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	Start date	Reporting criterion	Event description
05000416/LER-2017-007	12 December 2017	10 CFR 50.73(a)(2)(iv)(A), System Actuation	At approximately 0918 hours on Tuesday, December 12, 2017, while operating in MODE 1 at approximately 18 percent power, the Grand Gulf Nuclear Station (GGNS) experienced a loss of the Engineered Safety Features (ESF) Transformer 11 which was powering the Division 1 ESF bus. Subsequently, the station experienced an automatic start of the Division 1 Emergency Diesel Generator and the partial isolation of the primary and secondary containment buildings. Both of these events were expectedand as designed. The direct cause of ESF actuations was the loss of ESF Transformer 11. The cause of the transformer loss is under investigation at this time and this licensee event , report will supplemented upon completion of GGNS's causal analysis. Additionally, GGNS experiented an unrelated isolation of the Reactor Core Isolation Cooling System upon restoration of power. The isolation of the Reactor Core Isolatigh Cooling System did not result in a loss of safety function. The cause of this isolation is under investigation and will be documented in accordance with the.GGNS corrective action program. This event is reportable to the NRC in accordanCe with 10 CFR 50.72(b)(3)(iv) and 10 CFR 50.73(a)(2)(iv)(A) as an event or condition resulting in a valid actuation of a ESF system. Grand Gulf Nuclear Station, Unit 1 05000 416 . NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/3112020 (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 so RkG,„ LICENSEE EVENT REPORT (LER) r F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to y n4 CONTINUATION SHEET Infocollects.Resource@nrc.gov: and to the Desk Officer: Office of Information and .i: Regulatory Affairs, NEOB-10202. (3150-0104). Office of Management and Budoet, Washington, DC 20503: If a means used to impose an information collection does not c's, T (See NUREG-1022, R.3 for instruction and guidance for completing this form display a currently valid OMB control number, the NRC may not conduct or sponsor. and a N*,......0, htto://vAmnrc.00virP-adiriq-rmidoc-collectionsinureosistaff/sr1022/r3A . person is not required to respond to, the information collection. Contents 1 DESCRIPTION 2 REPORTABI LITY 3 CAUSE 4 NRC FORM 5 CORRECTIVE ACTIONS 6 SAFETY SIGNIFICANCE 7 PREVIOUSLY SIMILAR EVENTS DESCRIPTION At approximately 0918 hours on Tuesday, December 12, 2017, while operating in MODE 1 at approximately 18 percent power, the Grand Gulf Nuclear Station (GGNS) experienced a loss of the Engineered Safety Features (ESF) Transformer 11 (EB) which was powering the Division 1 ESF bus (EA): The transformer experienced an instantaneous ground resulting in a transformer lockout and loss of power to the ESF bus. Subsequently, the station experienced an automatic start of the Division 1 Emergency Diesel Generator (EK) and the partial isolation of the primary and secondary containment buildings. Both of the system actuations were expected responses to a loss of ESF bus and both systems responded as designed. The direct cause of ESF actuations was the loss of ESF Transformer 11. Additionally, GGNS experienced an unrelated isolation of the Reactor Core Isolation Cooling System (BN) upon restoration of power. The' isolation of the. Reactor Core Isolation Cooling System did not result in a loss of safety function. The cause of this isolation is under investigation and will be documented in accordance with the GGNS corrective action program. REPORTABI LITY This event is reportable to the NRC in accordance with 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.73(a)(2)(iv)(A) as an event or condition resulting in a valid actuation of a ESF system. The 10 CFR 50.72 reporting requirements were met with the completion of Emergency Notification System (ENS) Notificatibn 53115, at 1740 hpurs eastern standard time on December 12, 2017. CAUSE Direct Cause: The direct cause of the ESF actuation was the loss of ESF Transformer 11 and the opening of the transformer feeder breaker due to an instantaneous ground. Apparent Cause: The most probable cause is a ground on one of the feeder cables to ESF Transformer 11. However, the investigation and causal analysis is ongoing at this time and this licensee event report will be supplemented upon completion of the GGNS causal analysis. NRC FORM (6-2016) 366A U.S. NUCLEAR. REGULATORY COMMISSION LICENSEE. EVENT REPORT (LER) CONTINUATION 'SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form htto://www.nrc.coWreadino-rm/doc-collectionsinureos/staff/sr1022/r3/) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/3112020 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 Infoccillects.Resource@nrc.gov, and to the Desk Officer. Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington. DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number. the NRC may not conduct or sponsor. and a person is not required to respond to, the information collection. 2. DOCKET 3. LER NUMBER 05000.416 CORRECTIVE ACTIONS Spare Essential Transformer 21 was placed into service and normal power was restored. The investigation and causal analysis is ongoing and this licensee event report will be supplemented upon completion of GGNS's causal analysis. The planned corrective actions will be included in the corrective action program and may be changed in accordance with the program. .": SAFETY SIGNIFICANCE There were no nuclear safety consequences or radiological consequences as a result of this event. No Technical Specification Safety Limits were violated. Upon the loss of Engineered Safety Feature Transformer 11 all required accident mitigation ESF components responded as designed. The isolation of the Reactor Core Isolation Cooling System, although unexpected, did not adversely impact the plant's ability to respond to the event. PREVIOUSLY SIMILAR EVENTS Protective Relaying Circuitry on the "B" Main Transformer Transformer Wiring Entergy has reviewed the events listed in the licensee event reports (LER) documented above to determine if the corrective actions should have prevented the event documented in this LER. Based on a preliminary evaluation it has been concluded the established corrective actions would not have prevent this event. Entergy's investigation into the cause of this event and the development of corrective actions to preclude recurrence are ongoing. This section will be supplemented at the conclusion of this effort.
05000416/LER-2017-006	29 August 2017	10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown	On August 22, 2017 at 2321 hours central daylight time, Grand Gulf Nuclear Station entered Technical Specification (TS) conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal 'A' (RHR A) being declared inoperable. Entergy Operations Inc. (Entergy) made the decision to shut down the plant based on the results of troubleshooting performed on the RHR A pump. The A RHR pump TS differential pressure was out of specification (low) and could not be returned to acceptable limits. Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on August 29, 2017, due to expected restoration of RHR A exceeding the completion time of 7 days prior to restoring Operability. The shutdown was completed and entry into MODE 3 occurred at 2217 hours CDT on August 29, 2017. The cause is under investigation and this LER will be supplemented upon completion of the causal analysis. Corrective Actions included the replacement of the A RHR pump and the successful retesting of the. A RHR pump and restoration of the pump to operable status. This condition is reportable as a completion of a plant shutdown required by the TS. (4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 3. LER NUMBER 3 REPORTABILITY 4 CAUSE 5 CORRECTIVE ACTIONS 6 NRC FORM 7 CONTINUATION SHEET 8 SAFETY SIGNIFICANCE 9 PREVIOUS SIMILAR OCCURRENCES CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form htio://www.nrcoovireadino-rm/dcc-collectionenureosistafffsr1022;r31 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 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. Grand Gulf Nuclear Station, Unit 1 05000 416 3. LER NUMBER Description On August 22, 2017 at 2321 hours central daylight time (CDT), Grand Gulf Nuclear Station entered Technical Specification (TS) conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal (BO) 'A' (RHR A) being declared inoperable. LCOs not met: 1) TS 3.5.1 for one low pressure ECCS injection/spray subsystem. 2) TS 3.6.1.7 for one RHR containment spray subsystem, and 3) TS 3.6.2.3 for one RHR suppression pool cooling subsystem. Entergy Operations Inc. (Entergy) made the decision to shut down the plant based on the results of troubleshooting performed on the RHR A pump. Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on August 29, 2017, due to expected restoration of RHR A exceeding the TS completion time of 7 days prior to restoring Operability. The shutdown was completed and entry into MODE 3 occurred at 2217 hours CDT on August 29, 2017. REPORTABILITY Entergy completed Event Notification 52936 notifying the Nuclear Regulatory Commission of the commencement of a plant shutdown in accordance with 10CFR50.72(b)(2)(i), due to the anticipated inability to complete the required A RHR Pump repairs prior to exceeding the TS LCO time limits. The completion of the shutdown reported in Event Notification 52936 is reportable in accordance with 10CFR50.73(a)(2)(i)(A), the completion of any nuclear plant shutdown required by the plant's Technical Specifications. LCOs not met: 1) TS 3.5.1 for one low pressure ECCS (BO) injection/spray subsystem. 2) TS 3.6.1.7 for one RHR containment spray subsystem, and 3) TS 3.6.2.3 for one RHR suppression pool cooling subsystem. CAUSE The A RHR pump TS differential pressure was out of specification (low) and could not be returned to acceptable limits prior to exceeding the 7 day limiting condition for operation time. The A RHR pump was shipped to a vendor for the determination of the cause of the A RHR pump being out of specification limits. This causal analysis is not anticipated to be completed prior to the 60 day report time for this licensee event report (LER). This LER will be supplemented upon completion of the causal analysis. CORRECTIVE ACTIONS Replacement of the A RHR pump. Successful retesting of the A RHR pump and restoration of the pump to operable status. NRC FORM (4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for competing thIs.form httplAvww.nrc.dovireadino-rm(doc-coRectionsinurectsistaff/sr1022/r3/) 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 Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information colIection does not display a currently valid OMB con:rol number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection. 05000 416 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 OCCURRENCES Removal Pump The causes and corrective actions associated with these previous similar events was reviewed and it is believed that the corrective actions could not have prevented the cause of this event.
