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	Site	Start date	Title	Description
05000410/LER-2013-001	Nine Mile Point	23 January 2013	Reactor Core Isolation Cooling System Isolation Due to a Temperature Switch Unit Failure	On January 23, 2013 at 15:16, Nine Mile Point Unit 2 was operating at 100 percent power when Reactor Building General Area temperature switch unit 2RHS*TS85A failed, resulting in the closure of primary containment isolation valves and causing the Reactor Core Isolation Cooling (RCIC) system to isolate from the reactor vessel and become inoperable. The failure of the temperature switch unit occurred concurrently with the High-Pressure Core Spray (HPCS) system inoperable for planned surveillance testing. With both the RCIC and HPCS systems inoperable, high pressure makeup capability to the reactor core was lost from these systems. This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A), as an automatic actuation of containment isolation valves in more than one system. The event is also reportable in accordance with 10 CFR 50.73(a)(2)(v), as an event that could have prevented the fulfillment of the safety function of systems that are needed to: (A) shut down the reactor and maintain it in a safe shutdown condition, and (D) mitigate the consequences of an accident. The temperature switch failed due to age-related capacitor degradation. The apparent cause of the event is insufficient use of the corrective action program to fully implement a periodic capacitor replacement program for the Riley temperature switches. Corrective actions include replacement of the failed switch and planned refurbishment of similar units.
05000410/LER-2013-002	Nine Mile Point	28 February 2013	Failure of High Pressure Core Spray System Pressure Pump due to Motor Winding Failure	On February 28, 2013 at 1319, Nine Mile Point Unit 2 was operating at 100 percent power when the High Pressure Core Spray (HPCS) system pressure pump failed. At the time of the failure, the HPCS system was inoperable for planned maintenance. The HPCS system pressure pump failure was due to an electrical short caused by a turn-to-turn failure in the motor. The cause of this event was determined to be a turn-to-turn short in the motor winding, attributed to poor manufacturer quality of the original motor. Corrective actions include replacement of the failed motor with a rewound motor and development of a new replacement strategy for these types of motors. This event is reportable in accordance with 10 CFR 50.73(a)(2)(v)(D), as any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. This report constitutes a 10 CFR 21 (Part 21) notification because the motor failure that initiated the event is attributed to a manufacturing deficiency. There are no previous LERs similar to this event.
05000410/LER-2013-004	Nine Mile Point	2 December 2013	Manual Reactor Protection System Actuation due to Loss of Reactor Recirculation Flow	On December 2, 2013, at 0903, Nine Mile Point Unit 2 (NMP2) was lowering reactor power level to remove the main turbine from service to support maintenance. During the power reduction, the Low Frequency Motor Generators (LFMGs) did not start automatically. Attempts to manually start the recirculation system pumps in slow speed were unsuccessful and a manual reactor scram was inserted due to the sudden reduction in core flow. This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B). The Reactor Protection System is listed in 10 CFR 50.73(a)(2)(iv)(B). The root cause of this event is a failure to identify that the switches in the auto transfer circuits for the reactor recirculation pumps to shift from high speed to low speed are single point vulnerable (SPV) components because they were exempted from the AP-913 classification process. Since the switches were not classified as SPV components, no mitigation strategies were developed. Corrective actions include revision of the operating procedures to manually start the LFMG sets and not rely on the auto transfer circuitry. There are no similar Licensee Event Reports for NMP2.
05000410/LER-2014-002	Nine Mile Point		High Pressure Core Spray System Inoperability Due to Inoperable High Pressure Core Spray Diesel Generator	At 0330 on February 27, 2014, the High Pressure Core Spray (HPCS) System was declared inoperable. The unplanned inoperability of the HPCS System is reportable in accordance with 10 CFR 50.72(b)(3)(v)(D) and 10 CFR 50.73(a)(2)(v)(D). The event occurred during the Division III Emergency Diesel Generator (EDG), 2EGS*EG2, post maintenance testing (PMT). The EDG testing identified erratic performance of a voltage regulator that was subsequently attributed to a degraded motor operated potentiometer (MOP) and other potentiometers within the voltage regulator. With EDG inoperability due to ongoing PMT, HPCS inoperability was declared. This action prevented NMP2 from exceeding a TS LCO action statement associated with EDG inoperability. The corrective action taken was to replace the defective potentiometers. With the satisfactory completion of the EDG PMT, the HPCS and EDG were declared operable on February 27, 2014 at 1013.
05000416/FIN-2008002-07	Grand Gulf	31 March 2008 23:59:59	Inadequate Design Control of HPCS Minimum Flow Valve MOTOR-OPERATED Valve Over Current Setpoint	The inspectors identified a self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion III, \"Design Control,\" for failure to properly set the over current trip setpoint for the high pressure core spray minimum flow motor operated valve. This resulted in a spurious over current trip of the valve breaker during a high pressure core spray momentary pump start for breaker operability following post Division 3 emergency core cooling system testing. As a result of the trip, the high pressure core spray minimum flow valve failed open. This issue was entered into the licensees corrective action program as Condition Report CR-GGN-2008-01201. The finding was more than minor because it was associated with the barrier integrity cornerstone to provide reasonable assurance that the physical design barriers protect the public from radionuclide releases caused by accidents or events. Using the MC 0609, \"Significance Determination Process,\" Phase 1 worksheet, the finding was determined to have very low safety significance since it did not result in a loss of the containment barrier. Additionally, the issue was screened and determined to not impact the High Pressure Core Spray mitigating system function (Section 4OA3)
05000416/FIN-2009003-02	Grand Gulf	30 June 2009 23:59:59	Inadequate Operability Evaluation for Debris Left in the Condensate Storage Tank	The inspectors identified a Green noncited violation of 10 CFR Part 50Appendix B, Criterion V involving a failure to follow procedures which resulted in an inadequate operability evaluation. During the week of May 18, 2009, the site conducted debris removal in the condensate storage tank. This debris removal was necessary because of a failure to remove all debris in the condensate storage tank during their spring 2007 cleanup project. The licensee performed an operability evaluation for objects left in the condensate storage tank which stated that the high pressure core spray system and reactor core isolation cooling would remain operable for all postulated events. Upon review by the inspectors, the operability evaluation did not address several issues including objects left in the condensate storage tank and condensate system return flow to the condensate storage tank following a plant shutdown/scram. The licensee entered this issue into their corrective action program as Condition ReportsCR-GGN-2009-02815 and CR-GGN-2009-02837.This finding is more than minor because the failure to perform an adequate operability evaluation, if left uncorrected, could become a more significant safety concern. Using the Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, this finding was of very low safety significance since it did not result in a loss of operability, nor did it screen as potentially risk significant due to a seismic, flooding, or severe weather-initiating event. The cause of this finding had a crosscutting aspect in the area of problem identification and resolution associated with corrective actions because licensee personnel failed to thoroughly identify all materials left in the condensate storage tank during their original operability determination
05000416/FIN-2009006-04	Grand Gulf	30 June 2009 23:59:59	Inadequate Corrective Actions for Replacement of Safety-Related Batteries	The team identified a noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for failure to identify and correct a condition adverse to quality related to the seismic qualification of the Division III High Pressure Core Spray safety-related battery. Specifically, the licensee failed to identify an incorrectly installed end bracket after replacement of the Division III safety-related battery in 2002 using procedures, work instructions, and drawings that were supposed to have been corrected after this same issue was identified during a 1997battery replacement activity. The licensee has entered this into their corrective action program as CR-GGN-2009-00830.This finding was more than minor because it affected the mitigating systems cornerstone attribute of external events for ensuring the availability, reliability, and capability of systems that respond to initiating events. Also, using Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Section 1-3,Screen for More than Minor ROP, question 2, the finding is more than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Using the Inspection Manual Chapter0609, Significance Determination Process, Phase 1 Worksheets, the finding was determined to have very low safety significance (Green) because it was confirmed to not result in a loss of operability or functionality. The finding was reviewed for crosscutting aspects and none were identified
05000416/FIN-2011003-05	Grand Gulf	30 June 2011 23:59:59	Failure to Provide Adequate Procedures for High Pressure Core Spray Minimum Flow Valve Surveillance Testing	The inspectors reviewed a self-revealing noncited violation of Technical Specification 5.4.1.a for the licensees failure to provide adequate testing procedures, which resulted in the high pressure core spray minimum flow valve inadvertently stroking approximately 11 times during a surveillance test. The excessive stroking of the valve resulted in the unplanned inoperability of the high pressure core spray system because the valves feeder breaker overcurrent instantaneous trip setpoint had drifted below the manufacturers tolerance for the existing setting. As immediate corrective action, the licensee replaced the degraded breaker. This finding was entered into the licensees corrective action program as Condition Report CR-GGN-2011-01901. The finding is more than minor because it is associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone\'s objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, inspectors determined that the finding was of very low safety significance (Green) because it did not result in a loss of system safety function since the high pressure core spray system would still have been functional even with the minimum flow valve potentially failing open. Additionally, it did not represent a loss of a system safety function and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of problem identification and resolution associated with operating experience in that licensee had not incorporated operating experience from a similar event that had occurred at another Entergy site.
