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| Start date | Reporting criterion | Event description | |
|---|---|---|---|
| 05000458/LER-2013-002 | 19 September 2013 | 10 CFR 50.73(a)(2)(v), Loss of Safety Function | On September 19, 2013, at approximately 1437 CDT, with the plant operating at 100 % power, a door in the secondary containment pressure boundary was left unsecured by an employee entering the building. Upon closing the door, the employee mistakenly rotated the handwheel slightly, caused the latch bolts to extend partially. The latch bolts then contacted the outside of the keepers in the door frame, blocking the door open. The employee did not notice that the door was slightly open when he rotated the handwheel to the "closed" position, and then did not properly confirm its security prior to leaving the area. A security officer responded to the resultant alarm, and fully closed the door approximately four minutes later. This event was caused by improper use of human performance techniques by the employee, in that he failed to confirm that he had operated the door correctly. This event is being reported in accordance with 10 CFR 50.73(a)(2)(v) as a condition that could have caused the loss of the safety function of the secondary containment pressure boundary. Since the plant's safety analysis does not assume the function of secondary containment for the first 30 minutes of the design basis accident, safety function was actually maintained. This event was of minimal significance with regard to the health and safety of the public. |
| 05000458/LER-2014-001 | 9 January 2014 | 10 CFR 50.73(a)(2)(ii)(B), Unanalyzed Condition | On January 9, 2014, with the plant operating at 100 percent power, the final review of industry operating experience regarding the adverse effects of unfused direct current ammeter circuits in the main control room determined the described condition to be applicable to River Bend Station, resulting in a potentially unanalyzed condition with respect to 10 CFR 50 Appendix R analysis requirements. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(ii)(B). Interim compensatory measures have been implemented. This condition has existed since the plant was constructed. Neither the original design criteria nor any industry standards in effect at the time accounted for the possibility of the multiple short-to-ground failure mode and therefore, did not require overcurrent protection for remote ammeter circuits. This condition was documented in the station's corrective action program. Compensatory measures were established to restore margin potentially reduced by postulated fire scenarios. The compensatory actions credit operator presence in the plant for maintaining heightened awareness and taking action to minimize fire hazards. Compensatory actions are incorporated in pertinent operating procedures. The compensatory actions remain in effect. There have been no actual adverse safety consequences resulting from the reported condition. The administrative controls of the fire protection program, the availability of fire detection and suppression systems, and a trained on-site fire brigade all combine to make it highly unlikely that a fire could occur and progress in a manner that actually leads to the event postulated in this scenario. |
| 05000458/LER-2014-002 | 17 October 2014 | 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(iv), System Actuation | On October 17, 2014, at approximately 3:03 a.m. CDT, a reactor scram occurred in response to a high neutron flux signal from the average power range monitors (APRMs). The plant was operating at 100 percent power at the time. Immediately prior to that signal, an apparent malfunction in the main turbine electro-hydraulic control (EHC) system caused both the main turbine steam bypass valves to fully open, and also commanded all four main turbine control valves to close. The resulting increase in reactor steam pressure caused reactor power to immediately rise to the trip setpoint of the APRMs, at which point the actuation of the reactor protection system (RPS) occurred. After the scram occurred, an operator in the auxiliary control room erroneously removed all the main condensate system demineralizers from service, isolating condensate flow to the suction header of the main feedwater pumps. The running feedwater pump tripped on low suction pressure. The mis-operation of the demineralizer system was promptly corrected, and the main feedwater system was restored to service. The cause of the EHC malfunction has not been determined. Potential failure points were identitied, and those circuitry parts were replaced. A human performance error review was conducted regarding the mis-operation of the condensate deminerlizers, and appropriate procedure revisions have been made. This event is being reported in accordance with 10CFR50.73(a)(2)(iv) as an automatic actuation of the RPS system, and in accordance with 10CFR50.73(a)(2)(v) as a condition that potentially caused the loss of safety function of the affected RPS instruments. |
| 05000458/LER-2014-003 | 10 June 2014 | 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability 10 CFR 50.73(a)(2)(i)(b) 10 CFR 50.73(a)(2)(i) | On June 10, 2014, with the plant operating at 100 percent power, technicians performing a scheduled surveillance test found that one instrument channel in the reactor protection system failed its time response acceptance criterion. This was the second of two such tests that failed in similar fashion. Since it is conceivable that the second tested channel was out of specifications at the time the first channel was tested, this condition caused independent redundant channels in the same trip system to be inoperable at the same time. The actions required by the applicable Limiting Condition for Operation were not taken since the operators were not aware of the latent condition at the time of the first surveillance test failure. An engineering evaluation of this condition was performed, and the RPS system was declared operable with compensatory measures. Until this issue is resolved, the frequency of the calibration tests in the channels with Agastat relays has been increased to once per year. This condition is reportable in accordance with 10CFR50.73(a)(2)(i) (b) as operations prohibited by Technical Specifications, as well as 10CFR50.73(a)(2)(vii), a potential common-cause inoperability of independent trip channels. Due to the design redundancy of the independent channels of the RPS system, this condition would likely have not prevented the system from performing its safety function. Had an actual full MSIV isolation occurred with the channel response times in their as-found condition, the reactor scram signal would likely have still occurred within the specified instrument response time. |