05000416/LER-2017-005	9 July 2017	10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	On July 9, 2017, at approximately 2158 hours central daylight time a pressure boundary door to the Control Room Envelope was left unsecure. The Control Room Envelope was inoperable for approximately one minute, at which time the door was closed. Grand Gulf Nuclear Station personnel identified that a loss of Safety Function occurred due to a breach in the Control Room Envelope resulting in inoperability of both divisions of Standby Fresh Air. This event is being reported under 10CFR 50.72(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. The cause was determined to be that the organization failed to understand the nuclear safety consequence associated with a degraded condition of door SZ1000516 and failed to implement a mitigating strategy. Corrective actions included restoration of the door to operable status and coaching of the responsible individual. Future corrective action will include implementation of a maintenance strategy for control room pressure boundary doors to ensure reliable operation. There were no nuclear safety consequences or radiological consequences as a result of this event. (4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 DESCRIPTION 3 REPORTABILITY 4 CAUSE 5 CORRECTIVE ACTIONS 5.1 Immediate Corrective Actions: 6 NRC FORM 7 CONTINUATION SHEET 8 SAFETY SIGNIFICANCE 9 PREVIOUS SIMILAR OCCURRENCES CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form http://www.nrc.qovireading-rm/doc-collectionsinureasistaff/sr1 0221r31) 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 Infocoilects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs. NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection. 2. DOCKET 3. LER NUMBER 05000 416 DESCRIPTION On July 9, 2017, at approximately 2158 hours central daylight time a pressure boundary door to the Control Room Envelope (NA) was left unsecure. The Control Room Envelope was inoperable for approximately one minute, at which time the door was closed. Grand Gulf Nuclear Station personnel identified that a loss of Safety Function occurred due to a breach in the Control Room Envelope resulting in inoperability of both divisions of Standby Fresh Air systems. REPORTABILITY This event is being reported under 10CFR50.73(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. CAUSE The direct cause of the event was that the door was degraded, resulting in the door dragging on the floor such that the automatic door closer would not function properly. The organization failed to understand the nuclear safety consequence associated with the degraded condition and failed to implement a mitigating strategy. CORRECTIVE ACTIONS Immediate Corrective Actions: Upon identification the door was immediately secured and the Control Room Supervisor was notified. The event was entered into the Grand Gulf Nuclear Station corrective action program. Grand Gulf Nuclear Station Security personnel provided immediate coaching to the employee who left the door open. The support hinge bushing was replaced, restoring normal door closure. Corrective Actions To Prevent Recurrence: Implement a maintenance strategy for doors SZ1000715, Passageway Door; SZ1000708, Corridor Door; SZ1000612, Corridor No. 3 Door; SZ1000516, Corridor Door. NRC FORM (6-2016) nec.,„..., 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form htlp://www.nrc.novireading-rm/doc-collections/nurecis/staff/sr1022/r3/) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported :essons 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 Infocollects.Resource©nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget. Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection. 2. DOCKET 3. LER NUMBER 05000 416 SAFETY SIGNIFICANCE There were no nuclear safety consequences or radiological consequences as a result of this event. No Technical Specification Safety Limits were violated. PREVIOUS SIMILAR OCCURRENCES The identified licensee event reports were reviewed and it has been determined that the causes and corrective actions for the previously identified events were sufficiently different that they could not have predicted or prevented the occurrence of this event.
05000416/LER-2017-004	26 May 2017	10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	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.
05000416/LER-2017-002	28 February 2017	10 CFR 50.73(a)(2)(v)(C), Loss of Safety Function - Release of Radioactive Material 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	On March 24, 2017, it was determined that the A Standby Gas Treatment System (SGTS A) was not operating as expected. The investigation into the event revealed the Single Nest Power Supply had failed resulting in loss of flow control. It was determined the power supply had been replaced and the technical specification limiting condition for operation exited on February 23, 2017. The A SGTS was not run between replacement of the power supply and the time of discovery condition on March 24, 2017. Additionally, the B SGTS was removed from service for planned corrective and preventative maintenance on February 28, 2017 and returned to service on March 3, 2017. This condition prohibited by technical specifications in accordance with 10 CFR 50.73(a)(2)(i)(B) for the A SGTS train being inoperable for a period great than allowed by technical specifications. The cause of this event has been determined to be a power supply that could not be fully inserted due to pre-existing damage. The damaged power supply was not appropriately corrected prior to installation due to an incorrect screening practice. The defective power supply was replaced and tested satisfactorily. Entergy established proceduralized barriers to minimize recurrence of similar errors through the establishment of pre-installation checks for the power supply as well as post maintenance testing of the replaced power supplies. There were no actual nuclear safety consequences or radiological consequences. No Technical Specification Safety Limits were violated. (4-2017) to 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 DESCRIPTION 3 REPORTABILITY 4 CAUSE 5 3. LER NUMBER 6 CORRECTIVE ACTIONS 7 SAFETY SIGNIFICANCE 8 PREVIOUSLY SIMILAR EVENTS CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form htiorAww.nrc.00vireadino-rrradoc-collectionsinureosistaff/sr1022,ra) 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 20555-8001, or by e-mail to Infocollects.Resourcee 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. Grand Gulf Nuclear Station, Unit 1 05000 416 DESCRIPTION On March 24, 2017, while operating the A Standby Gas Treatment System (SGTS A) the SGTS Flow Recorder was indicated a downscale reading. The Plant Data System computer points indicated a flow mismatch between the available indications of approximately 5000 cubic feet per minute (CFM). Due to the mismatch indications and the downscale reading the surveillance was terminated and Standby Gas "A" was returned to standby. The investigation of the identified conditions determined the failure of the systems was the Single Nest Power Supply. Failure of this power supply would result in a loss of the associated train's flow control. The investigation revealed that the power supply was replaced and the technical specification limiting condition for operation exited on February 23, 2017. The A SGTS was not run between replacement of the power supply and the time of discovery condition on March 24, 2017. Prior to the power supply being replaced the system had been successfully tested and therefore it was determined that this condition could only have been present since the installation of the new Power Supply was completed on February 23, 2017. The investigation further revealed that the B SGTS was removed from service for planned corrective and preventative maintenance on February 28, 2017 and returned to service on March 3, 2017. The above described condition rendered the A SGTS inoperable and also resulted in a period when both SGTSs were inoperable during the same time period. REPORTABILITY The condition is also reportable as a condition prohibited by technical specifications in accordance with 10 CFR 50.73(a)(2)(i)(B) for the A SGTS train being inoperable for a period great than allowed by technical specifications. An engineering evaluation was performed that demonstrated the SGTS A was able to perform its safety function with the identified nonconformance. Therefore this LER supplement retracts reporting this concern as a loss of safety function under 10 CFR 50.73(a)(2)(v)(C). CAUSE The cause of this event has been determined to be within the control system of the Single Nest Power Supply. The equipment failure analysis determined the power supply could not be fully inserted due to pre-existing damage. The damage to the power supply was not appropriately corrected prior to installation due to an incorrect screening of the condition report that initially identified the pre-existing condition. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (6-2016) FiEnt, LICENSEE EVENT REPORT (LER) (A 2 CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this form http:ilwwwnrc.govireadina-rinidcc-collectionsinureasistaffisrl 022/0) 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 Infacollects.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. Grand Gulf Nuclear Station, Unit 1 05000 416 3. LER NUMBER CORRECTIVE ACTIONS The defective power supply was replaced and tested satisfactory. Proceduralized barriers were established to minimize recurrence of similar errors through the establishment of pre-installation checks for the power supply as well as post maintenance testing of the replaced power supplies. The governance was reviewed as it relates to discovery of deficient conditions on replacement parts and required actions based on classification of the part (i.e. safety related, quality part, etc.). This action was performed to determine if this issue should have been identified as a NON CONFORMING part and if it should have been tagged and segregated. This review revealed the process was not followed and follow-up actions were developed to correct the cause of the error. SAFETY SIGNIFICANCE There were no actual nuclear safety consequences or radiological consequences as a result of this power supply failure. No Technical Specification Safety Limits were violated. PREVIOUSLY SIMILAR EVENTS The identified licensee event reports were reviewed and it has been determined that the causes and corrective actions for the previously identified events were sufficiently different that they could not have predicted or prevented the occurrence of this event.
05000416/LER-2017-001	27 January 2017 28 March 2017	10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	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-2016-009	27 March 2016 16 August 2017	10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	On March 27, 2016, the Entergy, while returning the GGNS Unit 1 to power operations at the conclusion of Refueling Outage 21, reactor thermal power was allowed to exceed 16.8 percent without first fully calibrating the Oscillation Power Range Monitor (OPRM) to include the new limits required by the adoption and implementation of the Maximum Extended Load Limit Line Plus (MELLLA+) operating range. Specifically, the OPRM Upscale setting requirements specified in Technical Specification 3.3.1.1, Reactor Protection System (RPS) Instrumentation, Table 3.3.1.1-1, Reactor Protection System Instrumentation, Function 2, Average Power Range Monitors, Sub-Function f. OPRM Upscale were not fully met. The direct cause of this event was the failure to ensure the required procedure changes were incorporated and performed prior to the unit entering the mode of applicability. Corrective actions included the addition of the condition to Limiting Condition for Operation tracking system to ensure resolution prior to a mode of applicability. This event is reportable as a licensee event report (LER) in accordance with 10CFR50.73(a)(2)(i)(B) as an operation or condition prohibited by Technical Specifications and 10CFR50.73(a)(2)(v)(A) for the loss of safety function.
