|Report date||Site||Event description|
|05000364/LER-2017-005||11 January 2018||Joseph M Farley Nuclear Plant, Unit 2|
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.
|05000348/LER-2017-001||29 September 2017||Farley|
On July 31, 2017 with Unit 1 at 100% Rated Thermal Power it was identified that Q1P17HV2229-Norm/Block Switch (Norm/Block Switch) was out of position (aligned to the "SI BLOCK" position). This is a key operated switch which controls the operation of valve Q1P17HV2229 (HV-2229), Component Cooling Water (CCW) Supply to Sample Coolers. HV-2229 functions to automatically isolate the non-seismic portion of the CCW system which includes the Reactor Coolant System (RCS) Sample Coolers. The Norm/Block switch allows a Safety Injection (SI) signal to be blocked to allow alignment of CCW to the RCS Sample Coolers for post-accident sampling. The Norm/Block Switch was returned to normal position on August 1, 2017 at 0415.
HV-2229 also receives a closed signal on low level CCW Surge Tank which will override the Norm/Block switch regardless of position. Thus, in the event of an SI concurrent with a CCW leak, the safety function of CCW would have still been met. Since HV-2229 was blocked from closing and would not have met Surveillance Requirement (SR) 220.127.116.11 from October 29, 2016 (entry to MODE 4) to August 1, 2017, the station unknowingly operated in a condition prohibited by Technical Specifications which is reportable under 50.73(aX2)(i)(B).
Corrective actions include procedure changes, communications and training to close knowledege gaps associated with system operation.
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3. UM NUMBER 1. FACILITY NAME
On July 31, 2017 with Unit 1 at 100% Rated Thermal Power en operator was preparing to lift a clearance order on the Component Cooling Water (CCW) System. The operator noticed that the Q1P17HV2229-Norm/Block Switch (Norm/Block Switch) was not in the correct position. The Norm/Block Switch was not part of the clearance order. The Norm/Block switch allows a Safety Injection (SI) signal to be blocked to allow alignment of CCW to the Reactor Coolant System (RCS) Sample Coolers for post-accident sampling. The operator notified shift supervision.
An investigation was conducted to identify when the Norm/Block Switch was last manipulated. Based on interviews, records, and plant conditions it was determined that the most probable date the Norm/Block Switch was operated occurred on October 1, 2016 during chemistry sampling following a reactor trip. Farley Unit 1 began a refueling outage following this reactor trip.
EVENT CAUSE ANALYSIS:
An analysis of the event identified organizational shortfalls in both procedure quality and human performance. The Chemistry operating procedure for obtaining the RCS sample did not provide a method of maintaining configuration control for the Norm/Block Switch. Procedural guidance on the Norm/Block Switch operation was only located in the precautions and limitations portion of the procedure and not in the instruction portion of the procedure. Additionally, communication between the Chemistry Technician and the Control Room Supervisor (key control) was not sufficient because the Chemistry Technician did not understand system status or realize that operation of the Norm/Block switch was not required for sampling since the SI signal had been reset. The Chemistry Technician operated the Norm/Block Switch based on knowledge of the switch function obtained from reading the precautions and limitations. The Chemistry Technician left the switch in the "SI-Block" position when returning the key to the control room. Upon return of the key to the control room no challenge was provided on the configuration of HV-2229 or the Norm/Block Switch.
REPORTABILITY AND SAFETY ASSESSMENT:
The auto closure of HV-2229 during an SI is surveilled per Surveillance Requirement (SR) 18.104.22.168. This SR requires that "each CCW automatic valve in the fiowpath that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal". The last scheduled performance of the surveillance testing of HV-2229 was performed April 4, 2015. Per SR 3.0.1, failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be a failure to meet the LCO. With the inability to automatically close HV-2229 on an SI signal due to the position of the Norm/Block Switch Farley Unit 1 unknowingly operated in a condition prohibited by Technical Specification upon entry into MODE 4 at 0632 on October 29, 2016. This condition is reportable under 50.73(8)(2)(0(B).
This event would not have prevented CCW from meeting its safety function and has very low safety significance because HV-2229 also receives a closure signal from a CCW Surge Tank Low Level signal. The Low Level Surge Tank signal overrides the Norm/Block Switch regardless of position. Therefore, this event is not reportable for loss of safety function per 50.73(a)(2)(v).