| 05000458/LER-2014-004 | 30 July 2014 | On July 30, 2014, with the plant operating at 100% power, a review of an engineering analysis of the ultimate heat sink (UHS) determined that the UHS was in an unanalyzed condition that degraded plant safety. This condition was the result of a design basis deficiency for the UHS that did not account for the adverse effects of system leakage on compliance with the 30-day inventory required by Regulatory Guide 1.27. The system design basis requires that 30-day inventory be maintained, with the assumption that no replenishment of the UHS inventory occurs for the entire duration of the postulated event. In support of the development of the engineering analysis, compensatory measures have been implemented which provide adequate assurance that the UHS will perform its design safety function. Corrective actions to restore full compliance with design basis requirements are in development. This event is being reported in accordance with 10 CFR 50.73 (a)(2)(ii) as an unanalyzed condition that degrades the safety function of the UHS. | |
| 05000458/LER-2014-005 | 1 August 2014 | 10 CFR 50.73(a)(2)(v), Loss of Safety Function | On August 1, 2014, at approximately 9:42 p.m. CDT, with the plant operating at 100 percent power, the high pressure core spray (HPCS) system was declared to be inoperable as a result of an engineering evaluation of an apparent leakage path through a part of the system. The evaluation determined that, should the HPCS system be initiated in response to a design basis event, the leakage path through a pump test return line to the condensate storage tank (the symptoms of which were first seen on July 12) could potentially cause the suppression pool inventory to be depleted to the extent that the pool would not support its 30-day mission time assumed in the station's accident analysis. Operators closed the HPCS pump suction valve at the suppression pool on August 1, resulting in the inoperability of the system. This event is being reported in accordance with 10 CFR 50.73(a)(2)(v) as a condition that defeated the safety function of the the HPCS system. A subsequent evaluation confirmed that, had the HPCS system actuated in response to a design basis event, the leakage through the pump test return line would have depleted the suppression pool inventory before the completion of its 30-day mission time. Regarding the suppression pool, this event constituted operations prohibited by Technical Specifications (10 CFR 50.73 (a)(2)(i)(b)), as well as a condition that defeated the safety function of the suppression pool (10 CFR 50.73 (a)(2)(v)). A blind flange was installed in the pump test return line to the condensate storage tank in order to isolate the leakage path, and the 1-IPCS system was restored to an operable status on August 5. Repairs on the test return line isolation valves are scheduled. |
| 05000458/LER-2014-006 | 25 December 2014 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On December 25, 2014, at 0836 CST, a reactor scram occurred while the plant was operating at approximately 85 percent power. This event resulted from the loss of power on the Division 2 reactor protection system (RPS) bus, in conjunction with a pre-existing half- scram on Division 1. The loss of Division 2 RPS power also resulted in a Division 2 containment isolation signal. Approximately four minutes after the scram, reactor water level increased to the Level 8 setpoint, causing the running main feedwater pump to trip. As reactor water level decreased back through the normal operating range, operators attempted to re-start main feedwater pump "C," but its supply breaker failed to close. Main feedwater pump "A" was subsequently returned to service. As reactor water level decreased to the point at which the startup feedwater regulating valve (FRV) should have opened to establish automatic control, the valve failed to open. Attempts to open it with a manual input signal were unsuccessful, and the "C" main FRV was put back into service. By that time, reactor water level had decreased slightly below the Level 3 RPS actuation setpoint, resulting in a second scram signal. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an automatic actuation of the RPS system and the primary containment isolation logic. No plant parameters required the actuation of any standby diesel generators or emergency core cooling systems. No reactor safety-relief valves actuated. This event was of minimal safety significance with respect to the health and safety of the public. |
| 05000458/LER-2015-001 | 18 February 2015 | 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On February 18, 2015, while the plant was operating at approximately 98% power, it was discovered that four local leak rate surveillance test procedures each contained a similar error that resulted in an improper test configuration. This deficiency in each procedure erroneously required the closure of the respective motor-operated valve in the packing leak-off line for the outboard main steam isolation valve (MSIV) being tested, when the proper test configuration would require the valve to be open. The net effect of the error was to partially negate the effectiveness of a surveillance test required by Technical Specifications. This condition had existed since the procedures were revised in 1992 to add valve lineup checklists. The incorrect valve position for the subject test procedures was caused by lack of attention to detail when the procedures were developed. An assessment of the effects of the procedure error was conducted, and reasonable assurance was established that the safety function of the outboard MSIVs was not compromised by this condition. The procedures were corrected, and the tests were successfully conducted in the recent refueling outage. This condition is being reported in accordance with 10CFR50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications. |
| 05000458/LER-2015-001, Operations Prohibited by Technical Specifications Due to Deficient Local Leak Rate Test Procedures Containing Erroneous Valve Alignments | 18 February 2015 | 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On February 18, 2015, while the plant was operating at approximately 98% power, it was discovered that four local leak rate procedure erroneously required the closure of the respective motor-operated valve in the packing leak-off line for the outboard main steam isolation valve (MSIV) being tested, when the proper test configuration would require the valve to be open. The net effect of the error was to partially negate the effectiveness of a surveillance test required by Technical Specifications. This condition had existed since the procedures were revised in 1992 to add valve lineup checklists. The incorrect valve position for the subject test procedures was caused by lack of attention to detail when the procedures were developed. An assessment of the effects of the procedure error was conducted, and reasonable assurance was established that the safety function of the outboard MSIVs was not compromised by this condition. The procedures were corrected, and the tests were successfully conducted in the recent refueling outage. This condition is being reported in accordance with 10CFR50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications. |
