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On November 14, 2017, it was identified that the use of the Reactor Protection System (RPS) test fixture described in some operations procedures would result in the loss of two RPS reactor Scram functions. Technical Specification 3.3.1.1 requires that RPS Instrumentation for Table 3.3.1.1-1 Function 5, Main Steam Isolation Valve-Closure and Function 8, Turbine Stop Valve-Closure, remain operable. It was concluded that a closure of three of four Main Steam Lines or Turbine Stop Valves would not necessarily have resulted in a full Scram during testing depending on the combination of closed valves occurring during the bypass condition. Operations procedures were revised to incorporate the use of the test fixture in December, 2008 for the Turbine Stop Valve Closure Scram Test Procedure and February, 2009 for the Main Steam Isolation Valve Closure Scram Test Procedure. The operations procedures were inappropriately revised to allow use of the test fixture on all RPS functions to prevent a half Scram.

The operations procedures were quarantined until revisions were issued in December, 2017 that removed use of the test fixture.

On November 1, 2017, while in Mode 6 and at 0% power level, one of the C Loop Main Steam Safety Valves (MSSV) as-found lift pressure did not meet the acceptance criteria of +/- 3% of the setpoint (1129 psig) as required by Technical Specifications (TS) Surveillance Requirement (SR) 3.7.1.1. The MSSV lifted at 1171 psig which is 9 psig outside of its acceptance range of 1096 to 1162 psig and 3.72°o above its setpoint. The apparent cause of exceeding the MSSV upper acceptance limit is degradation of the valve spring and/or valve spindle compression screw. The as-found settings remained within analytical bounds; therefore, operation of the facility in this condition had no impact on the health and safety of the public.

TS Limiting Condition for Operation (LCO) 3.7.1, IvISSVs, requires five MSSVs per steam generator to be operable in Modes 1, 2, and 3. Since the failure affected the lift pressure over a period of time, it is assumed that the C Loop MSSV was inoperable for a time greater than allowed by TS. Therefore, this occurrence is considered reportable per 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

The C Loop MSSV was replaced on November 5, 2017, while in Mode 5.

On September 7, 2017, Wolf Creek Generating Station (WCGS) was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, WCGS personnel determined that the non safety-related exhaust lines from safety-related atmospheric relief valves (ARVs) and main steam safety valves (MSSVs) could be crimped by tornado generated missiles. If these are crimped completely, these components may be unable to perform their safety functions. The ARVs and MSSVs were declared inoperable and Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado- Generated Missile Protection Noncompliance," Revision 1 was applied. Immediate compensatory measures consistent with EGM 15-002 were implemented within the time allowed by the applicable Technical Specification Limiting Condition(s) for Operation. The ARVs and MSSVs were subsequently declared operable but nonconforming. These tornado missile vulnerabilities existed since the original plant construction. Actions will be taken to establish compliance for these components either by a plant modification or employing a methodology for addressing tornado missile non-conformances.

On April 5, 2017, WCGS personnel provided a 10 CFR 50.72 notification in Event Notification (EN) 52666 concerning tornado missile protection issues known at that time. As stated in EGM 15-002, the NRC will exercise enforcement discretion for subsequent tornado missile 10 CFR 50.72 notifications. Therefore, no 10 CFR 50.72 notification was made for this condition.

On June 8, 2017 at 1527 hours, the reactor automatically scrammed due to a loss of Main Turbine- Electro-Hydraulic Control (EHC) logic power causing a high neutron flux, Reactor Protection System (RPS) trip. The safety systems operated as expected. Secondary Containment differential pressure lowered to 0" WG due to a trip of the normal operation of the Reactor Building Ventilation system. The differential pressure was restored by the initiation of Standby Gas Treatment System.

The scram was caused directly by a DC+ (direct current, positive) test lead (Maxi Grabber) that inadvertently contacted with the grounding screw, causing a short and momentary loss of EHC logic power.

Immediate action was taken to validate that there was no damage to the +30 VDC (volts DC) EHC logic.

The root cause for this event is an insufficient focus on the High Risk Activity of adjusting the EHC power supply, and inadequate risk mitigating actions for that activity.

The condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the RPS, including reactor scram. Although no safety system functional failure occurred, this event is also reportable pursuant to 10CFR 50.73(a)(2)(v)(C) as a condition that could have prevented fulfillment of a safety function. There were no actual, or potential consequences to the health and safety of the public as a result of this event.