The cause of the event is that the manipulation of the Norm/Block Switch was not tracked using approved processes.
Barriers that broke down include; 1. Procedural guidance was not adequate for the task to maintain configuration.
2. Personnel knowledge level of the plant impact for performing the task did not meet standards.
3. Communications / Questioning attitude to obtain authorization were inadequate for the performance of the task.
4. The preparation and procedure use and adherence of the task was inadequate.
Farley has initiated corrective actions to address the organizational shortfalls and knowledge gaps associated with the event. This event was immediately communicated to the Department, Site and Fleet personnel. A training needs analysis is being conducted in Chemistry and Operations on the knowledge gaps and procedural guidance. The Site specific procedure for operation of the system has been revised to address configuration control of the Norm/Blodc switch.
PREVIOUS SIMILAR EVENTS:
OTHER SYSTEMS AFFECTED:
No systems other than those mentioned in this report were affected by this event.
(Joseph M. Farley Nudear Plant, Unit 1 05000- 348 2017 00
|05000364/LER-2017-001||21 August 2017||Farley|
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).
|05000348/LER-2016-009||2 February 2017||Farley|
On 12/7/16 Units 1 and 2 were in Mode 1 at 100 percent rated thermal power. Engineering personnel determined that the Unit 1 and Unit 2 Service Water Intake Structure (SW IS) intake and exhaust ventilation hoods were not adequately protected from tornado generated missiles. Subsequent evaluations on 1/26/17 resulted in the determination that the emergency diesel generator (EDG) fuel oil storage tank (FOST) vents were also not adequately protected from tornado generated missiles. Operations subsequently declared the affected systems inoperable, implemented Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance" and the required compensatory measures, and then declared the affected equipment operable but non-conforming.
This comition is an original plant design legacy issue. Immediate compensatory measures included actions to take if needed as described in severe weather procedures, and monitoring of system parameters on the MCB in accordance with annunciator response procedures. A risk based evaluation will be performed or plant modifications will be undertaken to establish compliance with the site's tornado missile protection design basis.
|05000348/LER-2016-007||13 January 2017||Farley|
On 11/17/2016 at 1859 with Unit 1 in Mode 1 at 99 percent power, the plant initiated a shutdown in accordance with Limiting Condition for Operation (LCO) 3.0.3 for having no operable steam flow channels for the C Steam Generator (SG). The two steam flow channels did not meet acceptance criteria for Technical Specification (TS) 3.3.2. The shutdown was completed and the plant entered Mode 3 as required by LCO 3.0.3. This is reportable as a plant shutdown required by Technical Specifications in accordance with 10 CFR 50.73(a)(2)(i)(A). This is also reportable as an event or condition that could have prevented fulfillment of a Safety Function needed to mitigate the consequences of an accident, in accordance with 10 CFR 50.73(a)(2)(v)(D).
This condition was discovered during an engineering verification of beginning of cycle full power scaling values for steam flow normalization. New scaling data was calculated and the channels were rescaled and restored to operable status. The cause of this event has not yet been determined. A supplemental LER will be submitted upon the completion of the causal analysis, and the cause and corrective actions will be provided at that time.
|05000348/LER-2016-005||28 December 2016||Farley|
On 11/1/2016 at 1743, Farley declared an Alert based on ammonia levels on the radiation side of the Auxiliary Building in the Recycle Evaporator room. The declaration was based on toxic gas emergency action level (EAL) HA3 which states, "Release of toxic, asphyxiant, or flammable gases within or contiguous to a VITAL AREA which jeopardizes operation of systems required to maintain safe operations or establish or maintain safe shutdown." The source was identified as a failed valve in Auxiliary Steam supply to the Recycle Evaporator system, which had previously been abandoned in place. The ammonia leak was subsequently isolated. Ammonia levels were reduced and the event was terminated at 2340 on 11/1/2016. The failure was determined to be due to ammonia- copper interaction in the brass valve material.