| 05000458/LER-2015-002 | 7 March 2015 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(iv), System Actuation | On March 7, 2015, at 9:40 p.m., while the plant was in cold shutdown, power from the reserve station service line no. 2 to the Division 2 onsite electrical distribution system was lost. The Division 2 diesel generator (EDG) received an automatic start signal due the under- voltage condition on the 4160v bus, but did not start since it was out of service for scheduled maintenance. The Division 2 standby service water pumps were operating at the time for scheduled testing, and subsequently shut down when power was lost. The investigation team concluded that electricians must have made contact with the sudden-pressure trip circuitry wires while working in the cabinet on the reserve station service transformer "D". The apparent cause of this event was inadequate work practices on the part of the electricians, in that they did not take all available precautions prior to performing the voltage check. The workers recognized the adverse conditions, but did not recognize the need to put into place any robust barriers. The electricians' successful past performance of this type of task likely led to overconfidence. Reviewers of the work package didn't challenge the potential risks or identify a most error-likely task. The EDG start logic responded as designed to the loss of power on the Division 2 electrical systems. This event did not involve any interruption of the shutdown cooling function. This event was, thus, of minimal safety significance with respect to the health and safety of the public. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a valid actuation of the EDG starting logic. |
| 05000458/LER-2015-002, Operations Prohibited by Technical Specifications Due to Deficient Local Leak Rate Test Procedures Containing Erroneous Valve Alignments | 18 February 2015 | 10 CFR 50.73(a)(2)(iv), System Actuation | On March 7, 2015, at 9:40 p.m., while the plant was in cold shutdown, power from the reserve station service line no. 2 to the Division 2 onsite electrical distribution system was lost. The Division 2 diesel generator (EDG) received an automatic start signal due the under-voltage condition on the 4160v bus, but did not start since it was out of service for scheduled maintenance. The Division 2 standby service water pumps were operating at the time for scheduled testing, and subsequently shut down when power was lost. The cabinet on the reserve station service transformer "D". The apparent cause of this event was inadequate work practices on the part of the electricians, in that they did not take all available precautions prior to performing the voltage check. The workers recognized the adverse conditions, but did not recognize the need to put into place any robust barriers. The electricians' successful past performance of this type of task likely led to overconfidence. Reviewers of the work package didn't challenge the potential risks or identify a most error-likely task. The EDG start logic responded as designed to the loss of power on the Division 2 electrical systems. This event did not involve any interruption of the shutdown cooling function. This event was, thus, of minimal safety significance with respect to the health and safety of the public. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a valid actuation of the EDG starting logic. |
| 05000458/LER-2015-003 | 14 May 2015 | 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 May 14, 2015, with the plant operating at 100 percent power, a manual valve in the Division 2 penetration valve leakage control (LSV) subsystem was found out of position. Subsequent investigation concluded that this condition had existed since before the plant was started up from a refueling outage on March 26, 2015, causing that subsystem to be inoperable for a period greater than the 30-day allowable outage time in Technical Specifications. The valve (SWP-V912) is in the service water supply to the air compressor on that skid. The mispositioning of the valve was caused by an error in equipment configuration control. Additionally, the investigation determined that, during the intervening period, there were two short planned outages of the Division 1 subsystem. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications, as well as 10 CFR 50.73(a)(2)(v)(C) as a loss of the LSV safety function during those periods when the Division 1 subsystem was out of service. The two periods during which the Division 1 LSV subsystem was inoperable totaled approximately 7.5 hours. Otherwise, it was capable at all other times to perform the design safety function. At no time during the period from plant startup on March 26 until the Division 2 subsystem was restored to an operable status was there an actual demand for the system to operate. This event was thus of minimal significance to the health and safety of the public. |
| 05000458/LER-2015-003, Operations Prohibited by Technical Specifications and Loss of Safety Function Due to Inoperability of Division 2 Containment Penetration Leakage Control System | 14 May 2015 | 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 | (LSV) subsystem was found out of position. Subsequent investigation concluded that this condition had existed since before the plant was started up from a refueling outage on March 26, 2015, causing that subsystem to be inoperable for a period greater than the 30-day allowable outage time in Technical Specifications. The valve (SWP-V912) is in the service water supply to the air compressor on that determined that, during the intervening period, there were two short planned outages of the Division 1 subsystem. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications, as well as 10 CFR 50.73(a)(2)(v)(C) as a loss of the LSV safety function during those periods when the Division 1 subsystem was out of service. The two periods during which the Division 1 LSV subsystem was inoperable totaled approximately 7.5 hours. Otherwise, it was capable at all other times to perform the design safety function. At no time during the period from plant startup on March 26 until the Division 2 subsystem was restored to an operable status was there an actual demand for the system to operate. This event was thus of minimal significance to the health and safety of the public. |
