reset as required following Main Generator manual synchronization.

This licensee event report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) for system actuations of the reactor protection system, the emergency diesel generators and the auxiliary feedwater system.

This event had no effect on the health and safety of the public.

05000335/LER-2016-0024 October 2016Saint Lucie

On August 5, 2016, during Unit 1 restart following a maintenance outage, operators observed excessive seat leakage past a Reactor Coolant System (RCS) pressure isolation check valve. The flow path was promptly identified and isolated. A leak test was planned and performed at higher RCS pressure to quantify the leakage. The seat leak test at normal operating pressure was halted when an appropriate differential pressure was not achieved for testing. As a result, V3217, Safety Injection Loop 1A2 Check Valve, was declared inoperable, and Unit 1' was placed in Mode 5 COLD SHUTDOWN to complete repairs. The leakage past V3217 was caused by inadequate maintenance practices and procedures that did not ensure V3217 was within acceptable tolerances and correctly assembled in 2013.

Cofrective actions inclUde revisions to procedures for check valve maintenance, check valve trending and check valve preventive maintenance.

This event is reportable pursuant to.10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications. Since this condition was identified with Unit 1 in HOT STANDBY prior to reactor startup, the leaking check valve had no direct nuclear safety significance or impact to the environment.

This event had no effect on the health and safety of the public.

05000335/LER-2016-00129 July 2016Saint Lucie

On June 2, 2016, St. Lucie Units 1 and 2 were in Mode 1 at 100% power. At 1500 hours FPL declared the containment high range radiation monitors (CHRRMs) inoperable on both Units. FPL determined that the resolution of the-.NRC Information Notice (IN) 97-45 industry Operating Experience (OE) concerning CHRRMs cabling was less than adequate. The assumed CHRRMs design accuracy could not be assured during some postulated design basis accidents due to the errors introduced by thermal induced currents and water intrusion/cable blistering within the associated detectors' cabling, resulting in inoperable CHRRMs. The Technical Specifications (TSs) require pre- planned alternate means for containment radiation monitoring for inoperable CHRRMs; these requirements were not implemented until June 2016. FPL also submitted a TS 6.9.2 Special Report for two channels of inoperable CHRRMs.

This legacy event was caused by the inadequate evaluation and improper tracking of actions required to fully close the nonconformance identified in the 1997 Information Notice. CHRRMs are used for information, they are not used to control radioactive releases or mitigate accidents. Their inoperability had no significant impact on the health and safety of the public.

FPL plans to replace the CHRRMs cabling susceptible to the phenomenon identified in NRC Information Notice 97-45 and its supplement 1.

05000389/LER-2015-00318 December 2015Saint Lucie

On October 19, 2015, during corrective maintenance activities on containment isolation valve FCV-26-3, maintenance personnel discovered that the valve actuator position limit switches were not wired correctly since December 2001.

This condition invalidated previous closure time surveillance results for this valve.

This condition is being reported pursuant to the requirements of 10 CFR 50.73(a)(2)(i)(B).

The wiring discrepancy was caused by a legacy maintenance human performance issue. The limit switch wiring was corrected, the post-maintenance testing was completed satisfactorily, and the valve was returned to service.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 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 intemet e-mail to Infocollects.Resourc,e@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.

05000389/LER-2015-00216 November 2015Saint Lucie

On September 17, 2015, at 1222 hours, with Unit 2 in Mode 5 at the beginning of a refueling outage, an electrical fault on the 2A 6.9 kV bus resulted in the loss of the 2A startup transformer (SUT) and its associated non-safety related 2A2 and safety- related 2A3 buses. The loss of the 2A SUT actuated the under-voltage relays that would have started the 2A EDG, which had been properly removed from service for preplanned maintenance. The root cause was that the protective boots for a bus bar bolted connection on a vertical riser were not installed (left between bus conductors) during initial plant construction.

Immediate corrective actions included extensive inspections and repair of the remaining vertical portions of this bus. Follow-up corrective actions include performing internal visual inspections of remaining vertical sections of non- segregated buses to ensure that bolted connections have properly installed protective boots.

This event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in automatic actuation of an EDG. All safety related systems functioned as designed.

This event had no effect on the health and safety of the public.