05000416/LER-2016-008	9 September 2016 16 August 2017		Entergy manually shutdown the Grand Gulf Nuclear Station (GGNS) reactor on September 8, 2016, at approximately 1104 hours, to replace Residual Heat Removal (RHR) Pump 'A' after it failed its technical specification surveillance. The reactor entered MODE 4, Cold Shutdown, at approximately 0509 hours on September 9, 2016. Residual Heat Removal Train 'B' was placed in shutdown cooling mode (SDC) to maintain Reactor coolant temperature 110 degrees Fahrenheit (F) to 120 F on September 9, 2016 at 0332. At the time of entry into MODE 4, and throughout the time period the 'A' RHR pump was inoperable, the Alternate Decay Heat Removal (ADHR) System was not available because the ADHR heat exchangers tube-side cooling water system had been clearance-tagged CLOSED to support cleaning of the heat exchanger tubes since August 10, 2016. This condition was not identified until September 23, 2016, after the 'A' RHR train was returned to OPERABLE status. The direct cause of this event appears to be the lack of adequate information validation and verification by station personnel. Entergy personnel verified both RHR trains were operable and available on September 23, 2016, when the ADHR Heat Exchangers were identified as clearance-tagged CLOSED. The cause of the event remains under investigation and this licensee event report will be supplemented upon completion of the causal evaluation.
05000416/LER-2016-007	8 September 2016	10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown	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-2016-006	30 June 2016	10 CFR 50.73(a)(2)(iv)(A), System Actuation	On June 30, 2016 at 1715 CDT, Grand Gulf Nuclear Station (GGNS) experienced an electrical power supply loss from Service Transformer 21 which resulted in power supply being lost to Division 2 (16AB Bus) and Division 3 (17AC Bus) ESF buses. This resulted in a valid actuation of Division 2 and Division 3 Diesel Generators on bus under voltage. They both automatically started and energized their respective ESF buses as designed. During this event, the loss of power to the Division 2 (16AB Bus) resulted in a Division 2 RPS bus power loss, which actuated a Division 2 RPS half SCRAM signal. The power loss also resulted in a loss of the Instrument Air pressure resulting in some Control Rod Scram Valves to drift open. This in turn caused the Scram Discharge Volume to fill to the point where a Division 1 RPS half SCRAM signal was initiated from Scram Discharge Volume level high on Channel 'A'. This resulted in a valid full RPS Reactor SCRAM while not critical. Instrument Air pressure was restored and the SCRAM signal was reset at 1733 CDT. Appropriate off normal event procedures were entered to mitigate the transient. All safety systems performed as expected. The Direct Cause was a failure of the taped insulation on the 'C' phase 34.5 kV Service Transformer power supply cable to the BOP 23 Transformer. The Apparent Cause was an outer tape wrap insulation failure that left a moisture path between the braid, connecting the splice, and the center conductor. A temporary three phase overhead line was installed to bypass the faulted 34.5 kV cable section. A planned corrective action to install a permanent underground replacement was generated. 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 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 CORRECTIVE ACTIONS 9 SAFETY SIGNIFICANCE 10 PREVIOUS SIMILAR EVENTS CONTINUATION SHEET 05000 416 PLANT CONDITIONS PRIOR TO THE EVENT At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 4, Cold Shutdown, with Main Steam Isolation Valves (MSIVs) (SB) closed. Reactor Water Level was maintained in the normal water level band by the Control Rod Drive System (CRDS) (AA). Residual Heat Removal (RHR) A (BO) was maintained in Shutdown Cooling operation and it was not affected by this event. DESCRIPTION On June 30, 2016 at 17:15, Grand Gulf Nuclear Station experienced an electrical power supply loss from Service Transformer 21 (ST21) (XFMR) which resulted in power supply being lost to Division 2 (16AB Bus) and Division 3 (17AC Bus) Engineered Safety Feature (ESF) buses (BU). This resulted in a valid actuation of Division 2 and Division 3 Standby Diesel Generators (SDGs) (EK) on under-voltage. Both SDGs automatically started and energized their respective ESF buses as designed. During this event, the loss of power to the Division 2 (16AB bus) resulted in a Division 2 Reactor Protection System (RPS) (JE) bus power loss, which actuated a Division 2 RPS half SCRAM signal. The Division 2 power loss also resulted in a loss of Instrument Air pressure resulting in some Control Rod Scram Valves to drift open. This in turn caused the Scram Discharge Volume to fill to the point where a Division 1 RPS half SCRAM signal was initiated from Scram Discharge Volume level high on Channel A. This resulted in a valid full RPS Reactor SCRAM while not critical. Instrument Air pressure was restored and the SCRAM signal was reset at 1733 hrs. Appropriate off normal event procedures were entered to mitigate the transient. No Emergency Core Cooling System (ECCS) (BM) initiation signals were reached. All safety systems performed as expected. REPORTABILITY Event Notification No. 52057 was made to the NRC Operations Center. This LER is being submitted pursuant to Title 10 Code of Federal Regulations 10 CFR 50.73(a)(2)(iv)(A) for the actuation of Engineered Safety Features. Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System on June 30, 2016, within 8 hours of the event, pursuant to 10 CFR 50.72(b)(3)(iv) for multiple valid specified system actuations. CAUSE The Direct Cause was a failure of the taped insulation on the 'C' phase 34.5 kV Service Transformer 21 power supply cable to the BOP 23 Transformer. The Apparent Cause was an outer tape wrap insulation failure between the braid, connecting the splice, and the center conductor. Disassembly and visual inspection of the cable splice showed that the insulation had voids and a moisture path through the split in the outer tape wrap. 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 CORRECTIVE ACTIONS A temporary three phase overhead line was installed to bypass the faulted 34.5 kV cable section. A corrective action, to install a permanent underground replacement, is planned for April 2018. 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 The INPO ICES search tool was used to find industry Operating Experience similar to this event. The search identified cable failures and partial loss of offsite power at both Grand Gulf and other stations. There were no specific learnings however that would have helped to prevent this event.
05000416/LER-2016-005	25 June 2016		On June 25, 2016, at 1407 Central Daylight Time, Grand Gulf Nuclear Station was operating in Mode 1 at approximately 98.75 percent rated thermal power, performing final power ascension to 100% power with Reactor Recirculation Flow Control Valves, when an unplanned automatic reactor SCRAM occurred. All safety systems responded per design. Two Safety Relief Valves opened at the onset of the event to control reactor pressure and reseated properly. All control rods inserted when the signals generated by the Reactor Protection System were received. There were no Emergency Core Cooling System actuations. The shift immediately entered the appropriate Off Normal Event Procedures. The plant was stabilized with pressure control on the main turbine bypass valves and level control on the start-up level control valve. The cause of the event is under investigation by a root cause evaluation team and will be provided in a supplemental report. There were no actual nuclear safety consequences or radiological consequences during the event. 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 not conduct or sponsor, and a person is not required to respond to, the information collection. 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 A. PLANT OPERATING CONDITIONS BEFORE THE EVENT 3 B. DESCRIPTION OF OCCURRENCE 4 C. REPORTABLE OCCURRENCE 5 NRC FORM 6 CONTINUATION SHEET 7 D. CAUSE 8 E. CORRECTIVE ACTIONS 9 F. SAFETY ASSESSMENT 10 G. PREVIOUS SIMILAR EVENTS CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 A. PLANT OPERATING CONDITIONS BEFORE THE EVENT At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1 and ascending in power at approximately 99 percent (%) rated thermal power (RTP). All systems, structures and components (SSCs) that were necessary to mitigate, reduce the consequences of, or limit the safety implications of the event were available. No inoperable SSCs at the start of the event contributed to the event. B. DESCRIPTION OF OCCURRENCE On June 25, 2016, at 14:07 hours, during power ascension while at approximately 99% RTP, Turbine Control Valve (TCV) 'B' initiated a Fast Closure followed by TCV 'D' Fast Closure followed by TCV 'C' Fast Closure resulting in actuation of Reactor Protection System (RPS) Divisions 'A' and 'B' causing an automatic full SCRAM signal. All Control Rods fully inserted as required. Reactor power lowered resulting in Generator Power Differential causing a Main Generator Trip. Reactor Pressure High signal was received and actuated Safety Relief Valves (SRVs) 1621F051D and 1B21F051B. Both SRVs opened once and re-closed approximately 27 seconds later. No other SRVs actuated and Low-Low Set functioned properly. Control room personnel entered the appropriate Off Normal Event and Emergency Procedures. The Feedwater Level Control System responded as designed. Reactor level initially lowered below the Level 3 scram setpoint as a result of void collapse and then rapidly rose as feedwater injected. Level stabilized without reaching the Level 8 feedwater trip setpoint. Reactor water level was transferred to startup level control mode. RPS was reset with reactor water level stable on Startup Level Control and reactor pressure stable on Pressure Reference. No Emergency Core Cooling System (ECCS) initiations and no unexpected group isolations occurred as a result of the transient. C. REPORTABLE OCCURRENCE This Licensee Event Report (LER) is being submitted pursuant to Title 10 Code of Federal Regulations (10 CFR) 50.73(a)(2)(iv)(A) for an automatic actuation of the reactor protection system (RPS). Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System on June 25, 2016, within 4 hours of the event pursuant to 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72 (b)(3)(iv)(A) for a valid RPS actuation while the reactor was critical. 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 collection. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 D. CAUSE Investigation of the root cause is ongoing. A supplemental report to this LER will be provided upon completion of the root cause investigation. E. CORRECTIVE ACTIONS Immediate: Tested and replaced the two suspect Main Turbine Control Valve circuit cards Pending Action: An RCE team is currently working to identify additional corrective actions. This LER will be supplemented when the corrective action(s) to preclude recurrence is/are determined. F. SAFETY ASSESSMENT There were no actual nuclear safety consequences or radiological consequences during the event as all systems operated as designed and there was no release of radioactivity. G. PREVIOUS SIMILAR EVENTS Previous events or conditions that involved the same underlying concern or reason as this event (i.e. same root cause, failure, or sequence of events) will be documented in the supplemental report when the RCE is finalized.