05000416/FIN-2011003-09	Grand Gulf	30 June 2011 23:59:59	Licensee-Identified Violation	Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be accomplished in accordance with prescribed procedures. Specifically EN-OP-104, Operability Determination Process, Revision 5, Section 5.3(1), states in part to Confirm the existence of a Degraded or Nonconforming Condition for the Technical Specification System Structure or Component. Contrary to this requirement, on March 18, 2011, the on-shift senior reactor operator failed to perform a proper operability determination for the high pressure core spray pump after minimum flow valve 1E22-F012 cycled approximately 11 times during testing causing the supply breaker to trip open, resulting in high pressure core spray being inoperable. After resetting the breaker for 1E22-F012, ensuring the breaker was not faulted, and performing a one-time stroke test, the system was declared operable. Engineering personnel evaluated the event several hours later and questioned the operability of valve 1E22-F012 and the high pressure core spray system due to repeated cycling of the valve motor, which resulted in the breaker tripping. Based on engineering input, operations performed a second operability determination and determined that the system was operable with evaluation required. The licensee performed testing of the breaker for valve 1E22-F012 and determined its over-current trip setting had drifted to approximately 60 amps when its minimum allowed setting was 85 amps. This confirmed that the high pressure core spray system was inoperable the entire time. This issue was entered into the licensees corrective action program as Condition Report CR-GGN-2011-02240. The finding was determined to be of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of a system safety function, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.
05000416/FIN-2012003-05	Grand Gulf	30 June 2012 23:59:59	Failure to Follow a Post-Modification Test Procedure	The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, involving the licensees failure to follow a post-modification test procedure for the interconnecting siphon line between the two standby service water system cooling tower basins. Operability of the ultimate heat sink is based on a minimum water level in the two standby service water cooling tower basins, an operable interconnecting siphon between the basins, and four operable cooling tower fans (two per basin). At extended power uprate conditions, the configuration of the basins and the original siphon line would not support 30 days of operation of both trains of the standby service water system and the high pressure core spray service water systems without makeup, so the licensee performed a modification (EC 25649), which involved replacing the original siphon line with a new siphon line in order to transfer water from one basin to the other. On March 28, 2012, after completing the modification, the licensee performed post-modification testing to determine the piping friction loss coefficient of the modified siphon line and to evaluate its acceptability against the worst-case friction loss coefficient documented in EC 25649. The licensee deviated from the test procedure, as-written, and performed the test with an inadequate pressure gauge instead of the specified gauge. After inspectors challenged the validity of these test results, the licensee performed another test of the siphon line with a different method that did not require the use of a pressure gauge to measure the piping friction loss coefficient. The inspectors reviewed the subsequent test data and found the test results to be satisfactory. The licensee documented this concern in Condition Report CR-GGN-2012-05260. The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the use of an unqualified gauge invalidated the test results, and a different test method had to be developed to determine the piping friction loss coefficient for the siphon line. The inspectors evaluated this finding using Inspection Manual Chapter 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency confirmed to result in loss of operability or function; did not represent a loss of safety system function; did not represent actual loss of safety function of a single train for greater than its technical specification allowed outage time; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The finding had a cross-cutting aspect in the human performance area associated with work practices component because licensee personnel proceeded in the face of uncertainty or unexpected circumstances. Specifically, the licensee proceeded with the test without verifying that the pressure gauge was suitable for the test conditions after observing unexpected measurements with the gauge.
05000416/FIN-2012005-03	Grand Gulf	31 December 2012 23:59:59	Failure to Implement Adequate Procedure Instructions to Perform Preventive Maintenance Requiring the Periodic Replacement of the Control Relays in GE Magne Blast Circuit Breakers	The inspectors reviewed a self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to complete preventive maintenance tasks on the high pressure core spray division III diesel generator output breaker in accordance with the corresponding preventive maintenance task template. The licensee entered this issue in their corrective action program as Condition Report CR-GGN-2012-07992. The immediate corrective actions included replacing the failed control relay and restoring operability to the division III diesel generator. The long term corrective actions included revising breaker refurbishment/replacement procedure with directions to replace the control relay and change the procedure frequency to every 10 years versus every 12 years. The inspectors determined that this performance deficiency was more than minor and is therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, this failed control relay caused the subject breaker to fail to close during the division III diesel generator monthly surveillance on June 5, 2012. The inspectors used NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, to determine that the issue affected the Mitigating System Cornerstone. Because the finding pertained only to a degraded condition while the plant was shutdown, the inspectors used Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Checklist 8, Cold Shutdown or Refueling Operation Time to Boil > 2 Hours: RCS Level < 23 Above Top of Flange, to determine that the finding was of very low safety significance because it did not increase the likelihood of a loss of reactor coolant system inventory; did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; did not significantly degrade the licensees ability to recover decay heat removal if lost; and did not affect the safety/relief valves (Green). The inspectors determined that the cause of this finding was a latent issue that is not reflective of current performance, therefore no cross-cutting aspect was identified.
05000416/FIN-2015004-04	Grand Gulf	31 December 2015 23:59:59	Failure to Establish Adequate Maintenance Instructions to Perform Work Activities on the Division III Diesel Generator Overspeed Trip Limit Switch	The inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.4.1.a, for the failure to establish adequate maintenance instructions to perform work activities on the division III diesel generator overspeed trip limit switch. Specifically, work orders did not contain adequate instructions to check the overspeed trip switches alignment in accordance with vendor recommendations. As a result, the division III diesel generator was rendered inoperable and unavailable. On July 15, 2015, the licensee appropriately set the limit switch to overspeed actuating arm engagement, and returned the diesel generator to operable. The licensee entered this issue into their corrective action program as Condition Report CR-GGN-2015-3985. The failure to establish adequate work instructions to verify the overspeed switch was properly set and adjusted was a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, work orders to check the overspeed trip switches alignment did not contain adequate instructions to successfully perform the maintenance. The division III diesel generator was declared inoperable when the diesel spuriously tripped during the monthly surveillance run on July 13, 2015. The inspectors performed the initial significance determination for the division III emergency diesel generator failure. The inspectors used the NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it involved a performance deficiency that represented a loss of the high pressure core spray system following a postulated loss of offsite power because of the failure of the division III diesel generator. The Region IV senior reactor analyst performed a detailed risk evaluation in accordance with NRC Inspection Manual 0609, Appendix A, Section 6.0, Detailed Risk Evaluation. The detailed risk evaluation result is a finding of very low safety significance (Green). The calculated change in core damage frequency of 5.0 x 10-7 was dominated by an unrecovered station blackout beyond battery depletion. The analyst determined that the bounding risk of a large, early release of radiation was 9.6 x 10 . For the details of the analysis, see Attachment 3. Work orders were developed to address operating experience provided from the diesel generator vendor to the industry in December 2011. The inspectors determined that the cause of the deficiency occurred in 2011, and therefore, determined the finding did not have a cross-cutting aspect since it is not indicative of current licensee performance.
05000416/FIN-2015007-03	Grand Gulf	31 December 2015 23:59:59	Lack of Coordination of Division III HPCS Switchgear 127N Undervoltage Relays	The following issues were discussed during the inspection; however, the team must review additional information provided by the licensee to determine whether these issues result in a more than minor performance deficiency or a violation of NRC requirements. In accordance with Inspection Manual Chapter 0612, this issue will be characterized as an unresolved item. The incoming offsite power supply circuit breakers for Division III 4160 V switchgear 17AC are equipped with 127N undervoltage relays. According to Drawing E-1009, One Line Meter and Relay Diagram, 4.16kV E.S.F. System Bus 17AC, Revision 9, these relays Trip incoming breaker to bus & start diesel. According to drawing E-0121-005, Summary of Relay Settings (ESF) 4.16 kV Bus 17AC and Diesel Gen 13, Revision 7, these relays are set with a 0 second time delay. This instantaneous time response potentially results in lack of coordination of the 127N undervoltage relays with high voltage system protective relays, switchgear overcurrent relays, and loss of voltage relays, thus preventing the other relays from performing their credited design functions. Protective devices that the 127N undervoltage relays are potentially not coordinated with are as follows: Protective relays associated the main transformer and its output circuit: Lack of coordination between the 127N undervoltage relays and the protective relays associated with the main transformer and its output circuit can result in coincident loss of two alternating current power supplies, contrary to the requirements of General Design Criterion 17. Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.2.1 states: The degree of reliability of the power sources required for safe shutdown is considered very high due to independence and ample redundancy; it equals or exceeds all the requirements of Criterion 17. General Design Criterion 17 states: Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit... Contrary to this General Design Criterion 17 requirement, a fault on the main transformer or its high voltage connection to the transmission system could cause coincident loss of electric power from both the main generator and the offsite power supply to Division III. The protective relaying on the main transformer and its output circuit is designed to initiate tripping of the main generator and isolation of the area of the fault without causing any cascading failures. However, the 127N undervoltage relay for the Division III 4160 V switchgear would also respond spuriously to the momentary voltage dip caused by the fault and cause loss of the offsite power supply to Division III. Transmission system bus protective relays: Grand Gulf Updated Final Safety Analysis Report Section 8.2, Offsite Power System, Subsection 8.2.2.1, Availability Considerations states: Short circuits on a section of a bus are isolated without interrupting service to any circuit other than that connected to the faulty bus section. Contrary to this requirement, the instantaneous setting of the 127N relays would not coordinate with the transmission bus protective relays and would react to the momentary voltage dip caused by a transmission system bus fault, resulting also in spurious loss of the offsite power supply to Division III. Loss of Voltage Relays: In addition to the 127N undervoltage relays, Division III high pressure core spray 4160 V switchgear 17AC is equipped with 127S1, S2, S3, and S4 loss of voltage relays and 127 1A, 1B, 2A, and 2B degraded voltage relays, which also trip the offsite power supply to 17AC upon actuation. NRC Regulatory Issue Summary 2011-12, Adequacy of Station Electric Distribution System Voltages, Revision 1, describes one of the functions of the degraded voltage relay time delay as follows: The time delay shall override the effect of expected short duration grid disturbances, preserving availability of the offsite power source(s). The same principle is relevant to the other undervoltage relays that automatically trip the switchgear offsite power supply. This conclusion is consistent with Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.2.3, which states: Protective devices of Class 1E systems, particularly the ECCS, are set to maintain continuity of power as long as possible short of causing a derangement of the equipment. However, the 127N undervoltage relays do not preserve availability of power as long as possible in the event of harmless transmission grid voltage transients, such as those caused by lightning strikes and normally-cleared faults on transmission lines, because their instantaneous setting miscoordinates with the time delay setting of the Technical Specification credited loss of voltage relays 127S1, S2, S3, and S4. According to Technical Specification Table TR 3.3.8.1-1, the 127S1, S2, S3, and S4 loss of voltage relays have a time delay setting of 2.3 seconds. According to Section 6.17 of calculation JC-Q1P81-90027, Division III Loss of Bus Voltage Setpoint Validation (T/S 3.3.8.1), Revision 2, Spurious segregation from the offsite source is prevented by the time delay function. However, since the non- Technical Specification 127N relays react instantaneously to trip the offsite power source during momentary voltage dips, their 0-second time delay setting invalidates this credited design function of the 2.3-second time delay of the 127S1, S2, S3, and S4 loss of voltage relays. Therefore, spurious segregation from the offsite source is not prevented, and a vulnerability exists for unnecessary loss of offsite power events initiated by, and subsequent to, harmless voltage transients from the transmission system. An actual event of this type occurred on April 2, 2012, as described in Licensee Event Report 2012-003. A lightning strike on a 500 kV transmission circuit resulted in actuation of the instantaneous 127N relay and unnecessary loss of the offsite power supply to the Division III electrical distribution system. Switchgear 17AC offsite power supply circuit breaker overcurrent relays: Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.4.2.5.3, HPCS Class 1E Electrical Equipment Circuit Protection states: Emphasis is given in preserving function and limiting loss of Class 1E equipment function in situations of power loss and equipment failure. Contrary to this statement, the instantaneous setting of the 127N undervoltage relays prevents the offsite power supply circuit breaker overcurrent relays from preserving function and limiting loss of Class 1E equipment function in the event of a switchgear bus fault. Switchgear 17AC offsite power supply circuit breakers are equipped with 151B overcurrent relays that, when actuated, trip and lockout the switchgear supply breakers. The purpose of the lockout function is to prevent attempted reenergization of a faulted bus. However, due to the instantaneous response time of the 127N undervoltage relays, the fault would be cleared and the bus deenergized on the undervoltage signal before the overcurrent relays could respond and initiate the bus lockout signal. This would result in automatic starting of the Division III diesel generator, closure of the diesel generator output breaker onto the faulted bus, and the potential for damage to the diesel generator and further damage to the switchgear. Switchgear 17AC feeder circuit breaker overcurrent relays: The circuit breakers for feeders downstream of switchgear 17AC are equipped with 150/151M and 150/151T overcurrent relays that are designed to isolate downstream faults locally. Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.2.3, Control Power and Circuit Protection states: A complete analysis of the application and coordination of the protective devices on Class 1E distribution has been conducted. This analysis shows that under design operation of these devices, faults, and undervoltages will be detected and corrected at the lowest level of distribution. Referring to the 150/151M and 150/151T overcurrent relays, Grand Gulf Updated Final Safety Analysis Report Section 8.3.1.1.4.2.5.3 states: Relay settings are coordinated in such a way that interference of service is not communicated to a higher level involving equipment other than that immediately affected by the fault or overload. Contrary to these requirements, the licensee failed to perform a coordination analysis or to ensure that interference of electrical service is limited as described. The voltage dip caused by a fault on a 4160 V circuit downstream of switchgear 17AC would be detected by the 127N relay, which would react instantaneously to trip the 17AC switchgear offsite power supply circuit breaker rather than isolating the fault locally at the downstream circuit breaker. This is contrary to the design criterion that the fault be detected and corrected at the lowest level of distribution and maintain continuity of power to the switchgear. These issues were entered into the licensees corrective action program as Condition Report CR-GGN-2015-4973.
05000416/FIN-2017002-01	Grand Gulf	30 June 2017 23:59:59	Failure to Establish an Appropriate Preventative Maintenance Procedure for the HPCS Jockey Pump	Green . The inspectors reviewed a self -revealed, non- cited violation of Technical Specification 5.4.1.a, for the licensees failure to establish appropriate procedural instructions for performing preventative maintenance on the high pressure core spray jockey pump. Specifically, on January 27, 2017, the high pressure core spray jockey pump failed because the licensee did not establish a preventative maintenance procedure that prescribes oil analysis and additional performance trending for the high pressure core spray jockey pump every 6 months consistent with the licensees preventative maintenance strategy template. On January 29, 2017, the licensee completed repairs and returned the high pressure core spray jockey pump and high pressure core spray system to operable status . The licensee has also incorporated oil analysis and performance trending into the preventative maintenance for jockey pumps. This issue has been entered into the licensees corrective action program as Condition Report CR -GGN -2017- 0917. The failure to establish appropriate preventative maintenance instructions for the high pressure core spray jockey pump was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to establish appropriate preventative and predictive maintenance work instructions resulted in the unplanned inoperability and unavailability of the high pressure core spray system. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At -Power, dated June 19, 2012, and Inspection Manual Chapter 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that the finding resulted in a loss of system and/or function; therefore, a detailed risk evaluation was performed. A senior reactor analyst performed a detailed risk evaluation in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power. The NRC determined that the increase in core damage frequency for internal initiators was 1.59 E-7/year, and a bounding analysis of external initiators indicated that these events would not result in a 3 change in the color of the finding. Therefore, this finding is of very low safety significance (Green). The analyst also determined that an estimation of large early release frequency (LERF) was required. The result was an increase in LERF of 3.19E -8/year, which is of very low safety significance for LERF (Green). This finding had a cross -cutting aspect in the area of human performance associated with consistent process because the licensee did not use a consistent, systematic approach to make decisions. Specifically, the licensee did not use a consistent approach in developing a preventative maintenance strategy for the high pressure core spray jockey pump by utilizing the approved preventative maintenance strategy template (H.13).
05000416/FIN-2018001-05	Grand Gulf	31 March 2018 23:59:59	Licensee-Identified Violation	10 CFR 50.72(b)(3)(v)(D) requires the licensee to report an event or condition that could have prevented fulfillment of a safety function (accident mitigation).Contrary to the above, from February 18, 2018, until February 23, 2018, Grand Gulf Nuclear Station failed to make a timely event report for an event or condition that could have prevented fulfillment of a safety function (accident mitigation). Specifically, Grand Gulf Nuclear Station experienced the concurrent inoperability of the division 2 diesel generator and the high pressure core spray diesel generator. Per Technical Specification Bases 3.8.1.E.1, there are insufficient standby ac sources available in this condition to power the minimum required engineered safety feature functions.Significance/Severity Level: In accordance with NRC Enforcement Policy, Section 6.9.d.9, the failure to make a report required by 10 CFR 50.72 is a Severity Level IV violation.Corrective Action Reference(s): The licensee entered the failure to make a timely report into the corrective action program as CR-GGN-2018-1595.
05000416/FIN-2018002-02	Grand Gulf	30 June 2018 23:59:59	Failure to Follow ASME Requirements for Maintaining Inservice Inspection (ISI) Cycles and Perform ASME Required Inservice Inspections within the Scheduled ISI Cycle	The inspector identified 15 examples of a Green non-cited violation (NCV)of 10 CFR 50.55(a)(g)(4)(ii), which requires that inservice examination of components classified as American Society of Mechanical Engineers (ASME), Section XI, Code Class 1, Class 2, and Class 3 be conducted during successive 120-month inspection intervals, and requires compliance with the requirements of the latest edition and addenda of the ASME Code (and all its paragraphs) applicable to the specific interval, including maintaining the 120-month inspection interval in accordance with the ASME Code, Section XI, Paragraph IWA-2430. Specifically, the licensee inappropriately adjusted its second inservice inspection 120-month cycle, and failed to perform VT-3 and MT examinations of 15 class 1, class 2, and class 3 components, including the high pressure core spray pump attachment weld and reinforcing band before the third inservice inspection cycle expired on November 30, 2017, as required by 10CFR50.55(a)(g)(4)(ii).
05000416/LER-1986-029, Forwards Standby Svc Water & HPCS Sys Design Review - Summary Rept,Per LER 86-029 & 870204 Enforcement Conference. Sys Presently Capable of Performing Safety Functions & Util Programs Adequate to Retain Capability	Grand Gulf	8 May 1987	Forwards Standby Svc Water & HPCS Sys Design Review - Summary Rept,Per LER 86-029 & 870204 Enforcement Conference. Sys Presently Capable of Performing Safety Functions & Util Programs Adequate to Retain Capability
05000416/LER-1987-006, Corrected LER 87-006-00:on 870501,isolation Valve in Steam Supply Piping to RCIC Sys Turbine Inadvertently Isolated. Caused by Personnel Error.Personnel Counseled	Grand Gulf	29 May 1987	Corrected LER 87-006-00:on 870501,isolation Valve in Steam Supply Piping to RCIC Sys Turbine Inadvertently Isolated. Caused by Personnel Error.Personnel Counseled
05000416/LER-1993-003	Grand Gulf	12 August 1993	LER 93-003-01:on 930324,SSW C Sys Pump Motor Failed Due to Movement of Motor Stator End Windings During Motor star-ups.SSW C Pump Replaced & Failed Motor Refurbished by GE & Being receipt-inspected.W/930812 Ltr
05000416/LER-1993-006	Grand Gulf	20 August 1993	LER 93-006-00:on 930720 & 21,annunciator,specifying High Temp in RHR Sys Equipment Room Received in Cr,Causing RCIC Sys Isolation.Caused by Failure of Equipment Room Differential Temp Switch.Switch replaced.W/930820 Ltr
05000416/LER-1996-002, Forwards LER 96-002-00 Re Routine Maint Rendering HPCS EDG Inoperable	Grand Gulf	26 February 1996	Forwards LER 96-002-00 Re Routine Maint Rendering HPCS EDG Inoperable
05000416/LER-2003-001	Grand Gulf Nuclear Station, Unit I			On January 30, 2003, at approximately 10:54 a.m., Grand Gulf Nuclear Station was operating at 100 percent power when operators inserted a manual reactor scram. The manual scram was initiated due to decreasing reactor water level resulting from a loss of feedwater. The loss of feedwater was caused by isolation of the condensate demineralizers due to shorting of a conductor which tripped the common power supply for the position indication limit switches for the demineralizers valves. The loss of the inlet valve's position indication caused all operating demineralizer outlet valves to close. High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) auto initiated and injected into the reactor vessel to restore level. In response to the HPCS initiation the Division 3 Emergency Diesel Generator auto started but was not needed to supply the Division 3 Buss. As designed, Standby Service Water system loops "A" and "C" started, for required support of equipment.