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On June 26, 2017, Operations commenced a downpower from 100 percent to 93 percent reactor power to support performance of the Main Turbine Stop and Control Valve Test. With reactor power at 94 percent, the 22 Main Boiler Feed Pump Turbine (MBFPT) speed control trouble alarm annunciated coincident with pump speed swings of 800 revolutions per minute (rpm). The operators ceased the downpower and placed the 22 Main Boiler Feedwater Pump (MBFP) in Manual speed control to control the rpm swings. This was unsuccessful, and the rpm swings continued. The 22 MBFPT low pressure (LP) governor valves were observed to be cycling from full-closed to full-open. The decision was made to take local pneumatic control of the 22 MBFP to stabilize pump speed. Two minutes after establishing local pneumatic control, the LP governor valves went to full closed. With the rapid reduction in 22 MBFP speed, the pump was no longer delivering feedwater flow to the SGs. An automatic main turbine runback signal should have been generated on a low speed signal; however, there was no turbine runback actuation. In response, the operators commenced a manual runback to reduce main turbine load, but the decreasing SG levels reached 15 percent, and at 1531 hours a manual reactor trip was initiated.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the reactor trip was that the shoulder screws used on the 22 MBFPT LP governor valve servomotor linkage had backed out and detached. This caused the LP governor valves to fail closed, shutting off the turbine steam supply. This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on June 26, 2017 under 10 CFR 50.72(b)(2)(iv)(B), 50.72(b)(2)(xi), and 50.72(b)(3)(iv)(A).

On February 11, 2017, Unit 2 was in Mode 5 for a planned refueling outage. While attempting to fill and vent the Unit 2 High Pressure Core Spray (HPCS) system, no flow was observed from the drywell vent valves or downstream of the HPCS injection valve. The HPCS system was already inoperable to support scheduled surveillances performed on February 8, 2017 in which the HPCS injection isolation valve had been cycled five times satisfactorily. Troubleshooting determined the cause of the valve malfunction was due to stem-disc separation. The valve internal components were replaced prior to restart of the unit from the refueling outage. The root cause of the valve failure was insufficient capacity of the shrink-fit stem collar, combined with multiple high-load cycles, which resulted in loosening and eventual shear failure of the wedge pin and threads.

This component failure is reported in accordance with 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of the safety function of structures or system that are needed to mitigate the consequences of an accident. This condition could have prevented the HPCS system, a single train safety system, from performing its design function if the valve failure occurred during an actual demand. This component failure is also reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS) 3.5.1 "ECCS - Operating," since the HPCS system could have been 1 inoperable for greater than the TS 3.5.1, Required Action B.2, Completion Time of 14 days to restore HPCS system to operable status. There were minimal safety consequences associated with the condition since HPCS was not required to be operable at the time of the failure, and other required emergency safety systems remained operable. There were no actual demands for Unit 2 LHPCS, other ECCS systems, or the reactor core isolation cooling (RCIC) system during this period.

- --- ------- - NRC FORM 366 (04-2017) - 01 003 2017

During the February 2017 Unit 2 refueling outage, two main steam safety relief valves (SRV) did not pass Technical Specification (TS) Surveillance Requirement 3.4.4.1 and Inservice Testing (1ST) Program lift pressure requirements. Both SRVs (2B21-F013C and 2B21-F013L) lifted below their expected lift pressures. On February 16, 2017, SRV 2B21-F013C was required to lift within plus or minus three percent of 1175 psi (i.e., 1175 psi plus or minus 35.2 psi), but actually lifted at 1131 psi. On February 17, 2017 SRV 2B21-F013L was required to lift within plus or minus three percent of 1195 psi (i.e., 1195 psi plus or minus 35.8 psi), but actually lifted at 1130 psi.

Multiple test failures are reportable under 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by the plants Technical Specifications. Both SRVs lifted prior to their expected lift pressures, which is conservative in regards to maintaining reactor pressure vessel over-pressure limits. Both SRVs were replaced during the outage. A failure analysis was conducted; however, it did not identify a cause for the valves lifting below their expected lift set-points.

On April 15, 2017 at approximately 10:56 am, with the plant at 0% power in Mode 4 (Shutdown), while performing a plant shutdown procedure the "D" outboard Main Steam Isolation Valve (MSIV), AO-2- 86D was functionally tested. The Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS) Surveillance Requirement (SR) 3.6.1.3.6 requires that the isolation time of each MSIV is > 3 seconds and ime was measured at approximately 40.7 seconds. The valve was declared inoperable and subsequently repaired. The failure was attributed to the air pack pilot valves.

This component failure is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS 3.6.1.3 "Primary Containment Isolation Valves," since AO-2-86D may have been inoperable for greater than the TS 3.6.1.3, Required Action A.1, Completion Time of 8 hours to isolate a main steam line, and the Completion Time for TS 3.6.1.3, Required Action F, to be in Mode 3 in 12 hours and Mode 4 in 36 hours when the completion time of A.1 is not met. There were minimal safety consequences associated with the condition since the primary containment isolation function was maintained.

On March 27, 2017, during refueling outage Q1R24 at 0840 hours, the Unit 1 Main Steam Isolation Valve (MSIV) as-found closure time test results indicated that four MSIVs failed to close within the required Technical Specification (TS) time of less than or equal to five seconds. The safety significance of this event was minimal.