05000416/LER-2016-004	17 June 2016		On June 17, 2016, at 0256 Central Daylight Time, Grand Gulf Nuclear Station experienced an automatic reactor SCRAM. Prior to the SCRAM, Grand Gulf Nuclear Station was operating in Mode 1 at approximately 65% rated thermal power and performing the Turbine Stop and Control Valve Operability Surveillance. During the surveillance, after the 'B' Turbine Stop valve was closed per procedure, the 'D' Turbine Stop Valve unexpectedly closed. The 'A' and 'C' Turbine Control Valves were then challenged to control Turbine and Reactor pressure resulting in Reactor pressure and power oscillations. Attempts were made to reset the 'B' Turbine Stop Valve followed by power reduction. While driving rods to reduce power, an automatic Reactor SCRAM was received at 0257 on a Neutron Monitoring System Oscillation Power Range Monitoring trip. A reset solenoid valve initiated the event due to a malfunction after it was actuated per the surveillance procedure. The solenoid valve remained in the tripped position during the surveillance which allowed the trip header pressure to be inappropriately vented triggering closure of the 'D' stop valve. The solenoid valve was replaced prior to startup. The root cause is still under investigation. This event posed no threat to public health and safety. 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 collection. 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 NO 3 PLANT CONDITIONS PRIOR TO THE EVENT 4 DESCRIPTION 5 REPORTABILITY 6 NRC FORM 7 CONTINUATION SHEET 8 CAUSE 9 NO 10 CORRECTIVE ACTIONS 11 SAFETY SIGNIFICANCE 12 PREVIOUS SIMILAR EVENTS CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 NO PLANT CONDITIONS PRIOR TO THE EVENT At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1 at approximately 65% rated thermal power due to a planned power reduction to complete a Control Rod sequence exchange, Steam Jet Air Ejector (SJAE) swap, Cooling Tower acid flush, and Main Turbine Stop and Control Valve Operability Surveillance. All systems, structures and components that were necessary to mitigate the consequences of, or limit the safety implications of an event were available. No safety significant components were out of service. DESCRIPTION On June 17, 2016, GGNS was in Mode 1 at approximately 65% rater thermal power performing the Main Turbine Stop and Control Valve Operability Surveillance. During the surveillance, the 'B' Turbine Stop Valve was closed, as directed by the surveillance procedure. While the 'B' Turbine Stop Valve was closed, the 'D' Turbine Stop Valve unexpectedly closed, resulting in a Division II Reactor Protection System (RPS) half SCRAM signal. With the 'B' and 'D' Turbine Stop Valves closed, the remaining 'A' and 'C' Turbine Control Valves were challenged to precisely control Turbine and Reactor pressure. This resulted in Reactor pressure and power oscillations. Although oscillations were occurring, Reactor pressure and water level maintained margin to SCRAM setpoints. Multiple attempts were made to reset the 'B' Turbine Stop Valve followed by power reduction. While driving rods to reduce power, the Reactor received an automatic SCRAM at 0257 on a Neutron Monitoring System Oscillation Power Range Monitoring (OPRM) trip. REPORTABILITY This Licensee Event Report (LER) is being submitted pursuant to Title 10 Code of Federal Regulations (10 CFR) 50.73(a)(2)(iv)(A) for an automatic actuation of the RPS. Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System on June 17, 2016, within 4 hours of the event pursuant to 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72 (b)(3)(iv)(A) for a valid RPS actuation while the reactor was critical. 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@nrcgov, 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 collection. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET CAUSE 2. DOCKET 3. LER NUMBER 05000 416 NO Direct Cause: The reset solenoid valve 1N32F514C initiated the event due to a malfunction after it was actuated per the surveillance procedure. The actuation of this reset solenoid valve triggered the loss of trip fluid pressure, and subsequent closure of the `D' stop valve. During initial investigation, the solenoid valve was found to have remained in the tripped position during the surveillance which allowed the trip header pressure to be inappropriately vented. Root Cause: Investigation of the root cause is ongoing. A supplemental report to this LER will be provided upon completion of the root cause investigation. CORRECTIVE ACTIONS The immediate corrective action was to replace both the 1N32F514C and 1N32F515C solenoid valves. SAFETY SIGNIFICANCE The event posed no threat to the health and safety of the general public or to nuclear safety as RPS 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 root cause investigation.
05000416/LER-2016-003	7 April 2016	10 CFR 50.73(a)(2)(v)(C), Loss of Safety Function - Release of Radioactive Material	On April 7, 2016 the Grand Gulf Nuclear Station, while at 100 percent reactor thermal power, experienced a loss of Secondary Containment safety function during the performance of routine Secondary Containment building roof inspection. During the inspection activity the roof hatch, which allows access/egress to the roof, was left open for approximately 20 minutes. Based on a review of the work activity it is believed this error has occurred a minimum of 30 times in the past 5 years. The direct cause of the event was the failure to close the hatch. The apparent cause of the event was the failure to establish adequate work instructions to maintain control of the hatch and to ensure Secondary Containment was maintained OPERABLE. Corrective actions include closure of the hatch and the establishment of the appropriate control over the hatch in the work instructions. There were no actual nuclear safety consequences or radiological consequences during the event. This condition is reportable in accordance with 10 CFR 50.73(a)(2)(v)(C). A 10CFR 50.72 notification was not performed because the event was not identified until after compliance was restored. 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 not conduct or sponsor, and a person is not required to respond to, the information collection. 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 PLANT CONDITIONS PRIOR TO THE EVENT 3 DESCRIPTION 4 REPORTABILITY 5 NRC FORM 6 CONTINUATION SHEET 7 CAUSE 8 CORRECTIVE ACTIONS 9 SAFETY SIGNIFICANCE 10 NRC FORM 11 CONTINUATION SHEET 12 PREVIOUS SIMILAR EVENTS CONTINUATION SHEET 05000 416 PLANT CONDITIONS PRIOR TO THE EVENT 100 percent reactor thermal power with no structures, components, or safety systems inoperable at the start of the event or contributing to the event. DESCRIPTION On April 7, 2016, while at 100 percent reactor thermal power, members of the Grand Gulf Nuclear Station (GGNS) staff were assigned to perform a routine inspection of the Secondary Containment (NG) roof surfaces and roof drain scuppers and screens. The purpose of this inspection was to verify the materials were in good working order and to identify any condition requiring maintenance/repair. The inspection is performed on a quarterly frequency and has been performed by the same lead individual for the past five years in the same manner. Therefore, it is estimated that the hatch has been inappropriately left open a minimum of 20 times in the past 5 years. After obtaining permission to start work the personnel proceeded to the roof access hatch, (DR) proceeded through the hatch, and performed the required inspection activities. The inspection requires approximately 30 minutes to complete all of the required tasks. Access to the roof is obtained via an access hatch that is normally closed and latched. The hatch can only be opened from inside the building. This required the personnel to leave the hatch open during the time period they were on the roof performing the inspection. Leaving the hatch open for purposes other than immediate access or egress results in a breach of the Secondary Containment boundary and a loss of safety function for the Secondary Containment boundary. This event occurred on April 7, 2016. The Nuclear Regulatory Commission Senior Resident Inspector questioned the acceptability of leaving the hatch in the open position. Members of the GGNS staff, based on the challenges from the Senior Resident Inspector, evaluated the concern and it was determined this event was reportable as a loss of safety function. REPORTABILITY A Licensee Event Report is required pursuant to Title 10 Code of Federal Regulations (10 CFR) 50.73(a)(2)(v)(C) for an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: (C) control the release of radioactive material. Specifically, the hatch was left open. 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 collection. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 A 10CFR 50.72 notification was not performed because the event was not identified until after compliance was restored. CAUSE Direct Cause: The failure to immediately close the hatch upon completion of egress from Secondary Containment Building. Apparent Cause: The failure to establish adequate work instructions to maintain control of the hatch and to ensure Secondary Containment was maintained OPERABLE. CORRECTIVE ACTIONS Immediate: The hatch was closed and Secondary Containment integrity was restored. Pending Action: Work instructions for the work orders that require personnel to access/egress the Secondary Containment Roof Hatch will be revised to ensure the correct control of the hatch and maintenance of Secondary Containment OPERABILITY. The work instructions will be revised by June 30, 2016. SAFETY SIGNIFICANCE There were no actual nuclear safety consequences or radiological consequences during the event. The time period for which there could have been an unmonitored release during an event was approximately 20 minutes. However, no abnormal event or release occurred during the time of the event, therefore, no radiological consequence occurred. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2015 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 not conduct or sponsor, and a person is not required to respond to, the information collection. CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 PREVIOUS SIMILAR EVENTS Drawdown Test Valves Heat Removal Entergy has reviewed the above identified licensee event reports and has concluded that the causes and corrective actions associated with these licensee event reports could not have prevented the occurrence of the event documented in this licensee event report.