05000416/LER-2003-002	Grand Gulf		Reactor Scram Due to a Partial. Loss of Offsite Power -	GGNS automatically scrammed at approximately 0948 CDST on 4/2412003 due to a partial loss of offsite power. At the time of the scram, there was a severe thunderstorm in the vicinity. High winds apparently resulted In closure of an open disconnect in the GGNS Switchyard which In turn led to the partial loss of offsite power. During the event the Reactor Protection System (RPS) auto-actuated; High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) auto-initiated on Reactor (Rx) Water Level 2 and injected into the Rx to restore Rx water level; Division 2 and 3 Diesel Generators (DGs) started and energized the 16AB and 17AC Electrical Buses, respectively; the 15AA Electrical Bus lost power and was re-energized by the Division I DG shortly after the initial event; all Standby Service Water (SSW) divisions started; all main steam line isolation valves (MSIVs) isolated on loss of power, and containment isolation occurred. Rx water level and pressure were restored and stabilized. Plant data was reviewed to confirm proper response of plant equipment. Switchyard inspections were conducted to assess damage and verify equipment condition prior to restoring tripped equipment. The NRC Resident Inspector was notified. NRC call-in per 10CFR50.72(b)(2)(iv) and 10CFR50.72(b)(3)(iv) was made at 1320 CDST. MC FORM 566 17.2001) .i.1..LLL NRC FORM 366 � U.S. NUCLEAR REGULATORY (7-2e0t) � COMMISSION ' (See reverse for required reenter of digitsrch.sracters tor each bilXix) - APPROVED BY OMB NO. 3150-0104 � EXPIRES 7414004 Estimated burden per response to comp)/ with atLs mandatory Information cabochon request. 50 hours. � Reported lemons learned ere Incorporated Into the licensing ad led back lo Industry. Send commeres � - � bunion estimate 10 the f=erg Branch (T-6 ESL U.S. Nuclear � IA3 � COMMSSial. Vitisringion. DC = Or by interne! a-mail to NE( � 10202 � and to the Desk Wear, Mee of Interrarticri and Regday Affairs, 08- � 150-0104). Office Of Management and Washing's:4 DC '..M.. It a rneare � to Impose Inforrnakes oreredion does riot � a currently rad OMB control number. the NRC rrsay not conduct or sponsor, and a person Is not rewired to respond to. the Information caged:Eon.
05000416/LER-2005-001	Grand Gulf	11 February 2005		On February 11, 2005 at 1959, Grand Gulf experienced an automatic reactor scram as a result of breaker 552-1105 tripping due to a ground fault on the 34.5 kV bus work of Service Transformer ST11. Loss of ST11 resulted in the loss of power to 12HE, 13AD and 15AA buses. Emergency Diesel Generator (EDG) 11 started on a loss of power and connected to the 15AA bus. All control rods inserted to 00 position. Reactor vessel water level dropped to approximately minus 75 inches on wide range level instrumentation before the High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) systems, initiated at Reactor Vessel Water Level - Low Low, Level 2 (minus 41.6 inches), and restored level to the normal operating band. Concurrent with this event, EDG 13 (Division III) started on Reactor Vessel Water Level - Low Low, Level 2. Standby Service Water (SSW) started to support EDG operation. Containment isolation occurred as a result of Reactor Vessel Water Level - Low Low, Level 2. The affected bus was lined up to other available power sources. The safety related bus was synchronized back to the grid and the EDGs were secured. Normal feedwater level control was established and both HPCS and RCIC were secured.
05000416/LER-2005-002		27 April 2005	Incorrect Assumption Used In Development Of Air Operated Valve Proaram	On April 28 and 29, 2005 Grand Gulf Nuclear Station made eight hour non-emergency calls (EN#s 41645 and 41650) to the NRC pursuant to 10 CFR 50.72(b)(3)(v)(D), Accident Mitigation. The calls were the result of discovery that original assumptions used in development of the Air Operated Valve (AOV) program did not consider instantaneous loss of the non safety related Instrument Air system. Failure to include loss of Instrument Air in the original assumptions produced negative margin for secondary containment isolation valve (SCIV) closure under some postulated accident conditions. All of the affected valves are flex wedge gate valves equipped with double acting Ralph A. Hiller Company actuators. It was determined that the actuator mounted accumulators would not provide sufficient air pressure to ensure positive closure of these SCIVs against postulated maximum expected differential pressure (MEDP) concurrent with loss of the Instrument Air system. A detailed review of all AOV primary and secondary containment isolation valves equipped with Ralph A. Hiller actuators was performed. The majority of the valves were determined to be operable or operable but degraded. The small number of valves that were determined to be inoperable were placed in their Technical Specification required closed position.
05000416/LER-2007-002	Docket Number	19 May 2007	Reactor SCRAM due to Turbine Trip caused by Loss of Condenser Vacuum	On May 19, 2007 at 1127, a Reactor SCRAM from 78% Core Thermal Power (CTP) occurred due to a Main Turbine trip on low Condenser vacuum. Reactor power had been lowered from 100% to 78%, per Loss of Condenser Vacuum Off-Normal-Event Procedure (ONEP), just prior to the automatic actuation of the Reactor Protection System (RPS). Failure of a High Pressure (HP) Condenser expansion joint resulted in degrading Condenser vacuum and subsequent turbine trip over an approximately three minute period. Pressure control was initially maintained with Turbine Bypass Control valves until vacuum decreased to the point that bypass was no longer available. Then Reactor pressure was controlled using a Safety Relief Valve (SRV). Reactor water level continued to be maintained with Condensate system. This report is being submitted pursuant to 10CFR50.73(a)(2)(iv)(A). The cause of the event was the failure of the HP Condenser expansion joint between the Main Turbine and Condenser. Failure of the expansion joint resulted in low condenser vacuum. All Control Rods inserted fully and Reactor level did not decrease below the automatic Emergency Core Cooling System (ECCS) actuation set point (Level 2, -41.6 inches). The Reactor vessel level 3 isolation setpoint of + 11.4 inches was reached for Shutdown Cooling which was already isolated. The expansion joint was replaced to correct the condition.
05000416/LER-2008-003		10 April 2008	Increased Buss Voltages Results in Breaker Trip on Over Current of a High Pressure Core Spray Pump Low Flow Valve Resulting in Non-Compliance with Technical Specification 3.6.1.3, Primary Containment Isolation Valve Function	On March 05, 2008 at 1619, Technical Specification Emergency Core Spray System (ECCS) surveillance testing was being performed of the High Pressure Core Spray (HPCS) pump and system. During the testing, the HPCS low flow valve 1E22-F012 (also a primary containment isolation valve), while stroking from closed to open position, de-energized and the HPCS loss or overload status light energized. The valve was found in the non-closed position and the power supply breaker for the motor actuator for the valve was found tripped open. This condition is considered a violation of Technical Specification 3.6.1.3 Primary Containment Isolation Valve (PCIV) due to exceeding the LCO Required Action Completion Time of four hours to isolate the penetration. The cause of valve 1E22-F012 to fail to close is due to its supply breaker instantaneous over current trip settings being set too low, thus rendering the valve inoperable. Investigation revealed that this condition had existed since the early 1990s when buss voltages had been increased to a higher value to account for under voltage events. Corrective actions were implemented which included replacement of the valve 1E22-F012 power supply breaker and increasing the instantaneous over current trip settings. Breaker settings for the other ECCS motor operator valves that were susceptible to this condition were checked and found to be acceptable.
05000416/LER-2011-001	Grand Gulf	19 March 2011	High Pressure Core Spray (HPCS) Failure Due To Failed Test Equip ent	On March 19, 2011 at 2236, with the plant operating at 96 percent power, the high pressure core spray (HPCS) pump was declared inoperable following the discovery of a degraded breaker that supplied power to the HPCS Minimum Flow Valve. The cause of the degraded breaker was the breaker's instantaneous overcurrent trip setpoint found out of tolerance during testing. The investigation of this event determined that the cause of the degradation was the result of a loss of power to a current calibrator installed for the performance of the HPCS System Flow Rate Low (Bypass) Functional Test. The loss of power caused repeated cycling of the valve and the resulting surge currents created excessive heat in the circuit breaker instantaneous trip and overload circuits. This degraded the instantaneous overcurrent trip setpoint which resulted in the breaker tripping at a setpoint that was out of tolerance. The breaker was replaced and the HPCS system was restored to its standby condition on March 20, 2011 at 0700. The functional test procedure was updated to require either new batteries to be utilized or the test equipment to be used with AC power. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(D) as the loss of a system needed to mitigate the consequences of an accident. No other safety-related systems were out of service during the time that the HPCS system was inoperable. This event was of minimal significance with respect to the health and safety of the public.
