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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.

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.

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.

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. ,

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.

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.

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.

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.

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.

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.