05000416/LER-2016-002	29 March 2016		On March 29, 2016, at 1123 Central Daylight Time, Grand Gulf Nuclear Station was operating in Mode 1 and ascending in power at approximately 37% when an unplanned uncomplicated automatic reactor SCRAM occurred. A generator lockout was received due to a Main Transformer 'B' Differential Relay Trip which was followed by a turbine control valve fast closure, turbine trip, and reactor SCRAM. The Reactor Protection System and all other safety systems functioned as designed. The cause of the Main Transformer 'B' Differential Relay Trip was identified during forced outage investigation of the 'B' Main Transformer control cabinet. The high voltage current transformer wiring was incorrectly landed at the X1/X2 terminals instead of the X1/X3 terminals. This wiring configuration resulted in a turns ratio of 1000:5 instead of the designed 2200:5, causing relay actuation at a point lower than designed. The erroneous wiring configuration was corrected and all remaining wiring for the 'A', '6', and 'C' Main Transformer wiring was verified correct prior to startup from the forced outage. This event posed no threat to public health and safety. 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 collection. 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 PLANT CONDITIONS PRIOR TO THE EVENT 3 DESCRIPTION 4 REPORTABILITY 5 NRC FORM 6 CONTINUATION SHEET 7 CAUSE 8 CORRECTIVE ACTIONS 9 SAFETY SIGNIFICANCE 10 PREVIOUS SIMILAR EVENTS 11 NRC FORM 12 CONTINUATION SHEET 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 and ascending in power at approximately 37% rated thermal power. All systems, structures and components that were necessary to mitigate, reduce the consequences of, or limit the safety implications of the event were available. No safety significant components were out of service. DESCRIPTION On March 29, 2016, Grand Gulf Nuclear Station (GGNS) was ascending in power for the unit startup following Refueling Outage 20 (RF 20). As reactor power reached approximately 37% rated thermal power, a generator lockout was received followed by a turbine control valve fast closure and turbine trip which resulted in an uncomplicated automatic reactor SCRAM. The generator lockout was the result of the Main Transformer 'B' Differential Relay Trip. The reactor protection system (RPS) (JC) and all safety systems functioned as designed and expected. During the investigation, it was discovered inside the 'B' Main Transformer control cabinet that the high voltage current transformer (CT) (XCT) turns ratio wiring was incorrect. The CT wiring was connected in a manner that produced a turns ratio of 1000:5 versus the designed 2200:5. Due to this erroneous configuration the CT trip setpoint was lower than designed. Therefore, the CT and current differential relay actuation was not an equipment failure but an actual sensed actuation based on an incorrect wiring scheme. Work orders that involved working inside this panel during RF 20 were reviewed to determine when the wiring was altered. No work on CT wiring found incorrectly landed was intended to be performed during RF 20. Current Transformer ratio wiring work was not within the scope of the transformer rewiring project carried out during RF20. The most likely time the wiring was incorrectly removed and re-landed would have been during the post modification testing which was performed under a work order at the conclusion of the wiring project. REPORTABILITY This Licensee Event Report (LER) is being submitted pursuant to Title 10 Code of Federal Regulations (10 CFR) 50.73(a)(2)(iv)(A) for an automatic actuation of the RPS. Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System on March 29, 2016, within 4 hours of the event pursuant to 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72 (b)(3)(iv)(A) for a valid RPS actuation while the reactor was critical. 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 collection. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET CAUSE 2. DOCKET 3. LER NUMBER 05000 416 Direct Cause: The 'B' Main Transformer X21 CT wiring was incorrectly landed at X1/X2 terminals instead of the X1/X3 terminals. This changed the ratio of the 'B' Main Transformer Current Differential Relay from the designed 2200:5 to 1000:5, which resulted in a lower trip setting than designed for the 'B' Main Transformer Differential Overcurrent trip. Cause 1: Vague or inadequate work instructions provided in the testing and troubleshooting work package. Cause 2: Insufficient testing following completion of all work. CORRECTIVE ACTIONS The immediate corrective action was to correct the 'B' Main Transformer CT wiring and verify all other wiring in the 'A', 'B', and 'C' Main Transformer control cabinets was correct. No other issues with wiring was identified during this verification. Two corrective actions to prevent reoccurrence were identified: 1. Revise procedure(s) to require lifted lead sheet use (or similar table with performer and verifier signatures) in all work instructions where wiring determinations and/or re-terminations are performed at GGNS. 2. Revise the Post Maintenance Testing procedure to include clear guidance from SOER 10-01 (as delineated in the Post Modification Testing and Special Instructions procedure) for transformer work. SAFETY SIGNIFICANCE The event posed no threat to the health and safety of the general public or to nuclear safety as RPS performed as designed. All safety systems responded as expected and Operator actions were in accordance with GGNS procedures. 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 EVENTS The Main Transformers were installed in April 2012 to support Extended Power Uprate (EPU). Since the installation, there have been three RPS SCRAMs on main turbine trips associated with CTs prior to this event. These are documented in LER-2012-008-00, LER-2013-01-00, and LER-2015-001-00. 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 collection. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 The cause of LER-2015-001-00 was not similar to the event being reported, and the corrective actions would not have prevented the March 29, 2016 reactor SCRAM. The cause of LER-2012-008-00 and LER-2013-001-00 was inadequate workmanship and work instructions that did not specify the minimum cold clearance of 0.5 inch between the CT and the micarta plate bolts during installation. The corrective actions addressed revising procedures, testing notes, work instructions, and drawings to ensure the minimum 0.5 inch cold clearance is maintained. Although these two events were attributed to inadequate work instruction, the corrective actions would not have prevented the March 29, 2016 reactor SCRAM.
05000416/LER-2016-001	17 March 2016 16 May 2016	10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat	At 1515 (CDT) on March 17, 2016, with Unit 1 in Mode 5 for a refueling outage, Grand Gulf Nuclear Station (GGNS) experienced an electrical fault and subsequent undervoltage condition on the 115kV offsite power source supplying the onsite Division 2 Engineered Safety Feature (ESF) transformer, ESF 12, and bus. The fault was present long enough to cause an actuation of the Division 2 Load Shedding and Sequencing (LSS) System and subsequent start of the Division 2 Standby Diesel Generator (SDG). The in-service B train of Residual Heat Removal (RHR) was load shed, as designed, and, within 7 seconds, the Division 2 SDG restored power to the Division 2 bus. RHR B was restored within 3 minutes and 13 seconds. Core alterations, in progress at the time, were suspended and fuel bundles were placed in their proper positions. The ESF 11 transformer was paralleled with SDG 2. The Division 2 bus was then placed back to the ESF 11 offsite electrical feed and the Division 2 SDG was secured. The apparent cause was determined to be that the 115kV line was not equipped with pilot scheme protective relaying. Protective relaying is scheduled to be installed in 2017. Alternate Heat Decay Removal (ADHR) remained available throughout this time period. No changes in Spent Fuel Pool or Reactor Cavity temperature were observed. All safety systems operated as expected for the loss of power to ESF12 and Division 2 LSS System. The automatic start of the Division 2 Standby Diesel Generator is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) and the temporary loss of RHR (Shutdown Cooling) is being reported pursuant to 10 CFR 50.73(a)(2)(v)(B).
05000416/LER-2015-003	14 October 2015		At 12:20 on October 14, 2015, with the plant in MODE 1 at 100 percent rated core thermal power, Grand Gulf Nuclear Station identified a condition prohibited by the plant's Technical Specifications. Grand Gulf Nuclear Station failed to meet the requirements of Technical Specification 5.5.6, Inservice Testing Program, and Surveillance Requirement 3.6.1.3.9. Specifically, three valves were not Local Leak Rate Tested at or greater than the required test pressure of 16.28 pounds per square inch guage, 110% of the Extended Power Uprate accident pressure. The cause of the inadequate Surveillance Testing was lack of post Extended Power Uprate testing criteria incorporation into Grand Gulf Surveillance Testing Procedures. Following the inadequate Surveillance Testing in 2013, the valves were subsequently leak rate tested at or greater than the required test pressure of 16.28 psig on October 15, 2015 and October 17, 2015. The subsequent leakage rate testing for all three valves was within the acceptance criteria of Technical Specification Surveillance Requirement 3.6.1.3.9. There was no actual impact to public health and safety due to this event. APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/3112018 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by intemet e-mail to Infocollects.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 collection. 366A U.S. NUCLEAR REGULATORY COMMISSION Contents 1 CONTINUATION SHEET 2 Description of Event: 3 Cause of Event: 4 NRC FORM 5 CONTINUATION SHEET 6 Corrective Actions: 7 Safety Significance: CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 Initial Conditions: At the time of the event, Grand Gulf Nuclear Station (GGNS) was operating in MODE 1 at 100 percent rated core thermal power. There were no systems, structures or components that were inoperable at the start of the event that contributed to the event. Description of Event: Grand Gulf Nuclear Station Unit 1 Technical Specification (TS) Surveillance Requirement (SR) 3.6.1.3.9 requires Primary Containment Isolation Valves (PC1Vs) to be hydrostatically tested at 110% of accident pressure in accordance with the Inservice Testing Program. The inservice Testing Program is defined in TS 5.5.6. While reviewing Local Leak Rate Testing (LLRT) Procedures for outage preparation on October 14, 2015, it was discovered the Local Leak Rate Test Low Pressure Water procedure was not revised as a result of the Extended Power Uprate (EPU). A step in the procedure states the base test pressure is 12.65 psig (110% of peak accident pressure). The value of 12.65 psig is 110% of the pre-EPU peak accident pressure of 11.5 psig. The peak containment accident pressure was revised on July 18, 2012 when the Nuclear Regulatory Commission (NRC) approved the GGNS, Extended Power Uprate, License Amendment Request. The base test pressure should have been revised to 16.28 psig, 110% of the post-EPU peak accident pressure of 14.8 psig. The current testing criterion remains at the post-EPU value of 16.28 psig. Three valves were determined to have not been Local Leak Rate Tested at or greater than the required base test pressure of 16.28 psig. These three valves included two Refuel Water Transfer Pump Suction from Suppression Pool valves and a Residual Heat Removal (RHR) Sample Return Isolation valve. Upon discovery, the valves were declared inoperable and isolated in accordance with TS 3.6.1.3. The two Refuel Water Transfer Pump Suction valves were tested at or greater than the post-EPU base test pressure on October 15, 2015 and passed with zero leakage