05000416/LER-2012-001	Grand Gulf	19 November 2009	Surveillance Test Procedure Inadequate to meet the requirements of Technical Specifications.	On November 19, 2009 Grand Gulf Nuclear Station (GGNS) failed to ensure that Technical Specification (TS) Surveillance Requirement (SR) 3.5.3.1 was met. The 2009 NRC Problem Identification and Resolution (Pl&R) Inspection identified a concern that there was no basis (calculation) for the two-minute venting criterion and that there was no visual means of confirming water flow through the vent line when performing venting of the Reactor Core Isolation Cooling (RCIC) system. In 2009, during review of the NRC concern, GGNS determined that the acceptance criteria of SR 3.5.3.1 was met, and that the RCIC system had successfully completed the required surveillance testing. However, as an enhancement, GGNS revised the verification procedures to require an ultrasonic test (UT) examination and commenced the engineering change process to install a permanent sightglass for the vent line. During the 2011 PISA Inspection, a review of a previous 2009 PI&R Inspection violation determined that the acceptance criteria to satisfy TS (SR) 3.5.3.1 was inadequate which resulted in the RCIC system being inoperable for a period of time in excess of TS allowances which resulted in a condition prohibited by TS. GGNS confirmed full compliance with TS SR 3.5.3.1 by performing UT testing on February 5, 2010 which verified the piping was full of water. Because GGNS considered SR 3.5.3.1 to still be met in 2009, SR 3.0.3 was not applied at the time it was discovered that the surveillance procedure may not be adequate.
05000416/LER-2012-003	Grand Gulf	2 April 2012	ESF Actuation Due to Division III Bus Undervoltage following a Lightning Strike	On 4/2/12 at 1511 hours Central Daylight Time (CDT), Grand Gulf Nuclear Generating Station (GGNS) was in Mode 5 when a valid Engineered Safety Feature (ESF) actuation for emergency Alternating Current (AC) power to Division III 4160 Volt bus occurred due to degraded voltage. One of the two 500 (kilovolt) kV offsite feeder breakers tripped causing a drop in grid voltage which resulted in a trip of the ESF feeder breaker for Division III 4160 V bus. The High Pressure Core Spray (HPCS) Diesel Generator automatically started and energized the bus. The HPCS system was not running and no Emergency Core Cooling System (ECCS) initiation occurred during this event. Divisions I and II ESF power monitoring instrumentation responded to the grid voltage transient but no actuation setpoints were reached. Division I and II ESF 4160 Volt buses remained energized and shutdown cooling remained in service. The Technical Specifications required offsite power sources remained operable and in service during this event. The 500kV feeder that tripped was restored by the dispatcher at approximately 1515 CDT. The Division III bus was subsequently transferred back to offsite power and the HPCS Diesel Generator was secured.
05000416/LER-2013-006	Grand Gulf	17 December 2013	Primary Containment Inoperable Due to an Inadequate Surveillance Procedure Resulting in a Loss of Safety Function	On December 17, 2013, at 1322 central standard time (CST) with the plant operating in Mode 1 at 100 percent thermal power, Grand Gulf Nuclear Station (GGNS) personnel utilized a procedure that was improperly revised. The event was identified at approximately 1415 CST during the performance of the surveillance when valve E51F063, RCIC Steam Line Drywell Inboard Isolation was observed to close when a test signal was applied. This was not an expected condition, the surveillance was halted and corrective actions were commenced. The improperly revised procedure resulted in the inoperability of primary containment, a loss of safety function for primary containment and the inoperability of the Reactor Core Isolation Cooling (RCIC) system. Primary containment operability was restored at approximately 1437 CST when the breaker was closed to energize valve E51F064, RCIC Steam Line Drywell Outboard Isolation which restored the penetration to an operable status. RCIC was Inoperable at 1415 CST and restored to an operable condition at approximately 1435 CST when valve E51F063 was reenergized and opened. The direct cause of the event was an improper procedure revision that resulted in an inadequate procedure. The procedure was revised to be technically adequate and an extent of condition review was performed for the affected procedure writer's work. There were no adverse effects on the health or safety of the public as a result of the event.
05000416/LER-2016-007	Grand Gulf	8 September 2016	Technical Specification Shutdown due to Loss of Residual Heat Removal Pump	On September 4, 2016 at 02:58, Grand Gulf Nuclear Station entered three TS LCO Action Statements because RHR 'A' pump was declared inoperable. LCO Actions entered: 1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem. All have 7 day Completion Times A decision was made to shutdown the plant to repair the RHR 'A' pump because, based on the troubleshooting and testing plan, the pump could not be repaired and returned to service within the LCO Completion Times. At 0300 CDT on 09/08/16, GGNS initiated the transition to Mode 4. The pump was removed from service and sent to the vendor facility for decontamination, disassembly and failure analysis. The 'A' pump was then replaced and tested satisfactorily. RHR 'A' was returned to operable. APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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 internet e-mail to Intocollects.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 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 PLANT CONDITIONS PRIOR TO THE EVENT 3 DESCRIPTION 4 REPORTABILITY 5 CAUSE 6 NRC FORM 7 CONTINUATION SHEET 8 EXTENT OF CONDITION 9 CORRECTIVE ACTIONS 10 SAFETY SIGNIFICANCE 11 PREVIOUS SIMILAR EVENTS CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 PLANT CONDITIONS PRIOR TO THE EVENT At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1, at 100% rated thermal power. All systems, structures and components, with the exception of the RHR 'A' pump, that were necessary to mitigate, reduce the consequences of, or limit the safety implications of the event were available. No other safety significant components were out of service. DESCRIPTION On September 4, 2016, GGNS was performing a Residual Heat Removal (RHR) 'A' quarterly Technical Specification (TS) Surveillance Requirement (SR). At 02:58, The RHR pump failed to meet its TS SR Acceptance Criteria for flow and differential pressure (d/p) and was therefore declared Inoperable. Action Statements for TS Limiting Conditions for Operation (LCOs) 3.5.1, 3.6.1.7 and 3.6.2.3 were entered, each having Completion Times of 7 days. LCO Action Statements entered: 1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem. Initial troubleshooting verified that the pump was incapable of meeting the flow requirement of 7756 gpm and d/p of 131 psid simultaneously. The observed pump flow and discharge pressures were verified to be correct via a temporarily installed ultrasonic flow meter and pressure gauge. RHR system valves and lines were verified not to be clogged or leaking. The pump motor was confirmed to be operating at the proper speed. Further troubleshooting and testing lead station management to the conclusion that RHR 'A' would not be returned to operable status within the 7 day Completion Time. A decision was made to commence an orderly shutdown. On September 8, 2016 at 0300, GGNS began the transition to Mode 4. No other systems were out of service that would have complicated an orderly shutdown to Mode 4. REPORTABILITY Event Notification No. 52225 was made to the U.S. Nuclear Regulatory Commission (NRC) Operations Center. This LER is being submitted pursuant to Title 10 Code of Federal Regulations 10 CFR 50.73(a)(2)(i)(A) for the completion of any nuclear plant shutdown required by the plant's Technical Specifications. Telephonic notification was made to the NRC Emergency Notification System on September 8, 2016, at 03:27, pursuant to 10 CFR 50.72(b)(2)(i) for the initiation of any nuclear plant shutdown required by the plant's Technical Specifications. CAUSE Direct Cause: The RHR 'A' pump was unable to provide its required flow at the required differential pressure in order to perform its safety function. APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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 internet 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 NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET Grand Gulf Nuclear Station, Unit 1 05000 416 Apparent Cause: Subsequent investigation suggests internal pump degradation but the Apparent Cause is ongoing. A supplemental report to this LER will be provided when the Apparent Cause investigation is complete. EXTENT OF CONDITION Quarterly surveillance data of similar Emergency Core Cooling System (ECCS) pumps showed no evidence of degradation. Data was re-examined from the following pumps: Low Pressure Core Spray (LPCS), High Pressure Core Spray (HPCS) and RHR 'B' and 'C.' GGNS also performed a partial quarterly surveillance on the RHR 'B' which was completed satisfactorily. CORRECTIVE ACTIONS The RHR 'A' pump was replaced and retested satisfactorily. The pump removed from service has been sent to the vendor facility for failure analysis. SAFETY SIGNIFICANCE The event posed no threat to the health and safety of the general public or to nuclear safety as safety- systems performed as designed. No Technical Specification safety limits were violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event. PREVIOUS SIMILAR EVENTS Previous similar events. will be discussed in the supplemental report upon completion of the Apparent Cause investigation.
05000416/LER-2017-001	Grand Gulf	27 January 2017 28 March 2017	High Pressure Core Spray (HPCS) Jockey Pump Trip LER 17-001-00 for Grand Gulf, Unit 1, Regarding High Pressure Core Spray Jockey Pump Trip	At 1808 hours on 1/27/17, Grand Gulf Nuclear Station entered into LCO 3.5.1.6 when the High Pressure Core Spray (HPCS) Jockey Pump (Component Function Identifier- P) failed and the HPCS System was declared inoperable. The Reactor Core Isolation Cooling (RCIC) System was verified operable and investigation into the cause was initiated. Under those plant conditions the Plant Technical Specifications action to restore the HPCS System to operable status allows a 14 day completion time. No other safety systems were inoperable at the time of this event. The decision was made to disassemble the HPCS Jockey Pump and rebuild the pump using parts from the warehouse which was completed on 1/29/17. The pump was tested to demonstrate functionality of the pump on 1/29/17 and the system was returned to service.