This report is being submitted under 10 CFR 50.73(a)(2)(x) for an event that hampered site personnel in performance of duties necessary for operation of the power plant due to a toxic gas release.
|05000348/LER-2016-004||19 December 2016||Farley|
On 10/20/2016 with Unit 1 in Mode 6 during a refueling outage, motor field cables on the 1C Containment Cooler were found to contain splice material that was Environmentally Qualified (EQ) but not approved for use in containment. The material had been installed as part of a design change during the previous refueling outage. This unapproved material could have exposed the associated connectors to potential accident environments and was an untested configuration for EQ purposes. As a result, operability of the 1C Containment Cooler cannot be supported for cycle 27. During Cycle 27 the 1C Containment Cooler was the selected cooler for B train for periods that exceeded the required action completion time for Technical Specification (TS) 3.6.6 for one containment cooling train being inoperable. This is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.
The cause was a Human Performance error that resulted in selection of an incorrect splice kit for a design change. The corrective actions were the installation of an appropriately EQ qualified splice suitable for use inside containment, and the establishment of expectations to have a corporate environmental qualification specialist review design packages when working with EQ component replacements.
|05000348/LER-2016-006||19 December 2016||Farley|
On November 8, 2016, Joseph M. Farley Nuclear Plant Unit 1 was reducing power to remove the main generator from service. The 1A steam generator feed pump did not respond to control steam generator levels as expected when the miniflow valve was opened per procedure. Steam generator levels lowered due to lower feed flow, and at 1331 the reactor was manually tripped from 32 percent power to prevent reaching the low steam generator level automatic reactor trip setpoint.
The motor driven auxiliary feed pumps also started automatically, as expected, with the manual reactor trip. The main steam isolation valves were closed to limit the unit cool down, decay heat removal was accomplished with the atmospheric relief valves, and the unit was maintained in mode 3. The controller failure was caused by the speed reference adjust and speed controller (C2) card being out of tolerance due to a failed A2 operational amplifier on the card, which was caused by infant mortality. The C2 card was replaced, and the new card was verified to be within the required tolerance. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to manual actuation of the reactor protection system and automatic actuation of the auxiliary feedwater system.
|05000348/LER-2016-003||12 December 2016||Farley|
On 10/13/2016 it was discovered that a Unit 1 pressurizer safety valve (PSV), which had been removed during the October 2016 refueling outage and shipped offsite for testing, failed its as-found lift test. The PSV lifted below the Technical Specification (TS) 3.4.10 allowable lift setting value. Seat leakage of the PSV is the most likely cause of the setpoint drift.
It is likely that the PSV was outside the TS limits longer than allowed by the Required Action Statement (15 minutes) during the Cycle 27 applicable modes of operation. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) for a condition which was prohibited by the plant's Technical Specifications.
The PSV was replaced during the October 2016 refueling outage.
|05000348/LER-2016-002||30 November 2016||Farley|
On 10/1/2016 at 0512 CDT with Unit 1 at 99 percent power the plant experienced a turbine trip and automatic reactor trip as a result of inadvertent closure of the 1 A Steam Generator Main Steam Isolation Valve (MSIV).
This caused a rapid pressure reduction in the remaining two Steam Generators' steam lines, resulting in a Safety Injection (SI). The 1 A MSIV closure was caused by failure of its test solenoid in conjunction with other air system leakage, which vented air pressure from the 1A MSIV actuator. An inadequate technical justification allowed the improper deactivation of the preventive maintenance (PM) task of the test solenoid valve in 2004. Decision making by control room personnel not to strictly adhere to an Annunciator Response Procedure was a contributing cause to the reactor trip being automatic versus manual, and led to the SI.
Following the reactor trip and SI the 1 A MSIV test solenoid was replaced and check valves on the 1 A MSIV steam line were tested and replaced. The technical justifications of a sample of previously extended or deleted PMs strategies will be reviewed and corrected. The PM for the Unit 1 solenoid will be reinstated.
Procedure use and adherence standards have been reinforced with Operations personnel, simulator just-in- time training was conducted for all crews, and further causal analysis is planned to investigate operations fundamental performance gaps. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of the reactor protection system, Emergency Core Cooling System (ECCS) injection into the Reactor Coolant System, and automatic actuation of the AFW system.
|05000364/LER-2015-001||14 January 2016||Farley|
On 1/9/2015 at 1255 CST with Unit 2 operating at 100 percent thermal power the Turbine Driven Auxiliary Feedwater (TDAFW) pump was declared inoperable based on a causal investigation for a November 2014 surveillance test failure. The causal analysis identified that a design vulnerability existed which was the cause of both the November failure and a similar April 2014 failure. This vulnerability with the governor control system created a configuration within the software that had the potential for an expected trip signal to be recognized as a shutdown signal during the start sequence. Due to his condition, the TDAFW Pump could not be relied on to start for some plant conditions in the accident analysis for a Main Steam Line Break (MSLB) such that a reasonable assurance of operability could no longer be supported. Other accident analysis conditions were found to be unaffected. The cause of the design error was missing information in the original design documentation which would have provided an opportunity to develop the design change correctly in 2011.