| 05000458/LER-2015-005 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On June 1, 2015, at 9:09 p.m. CDT, with the plant operating at 90 percent power, an unplanned automatic reactor scram occurred due to low reactor water level. This event resulted from the loss of a non-safety related instrument power panel, apparently caused by an internal electrical transient in a 125-volt AC / DC inverter. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as the automatic actuation of the reactor protection system. All reactor control rods inserted normally, and control of reactor parameters was promptly established using the main turbine bypass valves and the main feedwater system. An expected general containment isolation signal occurred when reactor water level decreased to Level 3. The "A" reactor recirculation pump shifted to slow speed as designed, while the "B" pump tripped off. The runback feature of the reactor recirculation flow control valves failed to operate due the loss of instrument power. No plant parameters requiring the actuation of the emergency diesel generators, the main steam safety-relief valves, or the emergency core cooling systems were exceeded. This event was, thus, of minimal safety significance to the health and safety of the public. | |
| 05000458/LER-2015-006 | 17 July 2015 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On July 17, 2015, with the plant operating at 92 percent power, it was determined that an operability evaluation previously performed for a safety-related instrument in the primary containment isolation circuitry was in error, which resulted in the failure to take actions required by the Technical Specifications. On July 8, 2015, a scheduled surveillance test was performed on one channel of the primary containment isolation logic. During the test, an error message was displayed on the associated trip unit. The operators and technicians researched the vendor manual, consulted the cognizant engineers, and determined that the error message was not indicative of any inability of the system to perform its design safety function. Subsequent review found that the first operability determination on the condition report was in error, and that the trip channel was not actually capable of performing as designed. The trip unit was declared inoperable, and taken out of service to be replaced. The channel was again declared operable on July 18 at 2:44 a.m. The elapsed time between the receipt of the error message on July 8 and the restoration to an operable status exceeded the allowable outage time of Technical Specifications. The cause of the error in the first operability determination was the use of an outdated vendor manual for the initial troubleshooting. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications. During the time that the trip unit was inoperable, redundant channels in the isolation logic remained capable of performing the safety function. This event was, thus, of minimal safety significance to the health and safety of the public. |
| 05000458/LER-2015-007 | 17 November 2015 18 January 2016 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | On November 17, 2015, at 11:55 p.m. CST, with the plant operating at 71 percent power, the high pressure core spray system (HPCS) was declared inoperable following the failure of the operating chiller in the Division 1 control building ventilation (HVK) system. HVK' chiller "C" was in service when the building operator found a freon leak in the system. The leakage was determined to be of such magnitude as to cause the chiller to be inoperable, and the operators took action to shift the building cooling loads to the standby Division 2 chiller. Maintenance technicians disassembled the service water flow control valve on the chiller, and found that the cause of the freon leak was failed rubber diaphragm in the valve actuator. No positive identification of the failure mode of the diaphragm could be made, so it was shipped to the valve vendor for further analysis. This condition potentially caused the HPCS system to be incapable of performing its safety function, and is, thus, reportable in accordance with 10 CFR 50.73(a)(2)(v)(D). The maximum time needed to perform the chiller realignment has been conservatively estimated to be 76 minutes. Calculations have determined temperatures in the Division 3 equipment rooms will remain below the 122F limit of the equipment for at least 24 hours. This event had no actual adverse effect on the ability of the Division 3 HPCS electrical system to perform its design safety function since there was more than sufficient time to align the other chiller in the same division to provide control building switchgear room cooling. |
| 05000458/LER-2015-008 | 19 November 2015 18 January 2016 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | On November 19, 2015, at 7:24 a.m. CST, with the plant operating at 97 percent power, the high pressure core spray system (HPCS) was declared inoperable following the failure of the operating chiller in the Division 2 control building ventilation system (HVK). Chiller "D" was in service when the building operator found an oil leak on that machine. The chiller subsequently tripped on low oil pressure. The "A" chiller in the Division 1 subsystem automatically started as designed. The loss of cooling to the various equipment rooms in the control building requires that the supported equipment in those areas be declared inoperable. The Technical Specifications for the Division 3 DC distribution system requires that the HPCS system be immediately declared inoperable. This condition potentially causes the HPCS system to be incapable of performing its safety function. Maintenance technicians identified the source of the oil leak as a failed seal on the compressor drive shaft. The apparent cause of the seal failure was the age-related degradation of a setscrew holding one of the rotating elements of the seal, allowing it to get out of position and disrupt the integrity of the seal face. In this event, the "A" chiller automatically started as designed, and it was confirmed to be operating correctly within 10 minutes. The HVK system continued to support the safety function of Division 3 electrical equipment after chiller trip, since the time required to restore an operable chiller is significantly less than the time limit for restoration of equipment room cooling. This event had no actual adverse effect on the ability of the Division 3 HPCS electrical system to perform its design safety function since there was more than sufficient time to align the other chiller in the same division to provide control building switchgear room cooling. This event, thus, did not constitute an actual loss of the ability of the HPCS system to perform its design safety function. |