identified. The Residual Heat Removal Isolation valve was tested at or greater than the post-EPU base test pressure on October 17, 2015 and passed with zero leakage identified. After satisfactory testing was completed, all valves were declared operable. The Refuel Water Transfer Pump Suction valves were previously tested on June 25, 2008 and August 14, 2008 respectively with the appropriate pre-EPU test pressure of 12.9 psig. The test passed with zero leakage identified. The RHR Isolation valve was tested on April 15, 2008 with the appropriate pre-EPU test pressure of 13.0 psig. The test passed with zero leakage identified. Therefore, the valves were demonstrated operable at the 2008 tests. Next testing of the valves was in 2013. The valves were inappropriately tested at or greater than the pre-EPU base test pressure and passed with zero leakage identified. Cause of Event: The cause was determined to be inadequate incorporation of testing criteria into Surveillance Testing Procedure 06-0P-1M61-V-0003, Local Leak Rate Test Low Pressure Water. An Engineering Change was completed which evaluated the impacts of EPU on Containment Leakage Rate Testing. However, it did not identify Local Leak Rate Test Low Pressure Water as a procedure requiring change. This change was missed due to failure of personnel to follow the Engineering Change Process per station procedures. Necessary reviews were not completed and the required procedure change was not identified. Extent of Condition: Ten valves were identified that should have been hydrostatically tested at or above 16.28 psig per post- EPU conditions on a schedule specified by the Inservice Testing Program. Three of those valves were not tested at or above 16.28 psig during their most recent regularly scheduled surveillance test. These three 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 collection. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION CONTINUATION SHEET 2. DOCKET 3. LER NUMBER 05000 416 Valves are being reported under this Licensee Event Report (LER). The remaining seven valves were tested at or above 16.28 psig during their most recent regularly scheduled surveillance test. These seven valves passed the surveillance testing with satisfactory results. Therefore, there are no adverse conditions with the hydrostatic testing of the remaining seven valves. Twenty-two valves are High/Low Interface Valves and are required to be hydrostatically tested at or above 50 psig. The most recent water LLRT was reviewed for each valve and the test was conducted at or above 50 psig as required. Therefore, there are no adverse conditions with the hydrostatic testing of these High/Low Interface valves. Grand Gulf Nuclear Station documented all pneumatically tested valves have been tested at or above the post- EPU accident pressure with the exception of four valves. These four valves do not require pneumatic LLRT at the post-EPU accident pressure until their next regularly scheduled test. Two valves are scheduled for testing prior to July 2016 and two valves are scheduled for testing prior to March 2017. The testing schedule for valves was addressed in the GGNS EPU License Amendment Request and acceptance of the testing schedule as documented in the EPU NRC Safety Evaluation Report. Therefore, there are no additional vulnerabilities as shown by this extent of condition evaluation summary. Corrective Actions: Required Actions of TS 3.6.1.3 were entered and immediate actions were taken to declare the two Refuel Water Transfer Pump Suction from Suppression Pool valves and the RHR Sample Return Isolation valve inoperable. The valves were re-tested at or greater than 16.28 psig, 110% of the post-EPU accident pressure, on October 15, 2015 and October 17, 2015 and passed with zero leakage identified. The LLRT procedure which displayed the incorrect testing pressure will be revised to reflect the appropriate post-EPU base testing pressure. Evaluation of the human performance aspect of this event is ongoing. Correction of the causal factors of the human performance errors will eliminate reoccurrence of this type of event. A supplement to this report will be submitted in the event the evaluation leads to significant changes in the cause or corrective actions associated with this LER. Safety Significance: There were no actual nuclear safety or industrial safety consequences related to this event. There were no actual or potential radiological consequences as a result of this event. The October 15, 2015 and October 17, 2015 post-EPU pressure surveillance testing passed with zero leakage identified for all three valves. Passing the surveillance test at the appropriate post-EPU testing pressure demonstrated the PCIVs continuous operability. Due to the testing proving continuous safety function was maintained, this event will not be counted toward the GGNS Performance Indicator for Loss of Safety Function. Basis of Reportability: This LER is being submitted pursuant to Title 10 Code of Federal Regulation (10 CFR) 50.73(a)(2)(i)(B) for any operation or condition which was prohibited by plant Technical Specifications and 10 CFR 50.73 (a)(2)(v)(C) for any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to (C) control the release of radiological material. Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System (ENS) on October 14, 2015, pursuant to 10 CFR 50.72(b)(3)(v)(C).
05000416/LER-2015-002	1 October 2015		On October 1, 2015, at approximately 0324 hours with the plant in MODE 1 at 100 percent rated core thermal power, Grand Gulf Nuclear Station experienced a loss of Secondary Containment. Grand Gulf Nuclear Station failed to meet the requirements of Technical Specification Surveillance 3.6.4.1.3 in the tested configuration. Following completion of the failed surveillance test, Secondary Containment was returned to an operable status at 0440 hours on October 1, 2015, by returning the system to a previously known operable configuration. The cause of the October 1, 2015 failed drawdown test was Secondary Containment door seal inleakage during testing. After the leaking Secondary Containment door seals were repaired, a subsequent Standby Gas Treatment drawdown surveillance test was performed. The test was completed with satisfactory results on October 6, 2015, for the previously failed configuration. There was no actual impact to public health and safety due to this event.
05000416/LER-2015-001	7 February 2015		On Saturday, February 7, 2015, at 1856 hours Central Standard Time, with the plant at 100 percent thermal power, Grand Gulf Nuclear Station experienced an automatic actuation of the reactor protection system (RPS) and subsequent reactor SCRAM. The "B" main transformer differential trip caused a generator lockout. The generator lockout was followed by a turbine control valve fast closure (RPS SCRAM signal), turbine trip and reactor SCRAM. All control rods fully inserted and safety systems operated as designed. Eleven safety relief valves (SRVs) lifted to control pressure. Feedwater was manually secured to transfer to the startup level control mode. There were no emergency core cooling systems (ECCS) actuations required or initiated in response to this SCRAM. Turbine bypass valves opened to stabilize pressure causing reactor water level to fluctuate. Residual heat removal (RHR) group 2 and 3 containment isolation signals were received on low level 3. A hard ground was discovered on the non-safety protective circuitry between the current transformer and control cabinet on "B" main transformer. The faulted cables and other similar cables were determinated and alternate wiring and conduit was installed before placing the transformers back into service. The event posed no threat to public health and safety.
05000416/LER-2013-006	17 December 2013		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-2013-005	12 December 2013		On December 12, 2013, with the plant operating in Mode 1 at 100 percent thermal power, Grand Gulf Nuclear Station (GGNS) discovered that during six past startups, the Reactor Pressure Vessel (RPV) steam pressure was below zero (0) pounds per square inch gage (psig) with the Main Steam Isolation Valves (MSIVs) open and the Mechanical Vacuum Pumps (MVPs) running without entering LCO 3.4.11 RCS Pressure and Temperature (P/T) Limits. From 12/12/10 through 12/12/13 there were six occurrences of reactor pressure being Report (PTLR) have a minimum pressure value of 0 psig referenced on the curve. The lowest pressure noted in the six occurrences was approximately -9.9 psig on December 13, 2012. All systems performed per design during the reactor startups with RPV pressure below 0 psig during the past 3 years. The cause of not entering LCO 3.4.11 was the condition was procedurally allowed and aligned with Operations training. There were no adverse effects on the health or safety of the public as a result of these events.
05000416/LER-2013-004	6 August 2013	10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	On August 6, 2013, at 10:15 Central Daylight Time (CDT) with the unit in Mode 1 at 93.5 percent thermal power, Grand Gulf Nuclear Station (GGNS) discovered that it was not in compliance with Technical Specification (TS) 3,3.6.1, Primary Containment and Drywell Isolation Instrumentation. Function 5.c, Reactor Steam Dome High Pressure Isolation of the Residual Heat Removal (RHR) system, was inoperable due to the jumpers that disable the function not being removed prior to startup. Upon discovery GGNS entered TS 3.3.6.1 Limiting Condition of Operation (LCO) Actions A.1, B.1, C.1, F.1 and H.1. Also, TS LCO 3.0.4 was not satisfied. At 1111 CDT the jumpers were removed making the reactor steam dome high pressure isolation function Operable and the LCO actions were exited. The cause of the event was a lack of Integrated Operating Instruction (101) 03-1-01-3, Cold Shutdown to Generator Carrying Minimum Load, to include the requirements of EN-DC-136, Temporary Modifications, for adequate procedural control of temporary modifications. Additionally, a failure of the Shift Manager (SM) to initiate a potential TS Limiting Condition for Operation Tracking Record (LCOTR) as required by piocedure 02-5-01-17, Control of Limiting Conditions for Operation was identified as a contributing cause. The event posed no threat to public health and safety. This interlock is provided only for equipment protection to prevent an intersystem loss of coolant accident (LOCA) scenario. Credit for the interlock, is not assumed in the accident or transient analysis sections of the Updated Final Safety Analysis Report (lJF.T..;AR).
05000416/LER-2013-003	30 July 2013		At 14:32 Central Daylight Time on July 30, 2013, Grand Gulf Nuclear Station experienced an unexpected Reactor SCRAM from 100% thermal power due to high reactor pressure detected by the Reactor Protection System. Operations staff immediately entered the appropriate off-normal event procedures. Reactor Core Isolation Cooling (RCIC) initiated and injected briefly during the transient, The RCIC initiation signal was valid, but not required to maintain the reactor vessel water level. Reactor levels were verified and RCIC was subsequently secured. All other systems operated as expected. Reactor pressure was controlled by discharging steam to the main condenser via the main turbine bypass valves. Reactor water level was controlled using the condensate and feedwater systems via the startup level control valve. No safety relief valves actuated. The cause of the SCRAM was a human performance-induced error due to inadequate troubleshooting activities on the Turbine Stress Evaluator (TSE). A temperature transmitter failure was not recognized nor corrected, thereby resulting in a false high turbine stress temperature signal. Upon restoration of the TSE, the incorrect signal forced turbine control valves in the closed direction and resulted in a high reactor pressure transient. Procedures and work orders are being revised to prevent recurrence of this event. There were no adverse effects to the health and safety of the public.