For corrective actions, a temporary modification was made to increase a timer setpoint to eliminate the design vulnerability. This modification will be made permanent through the design change process. Design documents will be revised to add missing information which led to the design vulnerability.
Supplement: A past operability review has been completed and the results are appended to this LER.
|05000364/LER-2015-002||8 January 2016||Farley|
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
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
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.
|05000364/LER-2014-003||13 January 2015||Farley|
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.
|05000364/LER-2014-002||12 December 2014||Farley|
On 10/14/14 at 0341 CDT, Unit 2 reactor was manually tripped after a lightning strike In the High Voltage Switchyard (HVSY) led to a phase 3 to ground fault on a 500kV transmission line resulting in a B train Loss of Site Power (LOSP). The fault caused the 2B Startup Auxiliary Transformer (SAT) Instantaneous overcurrent relay to actuate and resulted in de- energizing the 2B SAT. A missing nut in the Power Circuit Breaker (PCB) protection circuitry caused a high resistance on one side of the current transformer circuit resulting in an imbalance in current flows and an actuation in the primary differential instantaneous overcurrent relaying. The B train LOSP in conjunction with the 2B Emergency Diesel Generator (EDG) being out of service for a planned maintenance outage caused a loss of Component Cooling Water (CCW) to the Reactor Coolant Pumps (RCP). The Unit 2 Abnormal Operating Procedures for loss of CCW and loss of A or B Train Electrical Power were entered and the reactor was manually tripped and the RCPs were secured. The reactor trip is reportable per 10 CFR 50.73(a)(2)(iv)(A) for manual actuation of the reactor protection system. Additionally, the reactor trip resulted in a valid actuation of the Auxiliary Feedwater system which is reportable per 10 CFR 50.73(a)(2)(iv)(A).
Corrective actions include: installed the missing PCB current transformer (CT) nut; satisfactorily tested primary and secondary protective relaying for 2B SAT; and strengthening of switchyard standards of the utility performing the maintenance. Extent of Condition walkdowns were performed for other circuits in the HVSY and repaired as necessary.
NBC FoRm 366 (03.2014)
|05000348/LER-2014-002||9 October 2014||Farley|
On February 28, 2014 at 1300, with Unit 1 operating at 100 percent thermal power, a lower than expected flow rate in the B-Train Residual Heat Removal (RHR) system was observed while conducting a surveillance test per procedure FNP-1- STP-11.2. Investigation of this condition determined that the low flow rate was a result of previous maintenance performed on October 13, 2013 to replace an actuator linkage on the B-Train RHR heat exchanger discharge valve, Q1E11HCV603B. Analysis of the February 28, 2014 test results determined that the B-train RHR system flow rate was less than the minimum allowed by Technical Specifications, rendering the B-Train RHR system inoperable. Since this condition has existed for a time period in excess of the applicable Technical Specification Required Action Completion Time, this is a violation of Technical Specifications and is reportable per 10 CFR 50.73(a)(2)(i)(B). Since the A-Train of RHR has been briefly inoperable during the period of B-Train RHR inoperability, this is also reportable per 10 CFR 50.73(a)(2)(v)(B,D).