| 05000458/LER-2015-009 | 27 November 2015 26 January 2016 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On November 27,2015, at 4:31 a.m. CST, with the plant operating at 100 percent power, an automatic reactor scram occurred following the loss of power to both divisions of the reactor protection system (RPS). This condition resulted from a single-phase fault in the local 230kV switchyard. The initial response of the protective relays for the switchyard caused the breakers connected to the north 230kV bus in the switchyard to trip. The fault caused a voltage transient on the in-plant switchgear sufficient to trip the scram relays in the Division 2 RPS, resulting in a half-scram. The action of the protective relays continued, eventually causing the de-energization of reserve station service line no. 1. This lead to the loss of Division 1 RPS and a full reactor scram. The Division 1 and 3 emergency diesel generators started as designed to restore power to their respective safety-related onsite electrical distribution subsystems. No safety-related systems were out of service at the time of the scram, and reactor pressure and water level were promptly stabilized. All reactor control rods inserted properly. Multiple actuations of the main steam safety-relief valves (SRVs) occurred during the event. The nuclear steam supply system vendor reported this action was likely due to a localized pressure transient in the SRV instrumentation lines. SRV tailpipe temperature recorders indicated that all valves re-seated correctly following the initial transient. The cause of the event was an animal-induced fault in the 230kV switchyard that resulted in the automatic trip of the north bus feeder breaker to the RSS No. 1. The fault also caused the south bus feeder breaker to trip, de-energizing RSS No. 1. |
| 05000458/LER-2015-010 | 11 December 2015 8 February 2016 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | On December 11, 2015, at 4:16 a.m. CST, with the plant operating at 83 percent power, the high pressure core spray system (HPCS) was declared inoperable following the failure of the operating chiller in the Division 2 control building ventilation system (HVK). Chiller "D" was in service when it tripped automatically due to a high bearing temperature signal. The "C" chiller in the Division 1 subsystem automatically started as designed, and was confirmed to be operating correctly within approximately 5 minutes. The Technical Specifications for the Division 3 DC distribution system requires that the HPCS system be immediately declared inoperable. This condition potentially causes the HPCS system to be incapable of performing its safety function. The investigation determined that, during a recent corrective maintenance activity, too much oil was added to the chiller prior to its return to service. A subsequent load increase on the chiller caused excess oil to migrate into the compressor sump, where it contributed to the high bearing temperature condition. The HVK system continued to support the safety function of Division 3 electrical equipment after chiller trip, since the time required to restore an operable chiller is significantly less than the time limit for restoration of equipment room cooling. This event had no actual adverse effect on the ability of the Division 3 HPCS electrical system to perform its design safety function since there was more than sufficient time to align the other chiller in the same division to provide control building switchgear room cooling. This event, thus, did not constitute an actual loss of the ability of the HPCS system to perform its design safety function. |
| 05000458/LER-2016-001 | 5 January 2016 7 March 2016 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v)(C), Loss of Safety Function - Release of Radioactive Material | On January 5, 2016, at 10:58 p.m. CST, with the plant operating at 100 percent power, the main control room alarm indicating high pressure in the auxiliary building actuated. Operators confirmed that the building pressure was out of specification. Secondary containment was declared inoperable, and the Division 2 standby gas treatment system was started. This action restored building pressure to the acceptable range, and secondary containment was declared operable at 12:27 a.m. on January 6. An inspection of the auxiliary building normal ventilation system found that discharge dampers on the exhaust fans were degraded, and the flow control damper on the supply fans was not operating correctly. In order to restore the normal ventilation system to service, the troubleshooting plan for this condition temporarily altered the operating configuration of the system to close the suction damper on the idle exhaust fan. This prevents backflow through the idle fan, allowing the system to control building pressure within the required operating range. Corrective maintenance is being planned to restore the material condition of the normal ventilation system. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(C) as an event that caused the secondary containment to be potentially incapable of performing its safety function. , |
| 05000458/LER-2016-002 | 9 January 2016 7 March 2016 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(iv), System Actuation | On January 9, 2016, at approximately 2:37 a.m. CST, with the plant operating at 100 percent power, an automatic reactor scram occurred concurrent with the closure of all main steam isolation valves (MSIVs). That action was the result of an electrical transient caused by a phase-to-phase fault on a nearby 230kV transmission line. The transient caused a momentary decrease in the voltage on both reactor protection system busses, which also power the MSIV control solenoids. The Division 2 primary containment isolation logic was also actuated, causing the Division 2 valves in balance-of-plant systems to close. Both divisions of the standby gas treatment system automatically started due to the shutdown of the normal annulus pressure control system. Both reactor recirculation pumps downshifted to slow speed. The company's transmission department investigated the event. Although no definite source of the fault was found, it was concluded that a lightning strike likely caused the transient. The fault occurred on a 230kV transmission line approximately three miles from the station. The fault lasted for 5.4 cycles before it was isolated by automatic breaker action, and caused the voltage on the switchgear supplying the RPS busses to decrease to approximately 34 percent of normal. This transient was sufficient to trip the scram solenoids and the MSIV solenoids. No plant parameter limits requiring the automatic actuation of any of the emergency core cooling systems or the emergency diesel generators were exceeded. This event, thus, was of minimal significance to the health and safety of the public. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv) as an actuation of the reactor ( protection system and the primary containment isolation logic. . |