05000416/LER-2013-002	14 January 2013		At 18:05 Central Standard Time on January 14, 2013, Grand Gulf Nuclear Station experienced an automatic Reactor SCRAM caused by a Turbine Trip due to a Main Generator lockout. The plant was operating in Mode 1 at 100 percent thermal power. All safety systems responded per design. Safety Relief Valves opened at the onset of the event to control reactor pressure and reseated properly. All control rods inserted when the signals generated by the Reactor Protection System were received. There were no Emergency Core Cooling System actuations. The shift immediately entered the appropriate procedures. The plant was stabilized with pressure control on the main turbine bypass valves and level control on the start-up level control valve, although high pressure feedwater heater start-up outlet valve 1N21F010B did not open when placing the start-up level control valve in service. There were no adverse effects on the health and safety of the public as a result of this event. The cause of the SCRAM was the Main Generator Isolated Phase Bus Cooling System experienced partial grounding due to design configuration of the horizontal bushing in an energized section of the bus, in close proximity to a degraded viewing port, which allowed water accumulation that created a ground condition. Additional portions of the isophase bus with seal off bushings were de-energized, and covers were installed over the viewing ports prior to plant restart. 6 10-2010) Forms in Word Version Copyright 2008 (www.formsinword.com). For individual or single-branch use only.
05000416/LER-2013-001	4 January 2013		At 23:37 Central Standard Time on January 4, 2013, Grand Gulf Nuclear Station experienced an unexpected Reactor SCRAM caused by a Main Generator trip. The plant was operating in Mode 1 at 94 percent thermal power. All safety systems responded per design. Safety Relief Valves opened at the onset of the event to control reactor pressure and reseated properly. All control rods inserted when the signals generated by the Reactor Protection System were received. There were no Emergency Core Cooling System actuations. The shift immediately entered the appropriate Off Normal Event Procedures. The plant was stabilized with pressure control on the main turbine bypass valves and level control on the start-up level control valve, although high pressure feedwater heater start-up outlet valve 1N21F010B did not open. The cause of the SCRAM was the Main Generator 'A' Phase Neutral Current Transformer (CT) experienced partial grounding due to inadequate clearance between the micarta plate bolts and bottom of the CT allowing the conductors to come in contact with a bolt providing a shunt path to ground. This was caused by inadequate workmanship and work instructions not specifying the clearance during installation. There were no adverse effects on the health or safety of the public as a result of this event. The micarta plate bolts were subsequently removed or cut to provide adequate clearance prior to plant restart. Forms in Word Version Copyright 2008 (www.formsinword.com). For individual or single-branch use only.
05000416/LER-2012-008	29 December 2012		On December 29, 2012, at 00:18 Central Standard Time, Grand Gulf Nuclear Station was operating in Mode 1 at 100 percent thermal power when an unexpected Reactor SCRAM occurred due to a Main Generator trip. All systems responded as expected with the exception of Safety Relief Valve (SRV) 1B21F047A, which was slow to close, and high pressure feedwater heater start-up outlet valve 1N21F010B, which did not open. The shift immediately entered the appropriate Off Normal Event Procedures. Reactor water level was controlled using the normal condensate/feedwater system throughout the event. All control rods inserted after Reactor Protection System signals were received. There were no Emergency Core Cooling System actuations. The plant was stabilized with pressure control on the main turbine bypass valves, and level controlled on the start-up level control valve. The plant responded to the trip as designed with the exception of the one SRV and one start-up outlet valve noted above. The cause of the SCRAM was not initially determined. Additional monitoring equipment was installed to detect a similar condition. Following a second SCRAM on January 4, 2013, the cause was determined to be grounding of the Main Generator 'X Phase Neutral Current Transformer. There were no adverse effects on the health and safety of the public.
05000416/LER-2012-005	13 June 2012	10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	On June 13, 2012, during startup activities for Unit 1 with the reactor in Mode 1 operating at approximately 12 -15 percent (%) power, it was identified that the Average Power Range Monitor (APRMs) were indicating reactor power level lower than expected for the plant condition. Investigation identified that during Refueling Outage 18 (RF18) the APRMs were set to indicate flux lower than the actual power level. This resulted in the system being inoperable during Mode 2 due to the APRM setdown high flux scram setpoint being outside of Technical Specification (TS) 3.3.1.1 Reactor Protection System (RPS) Instrumentation limits. This condition existed when Mode 2 was entered initially on June 6, 2012 until Mode 1 was entered on June 13, 2012. The apparent cause of this condition was differing operating characteristics between the old system and the new system that were not noted during the Engineering Change (EC) process, and therefore they were not adequately addressed by procedure revisions/work order instructions. This condition was limited to the Power Range Neutron Monitoring (PRNM) system. This issue was related to the installation of the new system, future outages will only involve detector replacements and will not involve transferring settings from an existing analog system to a replacement digital system. During startup in Mode 2, the intermediate range monitors (IRM) and the high reactor pressure trip functions were operable. Therefore reactor power transients would have been mitigated by these functions. The APRM Neutron Flux High (Setdown) function is not directly credited in any safety analyses, this event did not adversely affect plant safety or the health and safety of the public.
05000416/LER-2012-004	28 April 2012	10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded	On 4/28/2012 with the plant in Mode 4 for refueling outage 18 (RF18) with the reactor shutdown, during In-Service Inspection (ISI) testing, the nozzle weld N6B-KB, Residual Heat Removal / Low Pressure Coolant Injection (RHR/LPCI) "C" Nozzle to Safe End Weld was ultrasonically (UT) tested. The UT examination revealed an indication indicative of intergranular stress corrosion cracking (IGSCC). The indication was evaluated by Entergy Engineering and Electric Power Research Institute (EPRI) personnel and confirmed to be a weld defect. Inservice Inspection (ISI) relief request (RR-ISI-17; ML12124A245) to repair the weld was submitted to, and approved by, the NRC (reference GTC 2012-00011). A full structural weld overlay repair to restore the weld to ASME Code requirements was completed on May 14, 2012. A post-weld UT test was completed satisfactorily on May 16, 2012. The event posed no threat to public health and safety.
05000416/LER-2012-003	2 April 2012	10 CFR 50.73(a)(2)(iv)(A), System Actuation	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-2012-001	19 November 2009	10 CFR 50.73(a)(2)(i)(B), Prohibited by 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-2011-001	19 March 2011	10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	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-2007-001	11 April 2007	10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	On March 24, 2007 at 1221, it was discovered during Technical Specification surveillance testing that the Division 2 Emergency Bus 16AB (4.16 kV) feeder breaker 152-1611 from ESF (Engineered Safety Feature) Transformer 12 would open at a 0.35 second time delay upon receipt of a loss of voltage signal. This was contrary to its required Technical Specification 3.3.8.1 Function 1.b allowable value of >/=0.4 and delay. Investigation revealed that the 4.16 kV Emergency Bus 15AA (Division 1) and 16AB (Division 2) loss of voltage protective time delay relays (15AA-162-1, 15AA-162-2, 16AB-162-1, and 16AB 162-2) were set such that their time delay (0.3 seconds) did not allow adequate surveillance testing of the Technical Specification 3.3.8.1 Function 1.b. Loss of Voltage - Time Delay Load Shedding and Sequencing System (LSSS) credited time delay devices (XA22-TD1 and XA22- TD2). The cause has been determined to be a failure to recognize in the original design documents for the ESF Division 1 (15AA) and Division 2 (16AB) Emergency Bus switchgear that the standard protective bus under-voltage device time delay (set at 0.3 second) relays could react faster than the Technical Specification 3.3.8.1 credited LSSS time delay devices.
05000416/LER-2006-001	12 May 2006		This is a Voluntary LER. On May 12, 2006 following a post maintenance test of Division 1 Diesel Generator, both exhaust valves in cylinder head 8L were found to have developed cracks going through the outer lapping tool holes on the valves. One of the valve cracks had propagated to failure. The cracked valves were shipped to an off-site laboratory for analysis. lntergranular Corrosion Cracking was determined to be the cracking mechanism. The root cause of the valve cracking was the valve material highly sensitized austenitic stainless steel. This sensitized valve material in the presence of moisture in the valve head creating sulfurous acid from the residual sulfur in combustion products led to cracking and subsequent failure. The source of the moisture was jacket cooling water leaking through a small crack in the cylinder head. The diesel was repaired and returned to service. An evaluation determined that the diesel could have performed its design function even with one of sixteen cylinders not firing. However, due the importance of communicating this issue to the nuclear industry, GGNS has elected to submit this voluntary LER. �NRC FORM 366A� U.S. NUCLEAR REGULATORY COMMISSION (1-2001) I� NUMBER Grand Gulf Nuclear Station, Unit 1 05000 416 2006 2� OF 5— 001�� — 00�� _
05000416/LER-2005-003	7 October 2005	10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications	The Division I Load Shed and Sequencer power supply was replaced on October 7, 2005 as part of routine preventative maintenance. During a Technical Specification (TS) Surveillance performed on October 25, the as found voltages for the Division I Engineered Safety Features Degraded Voltage set points were found to be higher than the TS Allowable Values. This condition was immediately corrected; however, since the cause of the setpoints being outside the allowed values occurred during the power supply replacement on October 7, the setpoints had been out of the allowable values from October 7 until October 25. TS require that the setpoints be brought to within allowable values within 12 hours or declare the associated emergency diesel generator (EDG) inoperable (which prohibits changing plant operational modes). Since the impact of the power supply replacement on the Bus Under Voltage bistable setpoints was not recognized and the appropriate TS action statement was not entered, the station violated TS 3.0.4 when the plant was brought into Mode 2 on October 16 and again on October 18 when the plant was brought into Model. This condition was determined to be reportable in accordance with 10CFR50.73(a)(2)(i)(B) since the plant was in an Operation or Condition prohibited by TS 3.0.4. There was no loss of safety function since it was limited to a single division and was a deviation in a setpoint. The system would have actuated somewhat earlier on a low voltage transient but would have functioned properly otherwise.