05000416/LER-2017-004	Grand Gulf	26 May 2017	Outside-of-Tech-Spec-Allowable-Value Automatic Depressurization System Initiation Timer Relay due to Inadequate Procedures	On May 26, 2017, while performing the Automatic Depressurization System (ADS) quarterly surveillance, the time delay on the Trip System A (Division 1) ADS initiation timer relay was found outside of its Technical Specification (TS) Allowable Value of 5 115 seconds. Specifically, the ADS timer requirements in TS 3.3.5.1, Emergency Core Cooling System Instrumentation, Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation, Function 4, Sub-function c. ADS Initiation Timer, Allowable Value was not met. The cause was determined to be inadequate preventive maintenance and review of the previous test results. This event is reportable as a license event report (LER) in accordance with 10CFR50.73(a)(2)(i)(B), as a "condition prohibited by Technical Specifications" because the same relay failed its previous test and could not be considered as OPERABLE during the full interval between tests. Corrective actions included replacement of the defective timer relay and planned actions to replace the corresponding timer relays in ADS and the Feedwater Control System. In addition, the applicable preventive maintenance procedures were revised. The event posed no threat to the health and safety of the general public or to nuclear safety as ADS would have performed as designed. No Technical Specification safety limits were challenged or violated. APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 366A U.S. NUCLEAR REGULATORY COMMISSION NRC FORM (4-2017) ..* ‘‘ Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to 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. (See NUREG-1022, R.3 for instruction and guidance for completing this form httplAwm.nrc.00vireadino-rm/doc-collections/nureas/staff/sr1022/r3/) 05000 416 Contents 1 DESCRIPTION 2 REPORTABILITY 3 CONTINUATION SHEET 4 CAUSE 5 CORRECTIVE ACTIONS 6 SAFETY SIGNIFICANCE 7 PREVIOUS SIMILAR OCCURRENCES DESCRIPTION On May 26, 2017, while performing Automatic Depressurization System (ADS) (AD)(C23) quarterly surveillance, the time delay on the Trip System A ADS initiation timer relay (RLY2) was found outside of its Technical Specification (TS) Allowable Value of 115 seconds. Specifically, the ADS timer requirements that are specified in Technical Specifications 3.3.5.1, Emergency Core Cooling System (ECCS) Instrumentation, Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation, Function 4, Sub-function c. ADS Initiation Timer, Allowable Value were not met. The failure mechanism is degradation of the timing function in the ADS initiation timer relay (Agastat Model TR14D3EC750) that delays initiation of ADS in order to allow time for high pressure injection to restore reactor water level. The TS Allowable Value for this timer is less than or equal to 115 seconds. The as found value was beyond this value. This surveillance is performed on a quarterly basis. This same condition was found during the last surveillance performed on February 23, 2017. This condition was not found during the surveillance performed prior to that on November 18, 2016. The Automatic Depressurization System is required in Modes 1, 2, and 3 with the reactor above 150 psig. Between November 18, 2016 and January 30, 2017, the plant was in Mode 4. Therefore this function was not required from November 18, 2016 to January 30, 2017, which is when the reactor reached 150 psig in Mode 2. The ADS was required to be Operable from January 30, 2017, until May 26, 2017. ADS initiation is accomplished by energization of either the Trip System A (Division 1) or Trip System B (Division 2) solenoids (FSW) associated with each of the ADS valves. The logic for each Trip System is separate and either trip system will cause all the ADS relief valves to open. Therefore, the automatic safety function would still be accomplished within the allowable time provided that the Trip System B was Operable. Trip System B initiation logic was taken out of service on March 10, 2017, to support performance of the quarterly ADS channel calibration surveillance procedure. An additional review was performed to determine if the Trip System A logic would have initiated within the allowable time during the period when the Trip System B logic was out of service. The average rate of change of the setpoint between surveillances was 0.402 seconds/day for the first interval (November 18, 2016 - February 23, 2017) and 0.424 seconds/day for the second interval (February 23, 2017 - May 26, 2017). Use of the larger rate of change is conservative, and therefore a rate of 0.424 seconds/day was assumed for the second interval. Linearly extrapolating from an as left condition of 104 seconds on February 23, 2017, it is concluded that the setpoint would have been approximately 110.4 seconds on March 10, 2017. This value is within the 115 second TS AV. Therefore, it is concluded that no loss of safety function occurred for this condition. REPORTABILITY This event is reportable as a license event report (LER) in accordance with NUREG-1022, Section 3.2.2, and 10CFR50.73(a)(2)(i)(B), as a "condition prohibited by Technical Specifications" because the same relay failed its previous test and could not have been considered operable for the full interval between tests. The timer relay would have been considered inoperable for a time period such that the Technical Specification 3.3.5.1 completion time would not have been met. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (6-2016) CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form + a httplAvwt.v.nrc.covireadinci-rm/doc-collections/nureqs/staff/sr1022/r3I) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Information Services Branch (T- 2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555.0001, or by e-mail to InTocollects.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. 05000 416 CAUSE The direct cause of the failure is the degradation of timing function for ADS initiation timer relay 1B21-K5A, most likely due to the electrolytic capacitor degradation. The cause of the failure was an inadequate preventive maintenance task and inadequate procedural guidance. The procedures did not require periodic replacement of the relay nor did they require an engineering review of the test results. CORRECTIVE ACTIONS Immediate: The defective timer relay in Trip System A was replaced. Completed: Preventive maintenance tasks were revised to require periodic replacement of the relays. Surveillance testing was revised to require timely engineering review of the completed quarterly surveillance tests. Planned: The corresponding relays in ADS and the Feedwater Control System will be replaced. This action has been entered in the corrective action program and may be modified in accordance with that program. SAFETY SIGNIFICANCE Initiation of the ADS is accomplished by energizing either the Trip System A or Trip System B solenoids associated with each of the ADS valves. Each separate trip system will cause all the ADS relief valves to open. Therefore, the automatic safety function would still be accomplished within the allowable time with Trip System A inoperable provided that Trip System B was Operable. Trip System B initiation logic was taken out of service on March 10, 2017, to support performance of the quarterly ADS Channel B calibration surveillance procedure. An additional review was performed to determine if the Trip System A logic would have initiated within the allowable time during the period when the Trip System B logic was out of service. The conclusion was that the "A" setpoint would have been approximately 110.4 seconds on March 10, 2017. This value is within the 115 second TS AV. Therefore, at least one division of ADS was always available to perform the safety function. In addition, manual actuation was available, and operators are trained on the conditions requiring manual actuation and the associated procedures. The ADS acts as a backup to High Pressure Core Spray System (BG) for a small break loss of coolant accident. The High Pressure Core Spray System was not impacted by the degraded condition of ADS. The event posed no threat to the health and safety of the general public or to nuclear safety as ADS would have performed as designed. No Technical Specification safety limits were challenged or violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event. PREVIOUS SIMILAR OCCURRENCES The identified licensee event reports were attributed to inadequate maintenance procedures. The events were reviewed and it has been determined that the causes and corrective actions were sufficiently different that they could not have predicted or prevented the occurrence of this event.
05000440/FIN-2007005-10	Perry	31 December 2007 23:59:59	Adequacy of Reactor Core Isolation Cooling System Surveillance Testing	On November 28, 2007, the inspectors observed licensee actions in response to a scram with complications. The digital feedwater level control system experienced a loss of two power supplies. This caused a loss of feedwater, main turbine trip, and reactor scram due to an erroneous reactor vessel water level 8 signal. The loss of feedwater caused an actual reactor vessel water level 2, which initiated both RCIC and high pressure core spray (HPCS) for reactor vessel water level control. RCIC tripped approximately 13 seconds after initiation due to low suction pressure, and reactor vessel control was maintained using HPCS. The inspectors observed licensee personnel shutdown the plant to Mode 4. A Special Inspection Team was chartered to investigate this event, and the results are documented in IR 05000440/2007010. At the end of the inspection period, the inspectors continued to evaluate the adequacy of RCIC surveillance test procedures. A contributing cause of the November 28, 2007, RCIC failure was determined to be an improperly tuned flow controller. The controller settings were established in January 2006 and the RCIC system had passed routine surveillance testing criteria since that time without identification of the condition. RCIC testing typically relied on a suction and return flow path to the condensate storage tank. On November 28, 2007, RCIC failed to perform as designed when called upon to inject from the suppression pool to the reactor vessel.
05000440/FIN-2007005-11	Perry	31 December 2007 23:59:59	Adequacy of Reactor Core Isolation Cooling System Flow Controller Tuning Procedures	On November 28, 2007, the inspectors observed licensee actions in response to a scram with complications. The digital feedwater level control system experienced a loss of two power supplies. This caused a loss of feedwater, main turbine trip, and reactor scram due to an erroneous reactor vessel water level 8 signal. The loss of feedwater caused an actual reactor vessel water level 2, which initiated both RCIC and high pressure core spray (HPCS) for reactor vessel water level control. RCIC tripped approximately 13 seconds after initiation due to low suction pressure, and reactor vessel control was maintained using HPCS. The inspectors observed licensee personnel shutdown the plant to Mode 4. A Special Inspection Team was chartered to investigate this event, and the results are documented in IR 05000440/2007010. At the end of the inspection period, the inspectors continued to evaluate the adequacy of the RCIC flow controller tuning procedure. A contributing cause of the November 28, 2007, RCIC failure was determined to be an improperly tuned flow controller. Following this failure, the licensee revised the tuning of the RCIC flow controller, tested the new settings, and determined that RCIC was operable on December 10, 2007. On December 12, 2007, the licensee declared RCIC inoperable due to questions over the appropriateness of the flow controller settings and whether the settings provided a sufficiently over-damped response for conditions of RCIC injection to the reactor vessel from the suppression pool. The licensee again revised the RCIC flow controller settings and returned the settings to values associated with successful injection testing to the reactor during baseline pre-startup testing. Following additional testing using the condensate storage tank and further evaluation, the licensee declared RCIC operable again on December 21, 2007.