05000335/LER-2015-0017 October 2015Saint Lucie

On August 9, 2015 with St. Lucie Unit 1 in Mode 1 at 100% reactor power, an unplanned reactor trip occurred. The trip occurred while Operators were performing a reactor protection system (RPS) logic matrix test in which the individuals performing the test did not follow the procedure steps in sequence resulting in a loss of configuration control. As a result, a set of reactor trip circuit breakers (TCBs) was opened before ensuring that all TCBs tested in the previous test section had been closed.

Corrective actions include procedure revisions to the test methodology to ensure configuration control of the TCBs is maintained through additional verification techniques.

This reactor trip event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an actuation of the reactor protection system (RPS). This event had no significant safety consequence since the RPS successfully performed its intended safety function upon opening the trip circuit breakers.

This event had no effect on the health and safety of the public.

05000389/LER-2014-00130 January 2015Saint Lucie

On July 25, 2014 with St. Lucie Unit 2 in Mode 1 at 100% power, a leak was confirmed on a one inch pipe between a safety injection tank (SIT) and a discharge header vent valve. In accordance with Technical Specifications (TS) and plant procedures, operators subsequently shut down the unit to repair the leak. The shutdown was uncomplicated and all plant safety systems functioned as designed. The leaking vent line and valve assembly were replaced and returned to service on July 28, 2014.

Engineering evaluation identified the direct cause of the pipe leak as through-wall cracking from high cycle, low stress fatigue. This condition is reportable in accordance with the following requirements: 1) 10 CFR 50.73(a)(2)(ii)(A), 2) 10 CFR 50.73(a)(2)(i)A, 3) 10 CFR 50.73(a)(2)(i)B, 4) 10 CFR 50.73(a)(2)(v)(D), 5) 10CFR50.73(a)(2)(ii)(B) and 6) 10 CFR 50.73(a)(2)(vii)(B).

This supplement revises the event description, analysis of event and safety significance and adds additional reporting criteria. This condition was determined not to be a significant impact on the health and safety of the public.

05000389/LER-2013-00413 January 2014Saint Lucie

On November 14, 2013 Unit 2 was in Mode 1 at 100 percent power when the 2B Steam Generator Train A main feedwater isolation valve (MFIV) HCV-09-2A spuriously stroked closed. This resulted in a manual reactor trip of Unit 2 due to rapidly lowering steam generator water level. The reactor trip was normal and uncomplicated. All safety related systems functioned as designed.

There were no automatic safety system actuations as a result of the trip. .

The MFIV closure was a result of corrosion of two relays (3Y/671 or 20X/671) located inside the relay box caused by internal water intrusion in the conduits.

Immediate corrective actions included replacing the degraded relays and installing internal conduit seals. An immediate extent of condition inspection and replacement resulted in installation of conduit seals and replacement of three degraded relays.

This event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a manual actuation of reactor protection system (RPS). All plant systems responded as designed and there was no safety significance associated with this event.

05000335/LER-2013-00213 January 2014Saint Lucie

On November 12, 2013 St. Lucie (PSL) Unit 1 was manually tripped due to a digital-electro- hydraulic (DEH) fluid leak from a tubing fitting in the turbine control system. Prior to the reactor trip, PSL Unit 1 was at 90% power ascending to 98% power following the SL1-25 refueling outage. Following the reactor trip, emergency operating procedures were successfully completed and the unit was stabilized in Mode 3. The reactor trip was uncomplicated. All systems functioned as designed. There were no automatic safety system actuations as a result of the trip.

A root cause evaluation was performed which identified the cause as failure of a DEH tubing fitting as the result of high cycle fatigue fracture and inadequate tubing support following a DEH pump replacement.

Corrective actions include: 1) update of the engineering procedure for post-modification testing and 2) update of the maintenance procedure for post-maintenance testing, to inspect for vibration and inadequate support of adjacent tubing/piping after a change to a vibration inducing component (pump, fan, etc.) This reactor trip event is reportable pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a manual actuation of reactor protection system (RPS). This event had no significant safety consequence.

Given the response of the plant and the actions taken, the health and safety of the public was not affected by this event.

05000389/LER-2013-00229 July 2013Saint Lucie

On June 3, 2013 at approximately 2000, Unit 2 was in Mode 1 at 8 percent power.

