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 Report dateSiteEvent description
05000458/LER-2017-00913 November 2017Docket Number
River Bend

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.

05000458/LER-2017-00613 July 2017River Bend

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-2017-0055 June 2017River BendOn 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-2017-00422 May 2017River BendOn 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-2017-0039 May 2017River Bend

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-2017-00218 April 2017River BendOn 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-2017-0013 April 2017River BendDuring 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-2016-0074 October 2016River Bend

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-2014-00217 August 2016River BendOn 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-2016-00612 July 2016River Bend

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-2015-00918 May 2016River BendOn 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-2016-00525 April 2016River BendOn 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-2016-00429 March 2016River Bend

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-2016-00317 March 2016River Bend

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-2016-0027 March 2016River BendOn 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-2016-0017 March 2016River Bend

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-2015-0108 February 2016River Bend

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-2015-00818 January 2016River Bend

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-2015-00718 January 2016River Bend

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-2015-00614 September 2015River BendOn 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-2015-0039 July 2015River BendOn 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 System9 July 2015River Bend(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-2015-0025 May 2015River BendOn 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-2015-00116 April 2015River BendOn 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 Alignments16 April 2015River BendOn 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, Operations Prohibited by Technical Specifications Due to Deficient Local Leak Rate Test Procedures Containing Erroneous Valve Alignments16 April 2015River BendOn 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-2014-00619 February 2015River Bend

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-2014-00526 September 2014River BendOn 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-2014-00426 September 2014River BendOn 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-2014-00311 August 2014River BendOn 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-2014-00110 March 2014River Bend

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-2013-0026 November 2013River Bend

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-2013-00118 April 2013River BendOn March 2, 2013, at approximately 1448 CST, with the plant in a refueling outage, maintenance on the reactor recirculation system was commenced without taking the required actions to comply with the applicable Technical Specifications. This maintenance constituted operations with a potential to drain the reactor vessel, and the required action for such an activity is restoration of the integrity of primary containment. This action was not taken, and the provisions of NRC Enforcement Guidance Memorandum 11-003 (Rev. 1) were instead invoked. The maintenance was completed and compliance with Technical Specifications was restored at 0830 CST on March 7. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications, as additionally specified by the Enforcement Guidance Memorandum.
05000458/LER-2011-00321 February 2012River Bend

On December 23, 2011, at approximately 6:10 a.m. CST, the main turbine tripped unexpectedly, resulting in a reactor scram. The plant was stable at 100 percent power at the time of the event, and no safety-related systems were out of service. Operitors implemented the appropriate response procedures, and began to stabilize reactor vessel pressure and water level. The closure of the turbine control valves resulted in the actuation of at least fifteen of sixteen main steam safety relief valves. A subsequent high reactor water level caused a trip of all three reactor feedwater pumps. As reactor water level lowered back through the normal operating range, operators attempted to restart a feedwater pump, but component malfunctions were encountered on "B" and "C" pumps. The reactor core isolation cooling (RCIC) system was manually actuated approximately nine minutes after the scram and injected water into the reactor for approximately two minutes.

The "A" feedwater pump was restored to service approximately one minute after RCIC was initiated. The cause of the turbine trip was a spurious backup over-speed trip resulting from an electrical discharge from the turbine shaft in the vicinity of the EHC turbine speed pickup probe. The cause of the electrical discharge was due to a failure of the shaft grounding system. The plant responded as designed, and no emergency core cooling system actuation setpoints were exceeded. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the automatic actuation of the reactor protection system (RPS).

05000458/LER-2011-00214 April 2011River BendOn February 13, 2011, at approximately 5:00 a.m. CST, during power ascent following a refueling outage, operators found that one channel of main turbine first stage pressure instrumentation was not responding to changing plant parameters. This instrument provides a permissive to the reactor protection system (RPS) to enable a reactor scram signal from main turbine control valve control valve fast closure and main turbine stop valve closure. Also enabled by that permissive is a reactor recirculation pump trip signal initiated by the main turbine stop valve closure. While performing the initial troubleshooting, a maintenance technician discovered that a valve at the affected steam pressure transmitter was closed, isolating it from the system. This valve had apparently been left closed following the calibration of the instrument during the outage. The valve was opened, and the instrumentation channel was declared operable at 5:52 p.m. that day. The signals enabled by this pressure transmitter are required to be operable when reactor power is greater than 40 percent. Reactor power had exceeded 40 percent at approximately 3:24 a.m. that day. This event is being reported as operations prohibited by Technical Specifications in accordance with 10CFR50.73(a)(2)(i)(B).
05000458/LER-2009-00323 November 2009River Bend

On September 29, '2009, at approximately 11:27 a.m. CDT, the main control room operators manually started the low pressure coolant injection function of the residual heat removal (RHR) system in response to a decrease in upper reactor cavity water level. At the time of the event, the plant was in a refueling outage. No handling of irradiated fuel or control blades was in progress.

A Division 1 integrated emergency core cooling system surveillance test was in progress. One of the expected responses was the actuation of the Division 1 primary containment isolation logic. That actuation caused the closure of primary containment isolation valves in various systems, one of which was the service air system.

Among the components being served by the service air system was the main steam line (MSL) plugs in the reactor pressure vessel. The investigation of this event found that the MSL plug in the "A" main steam line was not installed correctly. The mechanical seal had not been completely engaged. In this condition, the backup inflatable seal pressurized by the service.air system was the only barrier keeping water out of that main steam line. When the service air header in the primary containment was depressurized, the seal deflated and began to leak.