05000416/LER-2005-001	11 February 2005	10 CFR 50.73(a)(2)(iv), System Actuation	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-2004-001	24 February 2004		On 2/24/04 Residual Heat Removal System A was the operating shutdown decay heat removal (DHR) system with the Alternate Decay Heat Removal System (ADHR) as the operable alternate. Division 2 Electrical Bus 16AB was de-energized at 0503 for a planned bus outage. This outage de-energized isolation valves E12- F004C and E12-F064C. These valves must have power or be closed for ADHR to be operable. It was identified at 0630 that these valves were open with their motors de-energized. ADHR was declared inoperable and LCO 1-OTS-04-0015 was entered. Technical Specification (TS) 3.9.9 action A requires verification of an alternate method of decay heat removal (DHR) within one hour for each inoperable required DHR subsystem. ADHR was discovered to be inoperable 1- hour and 27- minutes after the event occurred. This resulted in exceeding the one hour TS time limit. TS 3.9.9 action B was not met due to not meeting the one hour time limit of action A. At 0817 the two valves were closed. ADHR was declared operable and the LCO exited. ADHR remained functional during the event due to installed check valve E12-F031C. This check valve would have prevented flow through the isolation valves. ADHR was inoperable per the SOI, which does not consider the check valve in determining operability. This event is not considered risk significant. There were no safety system functional failures.
05000416/LER-2003-003		10 CFR 50.73(a)(2)(vii), Common Cause Inoperability	On August 16 and 17, 2003, during performance of "Personnel Airlock Door Seal Air System Leak Test: on the outer door of the Upper Containment Airlock, the air system leakage was found to be 2.3 pounds/square inch gauge (psig) in 48 hours, compared to the permissible leakage rate of 2 psig in 48 hours specified in Technical Specification SR 3.6.1.2.4. Preceding the above lest On August 15. 2003. during initial testing on the inner door of the Upper Containment Airlock (BD) Seal System, the air system leakage was recorded to be approximately 81.6 psig in 48 hours. This leakage rate exceeds the permissible leakage rate of 2 psig in 48 hours specified in Technical Specification SR 3.6.1.2.4. In both cases Immediate actions were taken to correct the leakage. The pressure switches for the doors and the "0" ring for the inner door Bevis valve were replaced. The re-test for both doors was successful and the System was declared operable. The repetitive failure of two same types of pressure switches constituted "Common Cause Failure". The event is being reported per 10CFR50.73 (a) (2) (vii) due to a single cause or condition causing two independent trains to become inoperable in a single system designed to control the release of radioactive material. RC FORM 36617.20011 APPROVED BY OMB NO. 3150-0104 EXPIRES 7-31-2004 request: 50 hours. Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Records Management Branch (1-6 E0), U.S. Nuclear Regulatory Commission. Washington. DC 20555-0001. or by Internet e-mail to bjs1i 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 information collection does not display a currently valid OMB control nurnbe , the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection
05000416/LER-2003-002		10 CFR 50.73(a)(2)(iv), System Actuation	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-2002-003	22 June 2002		On June 22, 2002 at approximately 2217, while operating at steady state conditions of 100 percent rated thermal power and 88.7 percent total core flow, a reactor scram occurred on Turbine Control Valve fast closure. It was the result of a ground fault on the secondary (i.e. 34.5 kV side) of Service Transformer 21 Engineered Safety Feature busses 16 and 17 were de-energized. Division 2 and 3 diesel generators started and energized busses 16 and 17, respectively. No Emergency Core Cooling System initiated. A partial loss of plant non-safety power busses occurred. Those powered by Service Transformer 21 were lost, while those powered by Service Transformer 11 remained energized. Important loads lost were both Reactor Recirculation Pumps, and the running Electro-hydraulic Control (EHC) pumps. A third EHC pump auto started on low fluid pressure. Condensate Pumps B and C, and Condensate Booster Pump C tripped due to loss of buss 14AE. N Numerous Division 2 isolations occurred due to loss of 16AB. The lowest reactor level noted during the transient was minus 7 inches, approximately 18 inches below the low level automatic scram setpoint of 11 inches. Auxiliary site power loop was also de-energized. Important loads lost were the Emergency Operations Facility and a partial loss of security lighting. Both Reactor Feed Pumps (RFPs) tripped on low suction pressure about 8 minutes after the scram. One RFP was immediately restored. Safety related control room air conditioner "B" failed to sequence back on after the diesel re-energized buss 16. The air conditioner was started manually.
05000416/LER-2002-002	29 April 2002		During the performance of Residual heat Removal/Low Pressure Coolant Injection System RHR/LPCI-"A" (BO) quarterly functional test in accordance with procedure 06-OP-1E12-Q-0023 it was noted that RHR-A System pressure was higher than normal (approximately 80 psig total pressure). A Investigation of this abnormality revealed that this pressure had existed since the system was last "filled and vented" on April 18, 2002 following maintenance on the system. The pressure source was determined to be P11 (Condensate & Refueling Water Storage and Transfer System) which is used during the "fill and vent" procedure. E12F044A (See "A" in the attached RHR Figure) was found not fully seated which admitted P11 to the system. This valve is an inboard Primary Containment Isolation Valve (PCIV) for penetration 20. The valve was immediately torqued closed upon discovery (April 29, 2002). Technical Specification Limiting Condition of Operation (LCO) 3.6.1.3 states, "Each PCIV shall be OPERABLE". The term Operable/Operability is defined as, "A system, subsystem, division, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety functions(s)". A Based on review of this event, E12F044A was considered inoperable for about 11 days. Therefore, this event is reportable and a 60-day LER is required.
05000416/LER-2002-001		10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown	This is a voluntary LER to provide a follow-up to the Notice of Enforcement Discretion (NOED) received by Grand Gulf Nuclear Station on March 29, 2002. The NOED extended the limiting condition for operation (LCO) time by 72 hours to allow for repair and testing of the diesel generator (DG)(EK) as a result of the jacket water temperature switch failures. The NOED was invoked at 0402 on March 29th to avoid commencing a Technical Specification (TS) required shutdown. Although the NOED was used to avoid the commencement of a plant shutdown, the Division 2 DG was restored to operable status in time to preclude a reportable condition. The Division 2 DG was declared inoperable on March 26, 2002 at 0402 for planned maintenance. During the planned maintenance, various problems occurred such as infant mortality failure of some of the process sensors that caused the DG to remain inoperable. Along with the infant mortality switch failure, the equipment tagging and re-tagging issues and the limited contingency planning resulted in a planned outage time of 46 hours extending into excess of the 72-hour allowed LCO. A root cause determination was performed with the resultant root cause identified as job performance standards not adequately defined. Condition Report, CR-GGN-2002-00555 was written to address exceeding the 72-hour LCO and will address the corrective actions to prevent recurrence of this type event.
05000416/LER-2001-004			General Electric (GE) recently provided information related to methodology used to calculate core thermal power (CTP). On October 3, 2001, GGNS performed an evaluation which identified the potential for an error related to moisture carryover. GGNS had applied the generic moisture carryover assumption provided by GE and currently uses 0.1 percent for the moisture carryover fraction in the CTP. GE now recommends a value of 0.0 percent be used. Changing the fraction to 0.0 percent results in an increased calculated CTP of 0.082 percent (3.1MWt). Further evaluation by GE revealed that an older version of steam table data was used to calculate the saturated steam enthalpy. As a result, GGNS unknowingly operated at a core power level slightly in excess of the CTP limit (3833 megawatts thermal). Such operation was in violation of Operating License (OL) Condition 2.0 (1) and is being reported pursuant to OL Condition 2.F. Immediate actions were to administratively limit reactor CTP to account for the error in the calculated CTP. Programs/procedures were revised to assume a 0.0 percent moisture carryover value in the plant calorimetric heat balance. The GE report stated the error in CTP, although non-conservative, does not represent a safety issue. Therefore, this condition was of minimal safety consequence and the health and safety of the general public were not compromised. FACILITY NAME (1) LER NUMBER (6) DOCKET (2) PAGE (3) Attachment 2 to GNRO-2001/00093
05000416/LER-1998-004, Forwards Corrected Copy of LER 98-004-00 to Include Page 1 of 4.LER Discusses Containment Penetration Being Opened Contrary to Ts,Per Requirements of 10CFR50.73	24 July 1998
05000416/LER-1997-003, Forwards LER 97-003-01 Re CR Envelope Leakage Potentially Exceeding License Condition 2.C(38) Limit	30 September 1997
05000416/LER-1996-002, Forwards LER 96-002-00 Re Routine Maint Rendering HPCS EDG Inoperable	26 February 1996
05000416/LER-1994-002, Forwards LER 94-002-02.Revises Reportable Status of This LER to Voluntary Which Is Reinforced by NUREG 1022	28 June 1996
05000416/LER-1993-011, Corrected LER 93-011-00:on 931007,loss of Shutdown Cooling & ESF Actuation Occurred.Caused by Operator Error.Event Discussed W/Operations Personnel & Info Labels Placed on Inverter Panels at Power Supply Switch	8 November 1993
05000416/LER-1993-007	26 August 1993
05000416/LER-1993-006	20 August 1993
05000416/LER-1993-003	12 August 1993
05000416/LER-1990-008	20 June 1990

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