| 05000458/LER-2016-003 | 19 January 2016 8 June 2017 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On January 19, 2016, at 5:28 a.m. CST, while conducting core alterations, an alarm was actuated in the main control room alarm indicating that a reactor control rod had drifted out of the fully inserted position. At the time, a fuel bundle was being raised out of the core, and the control rod in the same cell drifted out one notch with no "withdraw" command present. This condition actuated a corresponding alarm on the refueling platform, and system interlocks stopped the platform hoist with the fuel bundle partially withdrawn. When the control rod moved from the fully inserted position, the Technical Specification applicability for the intermediate range neutron monitoring system was inadvertently entered, while a certain function of those instruments was not operable. This event constituted operations prohibited by Technical Specifications, and is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B). After a detailed assessment of the situation, the fuel bundle and the control rod were returned to their original positions. The drive mechanism for the control rod has been disabled, and the control rod will remain fully inserted for the remainder of the current fuel cycle. The causal analysis for this event will be completed when the control rod can be removed for inspection during the next refueling outage. The results of that investigation will be provided in a supplement to this report. |
| 05000458/LER-2016-004 | 29 January 2016 29 March 2016 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On January 29, 2016, at 1518 CST, with the plant in cold shutdown, power was lost on reserve station service (RSS) line no. 1. This is one of two sources of offsite power required by Technical Specifications. The power loss de-energized the Division 1 onsite AC safety.- related switchgear, causing an automatic start of the Division 1 emergency diesel generator (EDG). The Division 1 reactor protection system (RPS) bus was also de-energized, causing a half-scram signal. Approximately 8 minutes later, a full actuation of the RPS occurred due to high water level in the control rod drive hydraulic system scram discharge volume header. All reactor control rods were already fully inserted. The loss of Division 1 RPS also caused the actuation of the Division 1 primary containment isolation logic. The Division 1 isolation valves in the balance-of-plant systems closed as designed. Both trains of the standby gas treatment system actuated. The loss of RSS No. 1 was caused when company transmission department personnel working in the local 230kV switchyard executed a deficient work instruction while modifying relay settings. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as the automatic actuation of the Division 1 EDG, the Division 1 primary containment logic, and the reactor protection system (while subcritical). At the time of the event, the shutdown cooling system was operating on the Division 2 subloop, which was unaffected. The Division 1 EDG performed as designed. This event was, thus, of minimal significance to the health and safety of the public. |
| 05000458/LER-2016-005 | 24 February 2016 | On February 24, 2016, with the plant in cold shutdown, the operations shift manager was made aware of a notification regarding a certain model of Masterpact 480-volt circuit breakers that described a failure mode that could potentially prevent the automatic closure of the breakers. Assessment of this information determined that the susceptible breakers included those powering the emergency ventilation fans in the Division 1 and 2 emergency diesel generator rooms and two auxiliary building unit coolers. This condition required that both diesel generators and both trains of shutdown cooling and to be declared inoperable. This constituted a condition that could potentially prevent fulfillment of the safety function of onsite AC power sources and decay heat removal. The Division 2 residual heat removal loop was operating in shutdoWn cooling, satisfactorily maintaining reactor coolant temperature. The cause of the event is that station personnel failed to recognize the breakers' vulnerability to this failure mode. This directly resulted in the failure to take corrective action prior to this industry notification. The cause of the untimely corrective actions is that the breakers were incorrectly determined to be operable in 2014 when the condition was discovered. All the affected breakers were modified to eliminate the failure mode prior to the subsequent plant startup. | |
| 05000458/LER-2016-006 | 13 May 2016 12 July 2016 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | At 1200 CDT on May 13, 2016, while the plant was operating at 100 percent power, the shift manager was notified of a design inadequacy that could potentially prevent both divisions of the standby gas treatment system (GTS) from performing its design function. Under certain specific conditions, the 480-volt circuit breakers supplying the GTS fans may not re-close following a trip signal. In the postulated condition in which a start signal is followed by an immediate (within 0.075 seconds) trip signal, the breaker could fail to close at the next attempt. As a result of this condition, both divisions of GTS were declared inoperable. The initial investigation of this condition determined that circuit breakers in the main control building air conditioning system (HVC) and the diesel generator building ventilation system (HVP) are also susceptible to this postulated failure mechanism. This defect has the potential to similarly cause the HVC and HVP systems to be incapable of performing their safety function. The affected circuit breakers in those systems have been modified to correct the deficiency. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) and (a)(2)(v)(D) as operations prohibited by Technical Specifications and an event that could have caused a loss of safety functions of the affected systems. The specific scenario in which this failure mechanism could plausibly have occurred is a highly unlikely event. Additionally, standing _ orders were already in place at the time of this -event that directed the operators to take compensatory actions to preserve the safety function of the affected systems. Those orders will remain in effect until all modifications are complete. Thus, this condition does not represent a significant challenge to the health and safety of the public. |
| 05000458/LER-2016-007 | 25 May 2016 25 July 2016 | On May 25, 2016, it was determined that there had been a violation of Technical Specifications during a recent planned maintenance outage of the Division 1 diesel generator (DG). During that outage, three material deficiencies of various subcomponents were discovered while conducting maintenance tasks. The initial operability screening of each deficiency determined that the as-found condition did not, by itself, cause the DG to be inoperable. However, the associated condition report for each item was flagged as "inoperable." These determinations should have, thus, caused the operators to invoke the requirements of the TS to perform common cause evaluations to assure that the same conditions did not exist on the operable Division 2 DG. This action was not performed. Human performance evaluations of the operators involved in the condition report screening concluded that a cognitive, undocumented decision was made that the individual deficiencies did not meet the threshold of requiring a common cause evaluation. This event constituted operations prohibited by Technical Specifications, and is being reported in accordance with 10 CFR 50.73 (a)(2)(i)(B). The investigation of this event discovered a previous similar occurrence during a planned maintenance outage of the Division 2 DG in February 2014 which constituted operations prohibited by Technical Specifications, but which was not reported at the time. That event was later determined to have not defeated the safety function of the DG, and was, thus, of minimal significance with respect to the health and safety.of the public | |