05000440/FIN-2008004-09	Perry	30 September 2008 23:59:59	Licensee-Identified Violation	10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptable limits contained in applicable design documents. Contrary to this, on July 21, 2007, the licensee failed to test the C Emergency Service Water pump discharge valve for seat leakage following valve replacement. This resulted in high pressure core spray system inoperability and unavailability in May 2008 due to low keep-fill system pressure. Immediate corrective actions included repair of the affected valve. The finding was determined to be of very low safety significance because the system unavailability time was less than three days. (CR 08-40969
05000440/FIN-2009002-06	Perry	31 March 2009 23:59:59	Maintenance on HPCS System resulted in Emergency Operating Procedure Entry	A finding of very low safety significance and associated NCV of Technical Specification Section 5.4.1 was self-revealed on February 3, 2009, when the control room received an unexpected high pressure core spray (HPCS) pump room sump level high alarm and entered Emergency Operating Procedure (EOP) 3, Secondary Containment Control. The licensee did not properly control a maintenance activity on the HPCS system resulting in unexpected water spray in the HPCS pump room. As part of their immediate corrective actions, licensee personnel recovered from the drain down of the system and entered the issue into their corrective action program. This finding was considered more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability. The event challenged shutdown operations as operators entered the EOP and responded to reports of significant water spray entering the pump room. The finding was determined, through an SDP analysis, to be of very low safety significance as no mitigation equipment or functions were affected. The primary cause of this finding was related to the cross-cutting aspect in the area of Human Performance per IMC 0305 H.3(a)because the organization failed to appropriately plan work activities that impact plant structures and systems, and failed to ensure appropriate contingencies were in place to perform a maintenance activity
05000440/FIN-2009003-04	Perry	30 June 2009 23:59:59	Failure to Prevent Contact of Energized Components Renders RCIC System Inoperable	A finding of very low safety significance (Green) and associated non-cited violation of Technical Specification (TS) 5.4.1 was self-revealed when technicians failed to implement actions to prevent shorting of energized electrical components during maintenance. Specifically, during surveillance testing activities, a lifted lead shorted to a test lug causing the reactor core isolation cooling (RCIC) Division 2 logic to trip. The technicians suspended their surveillance procedure and operators restored the RCIC system in accordance with licensee procedures. Operators also verified high pressure core spray (HPCS) was operable. The licensee visually inspected the RCIC system and found no apparent damage. The licensee conducted additional training on the use of error prevention tools and entered the issue into the corrective action program as CR 09 59356.The finding was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the short circuit resulted in the RCIC system being inoperable. The finding was determined to have very low safety significance because it did not represent a loss of system safety function, a loss of safety function of a non-TS train designated as risk-significant for greater than 24 hours, an actual loss of safety function of a single train for greater than its TS-allowed outage time, or screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding has a cross-cutting aspect in the area of human performance per IMC 0305 H.4(a) because the technician failed to use error prevention techniques, such as self-checking, that are commensurate with the risk of the assigned task. Specifically, he did not use \'STAR\' (Stop, Think, Act, Review) during an activity that could render the RCIC system inoperable
05000440/FIN-2017008-01	Perry	31 December 2017 23:59:59	Failure to Address the Susceptibility of the Condensate Storage TankLow Level Instrument Lines to Freeze	The team identified a finding of very-low safety significance (Green) and an associated NCV of Title 10 of the Code of Federal Regulations(CFR),Part 50, Appendix B, Criterion III, Design Control, and 10 CFR 50.63, Loss of All Alternating Current Power, for the licensees failure to evaluate the capability to transfer the high pressure core spray (HPCS)and the reactor core isolation cooling (RCIC) pumps suction source from the condensate storage tank (CST)to the suppression pool during cold weather conditions. Specifically, (1) monitoring of the CST level instrument lines heat tracing was inadequate to detect a credible common mode failure before the instrument lines would freeze and be rendered inoperable during normal operation, (2)the licensee did not address the condensate (CST) level instrument lines susceptibility to freeze during a cold weather loss of off-site power (LOOP) event with or without a design basis transient or accident, and (3)the licensee incorrectly evaluated the capability to transfer the HPCS pump suction source from the CST to the suppression pool during a cold weather station blackout (SBO) event. The licensee captured the issues within their Corrective Action Program (CAP) as Condition Report(CR) CR-2017-08685, CR-2017-08930, and CR-2017-09006. Corrective actions implemented included: increased the CST level instrument line heat tracing circuit monitoring frequency, revised the affected procedures ensured HPCS and RCIC are adequately aligned to the suppression pool during LOOP design basis events, and ensured a timely transfer of the HPCS and RCIC pump suctions to the suppression pool during a SBO. The performance deficiency was determined to be more-than-minor because it was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability,reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.Specifically, the failure of the HPCS and or RCIC pumps to automatically transfer their suction source from the CST to the suppression pool upon reaching a low CST water level condition could damage the pump(s) thus preventing them to be used to mitigate a transient or accident. A detailed risk evaluation was performed and determined that the finding was of very-low safety-significance (Green). The team did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the CST instrument lines were designed and the SBO coping strategy during cold weather was established more than 3 years ago.
05000440/LER-2001-001	Docket Number	29 April 2001		On 4/28/01 at 2101 hours, a main generator field ground annunciator was received due to a Stator Water System leak and actions were taken to remove the main generator from service at 2323 hours. Following generator removal/turbine trip, the main condenser vacuum degraded and was determined non-recoverable. A manual reactor scram was inserted by procedure at 0050 hours, on 4/29/01. Following insertion of the reactor scram, as a result of one turbine steam bypass valve, which stuck one half open for four minutes, invalid Division 2 Emergency Closed Cooling System (ECCS) actuation signals were received on a combination of low sensed level and high pressure signals. Then shortly after MSIV closure at 0249 hours, during the first of a series of manual SRV operations for controlling pressure, an invalid Division 3 ECCS actuation signal was received. Though the signals were invalid, all systems responded as designed to their logic actuation. Also in response to the Division 3 actuation signal, the High Pressure Core Spray System pump was over-ridden off in accordance with plant procedures. Subsequently, the A and B loops of Residual Heat Removal were required by procedure to be placed in suppression pool cooling mode of operation as a result of SRV operations. This resulted in entry into Technical Specification 3.0.3, "Limiting Condition for Operation Applicability. The cause of the loss of vacuum was a process error that resulted in two moisture separator drain tank manways being improperly torqued during the recent refueling outage and becoming unseated when the pressure was reduced in the tank following the turbine removal from service. The cause of the reactor level/pressure actuations was determined to be localized flashing and pressurization of the sensing lines in the affected instrument reference legs. The stator water cooling lines were repaired. The affected manways were re-worked, gaskets repaired and the remaining manways were properly retorqued; RPV level instrument reference legs were filled and vented, and operators were provided with awareness briefings and lessons learned from the event. This event is being reported in accordance with the requirements of 10CFR50.73(a)(2)(iv), as a condition that resulted in multiple specified system actuations, and 10CFR50.73(a)(2)(i)(B), as a condition prohibited by the plant's Technical Specifications.
05000440/LER-2001-003	Docket Number			On 7/11/01, at 2223 hours, the plant was operating at 100 percent reactor power when a loss of feedwater occurred resulting in an automatic reactor scram, an automatic trip of the Reactor Recirculation Pumps, an automatic initiation and injection of the High Pressure Core Spray System (HPCS) and the Reactor Core Isolation Cooling System (RCIC) and a Balance of Plant Isolation due to a valid Reactor Pressure Vessel (RPV) water low level signal. Subsequently, at 0400 on 7/12/01, an invalid low RPV water level signal occurred resulting in an invalid automatic initiation of the HPCS pump, HPCS diesel and associated support systems, however no injection occurred. All systems responses were as expected to the valid and to the invalid signals. The cause of the loss of feedwater event was determined to be a blown fuse that supplies 24-Volt DC electrical power to the Loop B Analog Instrument Panel, which contains instrumentation for the feedwater control system. The cause of the invalid RPV low level actuation was determined to be due to a thermal hydraulic perturbation coincident with decreasing reactor pressure. The power supply fuse was replaced and a thermographic examination was performed of all fuses located in the Control Room. A thermographic examination of the Control Room fuses was again performed following plant restoration at approximately 60 percent power. Although no additional failures were identified, fuses indicating above normal temperatures were replaced. To address the invalid HPCS initiation, the signal dampening for the HPCS RPV level instruments was increased in order to reduce the instrument vulnerability to short duration pulses. This event is being reported in accordance with the requirements of 10CFR50.73(a)(2)(iv), an event or condition that resulted in specified system actuations.
05000440/LER-2001-005	Perry		Automatic RPV Level SCRAM, Specified System Actuations And Inoperability Of The Division 3 Diesel Generator .	On December 15, 2001, at 2228 hours, with the plant operating at 100 percent reactor power, an excessive feedwater demand transient occurred resulting in a high Reactor Pressure Vessel (RPV) water level scram. Following the feedwater pump trip on high RPV level, RPV level decreased causing actuation of High Pressure Core Spray System (HPCS), Reactor Core Isolation Cooling System and containment isolation as designed. A Reactor Protection System (RPS) actuation occurred on low RPV water level at 2304 hours when level inadvertently drifted low. Additionally, the HPCS diesel governor was misadjusted during diesel shutdown resulting in inoperability that was later identified during the review of normal surveillance testing results on December 21, 2001. I The cause of the feedwater transient was determined to be a failed logic card that has since been replaced. The cause of the RPS actuation and the failure to meet Technical Specifications was determined to be operator performance deficiencies. Lessons learned from the event were presented to operators and the HPCS diesel procedure was revised. This event is being reported in accordance with the requirements of 10CFR50.73(a)(2)(iv), an event or condition that resulted in specified system actuations, 10CFR50.73(a)(2)(i)(B), a condition prohibited by Technical Specifications, and also satisfies Perry Plant's Operational Requirements Manual (ORM) section 7.6.2.1, special report for an Emergency Closed Cooling System (ECCS) injection into the RPV. This was the fourteenth HPCS injection to date. The injection nozzle usage factor is less than 0.70, therefore no further data is required by the ORM.