To correct the low flow condition the full-open position of valve Q1E11HCV603B was adjusted to provide an acceptable flow rate. Corrective action taken established and communicated - using training, briefings, and performance monitoring plans - goals and expectations to improve issue resolution and prioritization, risk management, and response to operational challenges. Procedures were revised to identify valve adjustment verification requirements. The engineering analysis performed is preliminary and this LER will be supplemented if the final analysis warrants.
|05000348/LER-2014-001||17 April 2014||Farley|
On February 18, 2014 with FNP Units 1 and 2 operating at 100 percent thermal power, a review of industry operating experience determined that both units were in non-compliance with Technical Specification 3.4.3, Reactor Coolant System (RCS) Pressure and Temperature (P/T) Limits, during several previous refueling outages on each unit due to placing the RCS under vacuum conditions during RCS vacuum refill operations. From October 1995 through April 2012, 12 refueling outages have been conducted on Unit 1 and 11 on Unit 2 during which the RCS was placed under vacuum to perform vacuum refill operations. Technical Specification 3.4.3, applicable at all times, requires that RCS pressure, RCS temperature, and RCS heatup and cooldown rates be maintained within the limits specified in the Pressure Temperature Limit Report (PTLR). Although RCS temperature and heatup rates were maintained within limits, RCS pressure was lowered below zero pounds per square inch gage (psig), the lowest RCS pressure value identified on the curve.
The cause of not entering the required action for Technical Specification 3.4.3 was due to a failure to recognize that a negative RCS pressure is not allowed by Technical Specifications. An engineering review in support of the implementation of vacuum refill operations had previously determined that stress margins of the reactor pressure vessel and related components were not challenged. The station's PIT Limit curve is being revised to encompass RCS vacuum conditions.
|05000348/LER-2013-003||21 February 2014||Farley|
On November 5, 2013, with Unit 1 operating in Mode 1 at 100% power, Engineering personnel performing normalization calculations using beginning-of-cycle power ascension data identified that 1C Steam Generator Steam Flow Transmitter, FT-495, did not meet the acceptance criteria for normalization. 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 calculation was obtained on October 31, 2013, it is known that the channel had been inoperable since October 31, 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 10 CFR 50.73(a)(2)(i)(B). As an immediate corrective action, the steam flow loop was re-calibrated and returned to service on November 6, 2013. The apparent cause of this event was determined to be ineffective responses to previous events involving steam flow instruments not meeting normalization acceptance criteria. Corrective actions include providing additional margin in the normalization process and to pursue improvements in the scaling methodology to allow more timely identification of scaling inaccuracies.
|05000348/LER-2013-004||14 February 2014||Farley|
On December 16, 2013, while Farley Units 1 and 2 were both operating at 100 percent power in Mode 1, a review of industry operating experience related to unfused direct current (DC) ammeter circuitry was concluded. This review determined that the condition of unfused DC ammeter circuitry was applicable to both Farley units and that a postulated fire could result in concurrent shorts to ground of a DC ammeter cable and a DC cable of opposite polarity. Due to a lack of overcurrent protection, the resultant excessive current flow in the ammeter cable could result in a secondary fire in another fire area. The secondary fire could adversely affect alternate safe shutdown capability contrary to 10 CFR 50, Appendix R, requirements.
This condition is reportable pursuant to 10 CFR 50.73(a)(2)(ii)(B) as an unanalyzed condition that significantly degraded plant safety.
The cause of the condition was a latent design deficiency due to original plant design not providing DC ammeter circuits with overcurrent protection. Compensatory measures have been implemented for affected areas of the plant. Plant modifications are in development to provide these circuits with overcurrent protection.
|05000348/LER-2013-002||31 January 2014||Farley|
At 1202 CDT on October 4, 2013, while Unit 1 was in Mode 6, the B-Train Emergency Safeguards System (ESS) sequencer failed to actuate during the performance of procedure FNP-1-STP-40.0B (B-Train Safety Injection with Loss of Off-Site Power Test - B Train). Immediate investigation of the actuation failure identified that the Mechanism Operated Cell (MOC) Switch for the 1B Emergency Diesel Generator output breaker failed to actuate which resulted in no start signal for the B-Train ESS sequencer. At the time of the test, B-Train systems were not required by Technical Specifications to be in an operable condition. However, subsequent reviews of historical data have identified that the 1B Diesel Generator output breaker MOC switch failed to operate several times since August of 2010 during surveillance testing. Due to the history of this MOC switch, the 1B Diesel Generator is considered to have been inoperable for extended periods. This is reportable as a condition prohibited by Technical Specifications per 10 CFR 50.73(a)(2)(i)(B). Due to opposite train equipment being removed from service for various reasons during the affected periods this is also reportable as a condition that could have prevented fulfillment of a safety function per 10 CFR 50.73(a)(2)(v)(B,C,D).