| 05000458/LER-2017-001 | 31 January 2017 3 April 2017 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | During a refueling outage that commenced on January 28, 2017, there were occasions during which maintenance was performed without taking the required actions to comply with the applicable Technical Specifications. Specifically, operations with a potential to drain the reactor vessel (OPDRVs) were conducted without establishing primary containment integrity, and the provisions of NRC Enforcement Guidance Memorandum (EGM) 11-003, Rev. 3, were invoked instead. The first such operation was commenced on January 31, and the final OPDRV was completed on March 4. This condition is being reported in accordance with 10 CFR 50.73(a)(2) (i)(B) as operations prohibited by Technical Specifications. During all OPDRVs, the prerequisites specified by the EGM were enforced. All activities were completed with no transients in reactor cavity water level having occurred. This event was, thus, of minimal safety significance with regard to the health and safety of the public. On December 20, 2016, NRC approved a generic Technical Specification amendment that can be used by licensees to reconcile this condition. It is required by the EGM that applicable licensees (including River Bend Station) must submit a request for this amendment by December 20, 2017. |
| 05000458/LER-2017-002 | 18 February 2017 18 April 2017 | 10 CFR 50.73(a)(2)(ii)(B), Unanalyzed Condition 10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.73(a)(2)(v), Loss of Safety Function | On February 18, 2017, at 3:37 p.m. CST, while a refueling outage was in progress, the operators were shifting subsystems of the main control building ventilation system. The Division 2 "B" chiller had been in service, and it was intended to start the Division 1 "C" chiller to facilitate the outage work schedule. After the swap, operators noted that the air flow was abnormally low, and within approximately four minutes, the "C" chiller tripped. The operators were unsuccessful in attempts to restore the Division 2 subsystem to service;and the abnormal operating procedures for the loss of control building ventilation were then implemented. The electrical distribution subsystems in the control building were declared inoperable due to the loss of the ventilation system. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(v)(A). As described in the causal analysis, a circuit breaker manufacturing defect that violated the single failure requirements of 10 CFR 50 Appendix A, General Design Criteria, was discovered. This is being reported in accordance with 10 CFR 50.73(a)(2)(ii)(B) as an unanalyzed condition. During the restoration of the ventilation system, main control room temperature increased from approximately 73F to 81F as recorded in the operator's logs. No high temperature alarms from the electrical equipment rooms actuated. Thus, this event was of minimal significance to the health and safety of the public. |
| 05000458/LER-2017-003 | 10 March 2017 9 May 2017 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On March 10, 2017, at approximately 7:14 a.m. CST, the reactor operator manually actuated a reactor scram in response to an abnormal increase in steam pressure. Reactor power was approximately 15 percent at the time. The turbine generator had been synchronized to the grid at 5:13 a.m. on March 10, and was being closely monitored by engineers and operators since a major modification to the turbine electro-hydraulic control (EHC) system had been installed during the recent refueling outage. Approximately 45 minutes prior to the manual scram, a main control room alarm actuated indicating a problem with the EHC system. A few minutes later, it was reported from the turbine building that there was a steam leak in the area of the EHC steam pressure transmitters. Shortly thereafter, reactor pressure began to increase with no demand signal present, at which time the reactor operator initiated the scram. The main feedwater system remained in service, and reactor water level control performed normally as designed. No reactor safety-relief valves actuated. The main turbine bypass valves did not open following the shutdown, and engineering review determined this condition was consistent with the response to the abnormal configuration of the EHC system pressure transmitters created by efforts to isolate the leak locally. Approximately five minutes after the scram, the outboard main steam isolation valves were manually closed to limit the reactor cooldown rate. This event resulted from the incorrect installation of a new compression fitting in the steam pressure instrumentation tubing for the main turbine control system. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a manual actuation of the reactor protection system. |
| 05000458/LER-2017-004 | 23 March 2017 22 May 2017 | 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.73(a)(2)(v)(C), Loss of Safety Function - Release of Radioactive Material | On March 23, 2017, at 0028 CDT, with the plant operating at 100 percent power, the high pressure core spray system (HPCS was declared inoperable due to a malfunction of a motor-operated valve (MOV) in the system. During a scheduled test, the HPCS pump test return valve to the suppression pool was given a "close" signal after having been opened for the test. The valve position lights indicated that it fully closed, but system flow parameters did not respond as expected. An operator went to the valve and reported that it appeared that the anti-rotation device on the valve actuator had failed, and that the valve was not fully closed. This valve is a primary containment isolation valve. An examination of the MOV found that a set screw on the actuator had loosened, allowing the anti-rotation device to slip down the valve stem. When the anti-rotation device slipped far enough, the retainer keys fell out, allowing the valve stem to disengage from the anti-rotation device. The maintenance history of the valve was investigated, and it was found that in 1996, the anti-rotation device was loosened during a scheduled maintenance task. A review of the work documentation package found that no torque value was specified for the set screw, whereas the vendor manual requires the set screw to be torqued to 60 ft.-lbs. upon installation. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v) as a potential loss of safety function of the HPCS system and the primary containment isolation function. An evaluation of the as-found condition has concluded that the HPCS system and primary containment isolation would have been able to perform their design safety function had an actual design basis event occurred during the test. |