05000440/LER-2002-002	Docket Number		Failure of the High Pressure Core Spray Pump to Start	A 20.2203(a)(2)(v) 50.73(a)(2)(1)(A) X 50.73(a)(2)(v)(D) 20.2203(a)(2)(v) 50.73(a)(2)(i)(B) 50.73(a)(2XvIi) , .t/V:. , .:.. , .,,., -..,"-,!.., '. ,_. ,' . -.... - " t ' 20.2203(a)(2)(vi) 50.73(a)(2)(1)(C) 50.73(a)(2)(viii)(A) 50.73(a)(2)(viii)(B) 20.2203(a)(3)(i) 50.73(aX2)(ii)(A)
05000440/LER-2003-002	Docket Number	14 August 2003	Reactor Scram as a Result of a Loss of Off-site Power	On August 14, 2003, at 1610 hours, with the Perry Nuclear Power Plant operating in Mode 1, at approximately 100 percent reactor power, a generator trip due to under-frequency occurred resulting in a turbine control valve fast closure scram. -The.under-frequency was the result.of a loss of off-site power. The cause of the grid disturbance that resulted in the loss of off-site power is still under investigation by FirstEnergy. The loss of off-site power required entry into the emergency plan for an Unusual Event. Entry into the emergency plan is reportable per 10CFR50.72(a)(1)(i). Additional reporting requirements are documented in the event report. Loss of off-site power to the safety-related emergency power supply busses for greater than 15 minutes resulted in the declaration of an Unusual Event, which was reported to the NRC via the Emergency Notification System (ENS) at 1635 hours. Subsequently, it was recognized that power was not available at the Emergency Operations Facility and the Backup Emergency Operations Facility. This condition was reported to the NRC via the ENS at 2225 hours. The Unusual Event was terminated at 1952 hours on August 15, 2003, following restoration of off-site power. Following restoration of power to the emergency busses with the emergency diesel generators, low pressure alarms were received on low pressure core spray (LPCS) and on residual heat removal (RHR) A loop. Following initial investigation, both LPCS and RHR A were declared inoperable at 1847 hours. The associated water-leg pump was determined to be air bound and was vented. Both LPCS and RHR A were vented prior to returning to service. This report also satisfies Operational Requirements Manual section 7.6.2.1, which requires a special report submittal following an Emergency Core Cooling System actuation and injection into the reactor coolant system.
05000440/LER-2003-003	Docket Number		Unrecognized Diesel Generator Inoperability During Mode Changes	At 1206, August 21, 2003, with the reactor in MODE 1 at approximately 13 percent power, the monthly 'Diesel Generator Start and Load° surveillance was performed and the starting output voltage was discovered to be set at approximately 4534 volts. This value was greater than the Technical Specification acceptance criteria band of 3900 to 4400 volts AC and resulted in the Division 1 diesel generator (DG) being declared inoperable. The conditions initiating this event were traced to the reverse power trip of the Division 1 diesel generator and its output breaker at 1813, August 14, 2003, while restoring the Division 1, Class 1E, 4160 volt AC electrical bus to its offsite power supply. Subsequently, the plant changed MODES two times on 8/20/03 with an inoperable diesel generator. The two MODE changes were made In violation of Technical Specifications, i.e. one at 0150 to MODE 2 at 0 percent power and the second at 2146 to MODE 1 at approximately 8 percent power. This condition is reportable per 10CFR50.73(a)(2)(1)(B). The root causes of this event are a deficient procedure that does not contain a Precaution or Limitation with the diesel generator high voltage limit; failure to reinforce expectations for the review of the operating parameters in the 'System Operations' section of the system operating instructions; and failure of the post-event review process to detect the inoperability of the diesel generator prior to changing the plant Mode.
05000440/LER-2004-001	Docket Number05 22 2004 2004 - 001 -001 09 18 2004	22 May 2004	Emergency Service Water Pump Failure	On May 21, 2004, at 0150 hours with the Perry Nuclear Power Plant operating in MODE 1 at 100 percent power, Emergency Service Water (ESW) pump A was,declared_inoperable due to pump_shaft coupling failure. _At 1600 on __ . May21, 2004, a power reduction was ordered to shutdown the plant to complete repairs. MODE 3 (hot shutdown) was entered at 2139 on May 22, 2004. MODE 4 (cold shutdown) was entered at 0619 on May 23, 2004. Although bypassing of steam to the main condenser was available, an alternate decay heat removal system was not established in MODE 4 within the Technical Specification (TS) 3.4.10 completion time. The failure mechanism of the coupling was stress corrosion cracking (SCC). This was the second occurrence of this type of failure on the same pump in less than one year. Since the ESW pump B could not be physically inspected, an engineering evaluation for the susceptibility of ESW pump B to SCC could not support continued operability. At 1500 on May 24, 2004 ESW pump B was declared inoperable. The stress corrosion cracking failure mode was due to marginal coupling design, insufficient coupling keyway corner radius, and susceptible environmental conditions. The ESW pump B continued to operate until removed from service for inspection and upgrade to a new coupling design. Both A and B ESW pump couplings were replaced with couplings constructed of less susceptible material and additional design margin. This event is considered to be of very low safety significance.
05000440/LER-2005-003	Docket Number		Lack of Suction Flow Path Causes High Pressure Core Spray to be Inoperable	Nuclear Power Plant operating in Mode 1 at 100 per cent power, a review of the High Pressure Core Spray (HPCS) Pump and Valve Operability test instruction revealed that steps in the instruction closed both suction valves and caused a loss of HPCS pump suction flow path without declaring HPCS inoperable. While the valve stroking sequence is appropriate for the system design, the inappropriate action was not declaring the system inoperable. It was also determined that the manual shifting of HPCS suction flow path froin the Suppression Pool (SP) to the Condensate Storage Tank (CST) per the System Operating Instruction (S01) would result in the same condition. Both conditions would only occur for a short (less than 5 minutes) duration during valve timing for the quarterly testing or during manual shifting of the HPCS suction source. The cause of this event was determined to be a long-standing procedure and knowledge deficiency. Since the inoperability was only for a very short duration during actual valve stroking, the increase in risk is very small. The SO1 and the test instruction have been revised to include entry into the required TS LCO. The training program for licensed operators is being revised. This issue is considered to be a condition that could have prevented the fulfillment of a safety function of a system needed to mitigate the consequences of an accident in accordance with 10CFR50.73(a)(2)(v)(D).
05000440/LER-2006-001	Docket Number		Incorrect Wiring in the Remote Shutdown Panel Results in a Fire Protection Program Violation	On January 17, 2006, at about 1000 hours, with the plant operating at 84% power, an internal wiring jumper on a switch in the Remote Shutdown Panel (RSP) was found to be installed incorrectly. The jumper was identified as a result 01 surveillance testing. The switch contact has the function of isolating control room circuitry from the RSP circuitry for the Reactor Core Isolation Cooling (RCIC) turbine exhaust valve. Complete isolation of the control room circuitry for the RCIC valve would not have been established by transferring control switches to the emergency position. Although no actual fire occurred, thiS Was a violation of the fire protection program,-which Is a violation of the Operating License condition 2.C.6. The cause of the event was determined to be a wiring drawing error during manufacture of the panel that resulted in the switch being incorrectly wired. The cause of the wiring error was determined to be a less than adequate vendor drawing review that failed to discover a drawing error on a wiring diagram and less than adequate testing. A contrbuting cause was determined to be less than adequate understanding of fire protection related design functions and testing requirements of the RSP. Completed corrective actions were to rewire the switch correctly and to inform the manufacturer of the drawing and wiring error in the supplied RSP. Additional corrective actions will be to revise the necessary surveillances and the Updated Safety Analysis Report to clarify fire protection program testing requirements and to present lessons learned from this investigation to the Design Engineering Section. This event is reportable as a violation of the Operating License, paragraph 2.C.6, Fire Protection. This event was determined to be of very low safety significance.
05000440/LER-2007-002	Docket Number	11 July 2007	Shutdown Cooling Pump Trip Results in Operation Prohibited by Technical Specifications	On July 11, 2007, at approximately 2313 hours, the Residual Heat Removal pump (RHR) B tripped off. At the time of the event, the plant was in Mode 4 (Cold Shutdown). With RHR B subsystem inoperable, an alternate method of decay heat removal for the RHR B subsystem could not be verified within one hour as required by Technical Specification Limiting Condition for Operation 3.4.10, Required Action A.1. Required Action A.1 was completed on July 12, 2007, at 0559 hours when the tripped RHR B pump was returned to standby. The RHR B pump trip occurred when an Instrument and Control Technician performing Reactor Core Isolation Cooling (RCIC) surveillance testing unnecessarily loosened a wire connection from an electrical terminal, inducing a current from the RCIC circuitry into the electrically independent RHR B trip system. Modifications to separate the wiring and to install noise suppression diodes are being prepared for installation. Personnel actions were taken per the FENOC Performance Management Process. This event was determined to be reportable as an operation or condition prohibited by Technical Specifications, 10CFR50.73(a)(2)(i)B).

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