During monthly functional testing on the 2A hydrogen analyzer by Instrumentation and Controls ( I&C) personnel, the containment dome sample valve did not close when the selector switch was placed in the "OFF" position. The valve was not recognized as a containment isolation valve (CIV) and consequently the applicable technical .specification (TS) act ion statement to de- energize a downstream isolation valve within 4 hours was not entered. The downstream valve was however, in its normally closed position. Subsequently, the TS action statement was met by de- energizing the downstream valve.

This event is reportable pursuant to 10 CFR 5 0 . 7 3 (a) ( 2 ) ( i ) (B) as a condition prohibited by Technical Specifications. Since the sample valve is designated as a Class E piping penetration, and is designed to be open during a design basis event, this event had no significant safety impact. An apparent cause evaluation identified that the cause was a human error in evaluating the impact to plant operation caused by the failure of the hydrogen analyzer CIV.

Contributing causes included: 1) an inadequate procedure, and 2) ineffective hydrogen analyzer labeling.

Corrective actions include:

1) revision of the hydrogen analyzer procedure, 2) re- labeling the hydrogen analyzers to clearly demonstrate that the valves on the hydrogen analyzer are CIVs , and 3) operator briefing on lessons learned from the event.

05000335/LER-2013-00110 May 2013Saint Lucie

On March 12, 2013 at 1451 EDT, St. Lucie Unit 1 was in Mode 1 at 100% reactor power when the spurious closure of HCV-08-1B, 1B Main Steam Isolation Valve (MSIV), resulted in an automatic reactor trip. Upon troubleshooting and valve disassembly, it was discovered that interference between the internal tail link and the valve body prevented the valve disc from fully opening. This allowed unintentional loading of internal parts resulting in the failure of the valve's lower shear pin.

The pin failure led to spindle/disc separation and inadvertent closure of the valve.

This reactor trip event is reportable pursuant to 10 CFR 50.73 (a) (2) (iv) (A) as an automatic actuation of the reactor protection system (RPS). This event had no significant safety consequence since the RPS successfully performed its intended safety function upon the failure of the 13 MSIV.

The internal interference was caused by an oversized tail link supplied by the valve manufacturer. To correct the problem, the tail link was reworked to eliminate the body interference, and the MSIV was reassembled.

This event had no effect on the health and safety of the public.

05000335/LER-2012-0073 August 2012Saint Lucie

On June 7, 2 0 1 2 , FPL determined that the April 2, 2 0 1 2 , failure of the St. Lucie 1A2 emergency diesel generator (EDG) immersion heater pressure boundary was reportable. The most likely failure mode would have rendered the EDG inoperable for longer than its allowed outage time. The failure was attributed to procedural inadequacies during the fill and vent of the EDG following maintenance performed during the SL1-24 refueling outage. A contributing factor included inadequate chemistry procedures.

Immediate corrective actions included replacement of the failed immersion heater, extent of condition electrical checks on all St. Lucie EDG immersion heaters.

Other corrective actions included EDG chemistry, maintenance, and startup procedure changes. Additionally, the immersion heaters will be replaced with a design not susceptible to the same failure mechanism.

This event did not have a significant impact on the health and safety of the public.

05000335/LER-2011-0036 March 2012Saint Lucie

On November 3, 2011, with St. Lucie Unit 1 in Mode 1 at 85% power, the Onsite Review Group determined that past operation with unproceduralized manual actions to mitigate postulated single failures in the hot leg injection (HLI) flow path constituted a reportable condition.

St. Lucie failed to recognize that the historical condition was reportable due to weaknesses in corrective action program (CAP) implementation and legacy issues with operability/functionality determinations. Programmatic CAP improvements have been implemented to ensure condition reports are appropriately screened and dispositioned, and the operability/functionality determination program requirements have been updated.

The legacy design issue is being handled in the interim via proceduralized manual actions that are being tracked as an open operable but degraded condition via the station RIS 2005-20 list until an appropriate long-term solution is implemented.

This LER supplement concludes that there were no adverse effects of postulated HLI flow on the integrity of the regenerative heat exchanger.