| 05000458/LER-2017-005 | 5 April 2017 5 June 2017 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On April 5, 2017, during a scheduled surveillance test, it was discovered that the Division 1 main control room ventilation filter train was inoperable due to the flow rate being below the lower limit. The initial investigation found that a manually-operated damper in the flow path for that filter train was not correctly positioned. Work documents from the recent refueling outage that started on January 28 were reviewed, and it was found that the damper had been closed as part of establishing a system configuration needed for repairs to other dampers. It was concluded that the as-left condition of the damper after restoration from the maintenance was such that it vibrated in the closed direction upon the first start of the filter train fan, and that the filter train had thus been inoperable since the return to service on February 26, 2017. The plant was restarted at the end of the refueling outage on March 8. On March 10, an unplanned manual reactor scram was initiated due to a steam leak in the turbine building. The leak was repaired and the plant was restarted on March 11. Since the filter train was inoperable on both occasions, those mode changes were made in violation of Technical Specifications. The investigation of this event also found that during one 8-minute period when the Division 1 filter train was inoperable, the Division 2 main control room fresh air system was inoperable for planned testing. This event was caused by the lack of any instructions provided for the restoration of the Division 1 subsystem that directed the torqueing of the damper locking mechanism |
| 05000458/LER-2017-006 | 15 May 2017 13 July 2017 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | On May 15, 2017, an engineering investigation determined that a modification installed in 2014 on two of the four safety-related main control building chillers had a design error. The nature of that error was such that the performance of a regularly scheduled preventative maintenance (PM) task to draw an oil sample from'the chiller gearbox inadvertently caused the chiller to be incapable of responding to an automatic start signal. A review of the history of the PM found that, on three occasions since the modification was installed, the task was performed on the operable chiller that was in the standby condition. The inadvertent inoperability of the standby division of the main control building chillers causes the loss of safety function of the supported electrical distribution systems in the building. The control building chilled water system provides cooling to the equipment rooms housing the battery chargers and inverters for the safety-related onsite electrical distribution systems. The loss of cooling to the various equipment rooms in the control building requires that the supported equipment in those areas be declared inoperable. The Technical Specifications for the Division 3 DC distribution system requires that the high pressure core spray (HPCS) system be immediately declared inoperable. This condition potentially causes the HPCS system to be incapable of performing its safety function, and is, thus, reportable in accordance with 10 CFR 50.73(a)(2)(v)(D). The error in the subject modification is considered a legacy issue since its design was completed and approved in July 2012. The PM task will be revised to preclude its performance on chillers in the standby configuration. At no time during the three performances of the PM on the operable standby chiller was there an actual demand for its automatic start. This condition was, thus, of minimal significance with respect to the health and safety of the public. I |
| 05000458/LER-2017-007 | 21 August 2017 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On June 23, 2017, at 10:18 PM CDT, an unanticipated reactor scram occurred during scheduled testing of the main turbine generator. The plant was operating at 100 percent power at the time, and no safety-related equipment was out of service. A reactor recirculation system flow control valve runback occurred as designed, and the recirculation pumps properly downshifted to slow speed. The main feedwater system responded properly to control reactor water level. The scram signal was initiated by the closure of the main turbine control valves, which was an automatic response to a trip of the main generator. The associated steam pressure increase following turbine valve closure resulted in the actuation of 12 main steam safety-relief valves. A reactor water level 3 signal was received, as expected, following the turbine trip and reactor scram and was promptly restored to the normal reactor water level band. The non-safety related turbine building chillers tripped as a result of the electrical transient caused by the generator trip. One area served by that cooling system is the reactor water cleanup (RWCU) system heat exchanger room. Approximately 20 minutes after the scram, the temperature in that room exceeded the trip setpoint of the area temperature monitors, resulting in the automatic closure of the primary containment isolation valves for the RWCU system. |
| 05000458/LER-2017-009 | 27 September 2017 13 November 2017 | 10 CFR 50.73(a)(2)(v)(C), Loss of Safety Function - Release of Radioactive Material | On September 27, 2017, at approximately 10:00 a.m. CDT, with the plant operating at 85 percent power, a door in the auxiliary building pressure boundary was left unsecured by an employee entering the building. The employee failed to fully close the door, and then did not properly challenge the door to confirm its security prior to leaving the area. A security officer responded to the resulting alarm, and fully closed the door approximately four minutes later. Since the worker had sufficient experience with watertight doors to know their proper operation, this event is considered a skill-based error caused by over-confidence and improper assumptions. Having successfully used such doors numerous times, the worker was confident in the ability to do so. The effort to check the door's security by pushing it failed, likely due to its heavy mass. A briefing memorandum was issued from the general manager to site personnel. Tamper alarms were installed on all watertight doors in the secondary containment boundary to provide an audible indication that the door is open. Administrative controls have been instituted to schedule routine battery replacements. |