This event is being reported in accordance with 10CFR50.73(a)(2)(iv)(A) as a condition involving the unplanned actuation of an ECCS system.

05000458/LER-2007-00514 November 2007River BendOn September 26, 2007, at 10:42 pm CDT, an unplanned automatic reactor scram occurred while the plant was operating at 100 percent power. At the time of the event, scheduled surveillance testing was in progress for a functional test of the average power range monitor (APRM) channel "A". Part of the test procedure involved the actuation of the Division 1 reactor protection system (RPS) trip circuitry. When this action was taken, 36 reactor control rods ("Group 2" rods) unexpectedly inserted into the core. As the reactor operator was taking actions to respond to this condition, an automatic reactor scram was generated by a low reactor water level (Level 3) signal. This event is being reported in accordance with 10CFR50.73(a)(2)(iv) as an automatic actuation of the reactor protection system. The investigation found that a terminal block and wiring had been damaged by overheating due to a loose terminal screw, which had caused a loss of power to the scram valve pilot solenoids on the Group 2 rods. This loss of power was not apparent to the operators, as it occurred in a part of the circuit downstream of the power status lights. The damaged components were repaired, and similar circuits were inspected for loose terminals.
05000458/LER-2007-00319 July 2007River Bend

On May 21, 2007, a review of industry operating experience (OE) related to emergency diesel generators (DG) found a condition which is not consistent with the assumptions of the River Bend Station (RBS) post-fire safe shutdown analysis. That analysis assumes that the high temperature trips on the Division 1 DG would remain active following a start signal resulting from a loss of offsite power (LOP). This OE review found that when the DG starts following a LOP, non-critical trips (such as high temperature) are bypassed. With the non-critical trips bypassed, the DG will continue to run without sufficient cooling, likely resulting in damage to the engine. It appears that, during past revisions of the safe-shutdown analyses, reviewers did not adequately assess all potential failure modes resulting from multiple spurious actuations. This is being reported in accordance with 10CFR50.73(a)(2)(ii)(B) as a condition resulting in the plant being in an unanalyzed condition that significantly degrades plant safety.

This condition does not cause the Division 1 DG to be inoperable with respect to its function required in the accident analysis and Technical Specifications. A pre-existing Standing Order that prohibits welding and grinding in the main control room during Modes 1, 2, and 3 was revised to specifically address this condition.

05000458/LER-2006-00718 December 2006River Bend

On October 19, 2006, at approximately 5:57 p.m. CDT, an automatic reactor scram occurred in response to a low water level signal (Level 3) in the reactor vessel. This condition was the result of the inadvertent closure of the motor-operated isolation valves in the main feedwater headers supplying the reactor. These valves closed when part of a chart recorder was accidentally dropped on their control switches. The high pressure core spray system automatically actuated as designed when its reactor water level (Level 2) initiation setpoint was reached. The reactor core isolation cooling system was out of service for planned maintenance. Reactor steam pressure began to decrease as expected, and when pressure reached 849 psig approximately three minutes after the scram, the main steam isolation valves (MSIVs) automatically closed.

The MSIVs closed because the reactor mode switch was not promptly re-positioned as required by scram response procedures. This event is being reported in accordance with 10CFR50.73(a)(2)(iv) as an automatic actuation of the reactor protection system and the high pressure core system (including the Division 3 diesel generator). Also, primary containment isolation signals actuated as a result of the Level 2 condition and the low reactor steam pressure signal to the MSIVs.

05000458/LER-2006-00626 July 2006River BendOn May 27, 2006, while the unit was operating at 100 percent power, the determination was made that one of the required offsite power supplies to the Division 3 standby switchgear had been inoperable during the recent plant startup on May 13, 2006. A 4160 volt circuit breaker in one of the power supplies to Division 3 was not functional at the time of the plant startup. This condition does not meet the requirements of Technical Specifications Limiting Condition for Operation 3.0.4. In addition, during the investigation, it was determined that the surveillance test procedure that implements Surveillance Requirement 3.8.1.1 did not include the verification of the alignment of the offsite power supplies to Division 3. A similar condition was also found to exist for Surveillance Requirement 3.8.1.8. These conditions are being reported in accordance with 10CFR50.73(a)(2)(i)(B) as operations prohibited by Technical Specifications. The circuit breaker was subsequently repaired and demonstrated to be functional. The Division 3 emergency diesel generator is the safety-related power source for the Division 3 switchgear, and it was operable at the time this condition was discovered. Therefore, this condition was of minimal safety significance.
05000458/LER-2003-00820 November 2003River Bend

At 10:43 p.m. CDT on September 22, 2003, with the plant operating at approximately 78 percent power, an automatic reactor scram occurred during scheduled testing of the main turbine control valves. The scram signal originated from reactor steam pressure instruments following a malfunction of the main turbine control system which caused the control valves to move toward the closed position.

A containment isolation signal initiated due to the expected reactor low water level alarm, which caused the isolation of the suppression pool cooling system, as designed. This event is being reported in accordance with 10CFR50.73(a)(2)(iv) as a valid actuation of the reactor protection system and the containment isolation logic circuitry. Modifications are being considered to prevent recurrence of this condition.

Turbine control valve testing has been suspended pending further corrective actions.

This event was of very low safety significance, as the response of the plant to the scram signal was bounded by the safety analysis.