05000335/LER-2011-00217 December 2011Saint Lucie

On October 19, 2011, St. Lucie Unit 1 was operating in Mode 1 at 86% when the unit was manually tripped due to rising condenser backpressure. The cause of the rising backpressure was an unplanned trip of the 1A1 circulating water (CW) pump.

Condenser backpressure reached procedural limits which required a manual unit trip. The 1A1 CW pump breaker tripped as a result of an internal motor fault.

Unit 1 was in a planned power reduction at the end of the cycle. All control element assemblies (CEAs) fully inserted and decay heat removal was achieved through main feedwater and steam bypass to the main condenser.

A root cause evaluation (RCE)concluded that ineffective condition monitoring of the 1A1 CW pump motor for degraded air flow passages prior to scheduled motor overhauls, resulted in a buildup of salt and corrosion products in the rotor cooling air flow passages, restricting air flow.

Contributing causes included previous actions to implement quarterly resistance temperature detector measurements for the CW pump motors were ineffective.

Corrective actions will implement temperature monitoring using the CW pump motor winding resistance temperature detectors (RTDs).

05000389/LER-2011-00221 November 2011Saint Lucie

On June 6, 2011 St . Lucie Unit 2 was in Mode 1, when an unplanned automatic reactor trip occurred. The trip occurred while Operators were performing a reactor protection system (RPS) test in which the Operator inadvertently moved the matrix relay trip select switch one position too far, causing the reactor trip circuit breakers (TCBs) to open. Upon reactor trip all CEAs fully inserted into the core, auxiliary feedwater actuation system (AFAS) initiated as designed on low steam generator water level and was restored using auxiliary feedwater. All safety related systems functioned as designed.

A root cause evaluation (RCE) determined the trip was a result of latent single human error vulnerability in the test methodology. Contributing causes included human error during performance of the test and inadequate "problem resolution" which required the matrix relay hold pushbutton to be depressed during performance of the entire test.

This event is reportable under 10 CFR 5 0 . 73 (a) ( 2 ) (iv) (A) , as any event or condition that resulted in a manual or automatic reactor trip and actuation of the auxiliary feedwater system.

Corrective actions include procedure revisions to test methodology to remove the human error vulnerability and replacement of the RPS matrix relay hold pushbuttons with rotary switches.

05000335/LER-2011-00120 October 2011Saint Lucie

On August 22, 2011, St. Lucie Unit 1 was operating in Mode 1 at 89% when it was manually tripped due to rising condenser back pressure. All control element assemblies (CEAs) fully inserted into the core. The cause of the rising back circulating water system performance. Decay heat removal was initially from the main feedwater and steam bypass to the main condenser. However, subsequent to the manual trip, the 1B main feedwater pump was manually secured due to a leak on the pump casing. The 1A main feedwater pump subsequently tripped due to low suction pressure after manually securing the 1B condensate pump and decay heat removal was transitioned to the atmospheric dump valves and auxiliary feedwater.

Root cause evaluation determined the jellyfish intrusion rate exceeded the current capacity of the traveling water screens and trash pits. In addition, procedural guidance did not anticipate the possible rapidly escalating jellyfish intrusion rate and the urgency for response regarding the negative effect of the rapid jelly intrusion on condenser back pressure was not recognized.

Contributing causes included: plant maneuvering did not account for condenser back pressure margin, equipment degradation and malfunctions, and design deficiencies.

Corrective actions include procedure revisions and design changes to address procedure deficiencies and correct design deficiencies.

05000389/LER-2005-00310 October 2005Saint LucieOn August 11, 2005,St. Lucie Unit 2 was in Mode 1 operation at 100 percent reactor power. Personnel errors by a non-licensed maintenance supervisor caused a de- energization of two electrical buses which resulted in a partial loss of feedwater event and manual reactor trip based on lowering steam generator levels. The event occurred when the maintenance supervisor opened the incorrect breaker cubicle during an equipment clearance order walkdown, and caused the spurious operation of a lockout relay when the breaker cubicle door was closed. In addition to the manual reactor trip, there were automatic actuations of the A train emergency diesel generator and auxiliary feedwater system. Safety related equipment responded to the event as required. Corrective actions included maintenance stand-downs and training. There were no adverse safety consequences as a result of this event.