The direct cause of the MOC switch failure was determined to be inadequate lubrication.
|05000364/LER-2013-001||13 September 2013||Farley|
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
|05000348/LER-2012-005||24 September 2012||Farley|
On July 26, 2012, at 2151 hours CDT with Unit 1 operating in Mode 1 at approximately 100 percent rated thermal power, a reactor shutdown was conducted in accordance with Condition H of Limiting Condition for Operation (LCO) 3.8.1 following expiration of the Completion Time allowed for compliance with Condition B.4 of that LCO. The Unit was stabilized in Mode 5 pending necessary repairs to EDG 1B and its return to operability. Previously, on July 16, 2012, LCO 3.8.1 was voluntarily entered and EDG 1B was removed from service for planned 24-month maintenance.
Following completion of the maintenance on July 20, 2012, during the post-maintenance operation evaluation run, oscillations occurred in certain EDG parameters including power output.
Subsequently, within minutes, EDG 1B unexpectedly shutdown. The initial investigation included an examination of all cylinders which led to the discovery of a damaged piston and cylinder liner on the #12 cylinder. Subsequent investigation determined the immediate cause of the EDG 1B shutdown was a high crankcase pressure trip: the underlying cause of the engine shutdown was the malfunction of the engine's intercooler thermostatic bypass valve (Q1R43V0561) due to the failure of one of three thermal actuating devices. There were no adverse effects on plant safety or on the health and safety of the public as a result of this event.
NRC FORM 38e (10-2olo) Joseph M Farley Nuclear Plant -Unit 1 05000348
|05000348/LER-2012-002||9 April 2012||Farley|
On February 15, 2012 at 0212, with Unit 1 operating at 100 percent power, 1B containment cooling fan (A Train) failed to start in slow speed during surveillance testing. Subsequent troubleshooting revealed that the failure of the fan to start was due to a malfunction of the 600 volt breaker that provides power to the fan motor slow speed winding. Based upon the investigation performed, it was determined the breaker had been rendered incapable of closing since January 18, 2012. This was the last time the breaker had been closed and the containment cooling fan had operated in slow speed satisfactorily. Although the 1B containment cooling fan was inoperable, the A Train of containment cooling was operable until the 1B containment cooling fan was selected for automatic start on January 23, 2012. Therefore, the A Train was inoperable for approximately 23 days until the failure was discovered on February 15, 2012. Since the seven day completion time of Technical Specification 3.6.6 Condition C was exceeded, this represents a condition prohibited by Technical Specifications and is reportable pursuant to 10 CFR 50.73(a)(2)(i)(B).
The A Train operability was restored in approximately eight minutes when the 1A containment cooling fan was selected to automatically start on February 15, 2012 at 02:20. Investigation into the breaker failure determined that the cause was due to a failed charging motor cut-out switch.
NRC FORM 368 (10-2010) 2. DOCKET 6. LER NUMBER � I � 3. PAGE 1. FACILITY NAME 002 - 00 Joseph M. Farley Nuclear Plant. Unit 1 05000 348 2012
|05000364/LER-2011-001||22 September 2011||Farley|
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)
|05000364/LER-2010-003||21 July 2010||Farley|
During the period between August 5 and August 9, 2009, the Unit 2 power supply to 1-2R 600 V load center (LC) did not meet the Unit 2 portion of Technical Specification (TS) 3.8.9 "Distribution Systems - Operating." This was discovered on August 9, 2009 when during routine surveillance for on-site AC distribution, the Unit 2 4160 V supply breaker DH08-2 to 1-2R 600 V LC was found in due to the 4160 V supply breaker DH08-2 from Unit 2 being open, and the required action statement was entered on August 9, 2009 at 02:02. Subsequently, the 4160 V supply breaker DH08-2 was closed on August 9, 2009 at 03:36. The 4160 V supply breaker DH08-2 being open resulted in a failure to meet TS 3.8.9 limiting condition for operation (LCO) for maintaining two trains of AC vital bus electrical power distribution subsystems operable. The 1-2R 600 V LC did not meet its surveillance requirement of correct breaker position and voltage for longer than the allowed by TS.
The 4160 V supply breaker DH08-2 was left open due to omission of relevant information in procedures and the interpretation of LCO 3.8.9 that existed at the time.
|05000364/LER-2010-002||2 July 2010||Farley|
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.