The cause of three of the slow closure timing events was due to a less than optimal replacement frequency for the MSIV actuators, and the cause of the fourth slow closure timing event was due to a less than optimal replacement frequency for the MSIV springs.

Corrective actions included replacing the 1-0203-1B and 1-0203-1D MSIV actuators, replacing the springs on the 1-0203-2C MSIV, readjusting the as-left closure times on all four MSIVs and satisfactory retesting prior to startup. Follow-up corrective actions include replacing the 1-0203-2D MSIV actuator and changing the preventive maintenance frequency and description.

Since the MSIV slow closure times were due to degradation from less than optimal replacement frequencies, it is likely the degradation occurred over time since the last successful refueling outage testing and during power operations when the required TS 3.6.1.3, Primary Containment Isolation Valves was applicable. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B), which requires reporting of any operation or condition that was prohibited by the plant's TS.

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.

In order to address the concerns outlined in NRC Regulatory Issue Summary (RIS) 2015-06 "TORNADO MISSILE PROTECTION", an evaluation of tornado missile vulnerabilities and their potential impact on Technical Specification (TS) plant equipment was conducted. This evaluation concluded that the following Structures, Systems, and Components (SSCs) are potentially vulnerable to tornado generated missiles:

The steam discharge flow paths to atmosphere of the Beaver Valley Power Station Unit 1 (BV-1) and Unit 2 (BV-2) Main Steam Safety Valves (MSSVs) (reference TS 3.7.1) are potentially vulnerable to tornado generated missiles.

The steam discharge flow paths to atmosphere of the BV-1 and BV-2 Atmospheric Dump Valves (ADVs) (reference TS 3.7.4) are potentially vulnerable to tornado generated missiles.

On February 23, 2017, the BV-1 and BV-2 TS required MSSVs and ADVs were declared inoperable and Enforcement Guidance Memorandum (EGM) 15-002 Rev 1 "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance," was applied. Compensatory measures were implemented within the time allowed by the applicable Limiting Condition(s) for Operation and the associated systems were then declared Operable but nonconforming.

The apparent cause of this issue was a lack of clarity during the original design and licensing of the plants that led to inadequate understanding of the tornado missile protection regulatory requirements.

In addition, as part of the evaluation of tornado missile vulnerabilities, two BV-2 tornado missile barrier doors were found to be open. Specifically, Auxiliary Building door (A-35-5A) was found open and Fuel Building door (F-66-3), was found to be partially open. These doors were then closed and latched.

Actions will be taken to establish compliance for the MSSVs and ADVs either by plant modification or by employing a methodology for addressing tornado missile noncompliance for the MSSVs and the ADVs.

These conditions (as applicable) were reported to the NRC on February 23, 2017 in Event Notification (EN) number 52571 under 10 CFR 50.72(b)(3)(ii)(B) and 10 CFR 50.72(b)(3)(v)(A).

On October 22, 2016, Hope Creek Generating Station (HCGS) received results that the 'as-found' set-point tests for safety relief valve (SRV) pilot stage assemblies had exceeded the lift setting tolerance prescribed in Technical Specification (TS) 3.4.2.1. The TS requires the SRV lift settings to be within +/- 3% of the nominal set-point value.

During the twentieth refueling outage (H1R20), all fourteen SRV pilot stage assemblies were removed for testing at an offsite facility. Between October 22 and October 28, 2016, HCGS received the test results for all fourteen of the SRV pilot valve assemblies. A total of ten of the fourteen SRV pilot stage assemblies experienced set-point drift outside of the TS 3.4.2.1 specified values. All of the valves failing to meet the limits were Target Rock Model 7567F two-stage SRVs. This is a condition reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition Prohibited by Technical Specifications.

The cause of the set-point drift for the ten SRV pilot stage assemblies is attributed to corrosion bonding between the pilot disc and seating surfaces, which is consistent with industry experience. This conclusion is based on previous cause evaluations and the repetitive nature of this condition at HCGS and within the BWR industry.

On March 7, 2016, while performing set-up activities for 2-PT-R084C, "23 EDG 8 Hour Load Test," the normal supply breaker to 480 Volt AC Bus (ED) 3A tripped on overcurrent. This caused 480 Volt AC Buses 3A and 6A to de-energize since, as part of the test set-up activities, the tie breaker (3AT6A) between Buses 3A and 6A was closed and the normal supply breaker for Bus 6A was opened. This resulted in a loss of both 21 and 22 Residual Heat Removal (RHR) (BP) pumps. As 'designed, all Emergency Diesel Generators (EDGs) (EK) received automatic initiation signals to start. All required 480 Volt AC buses automatically re-energized by design, with the exception of Bus 3A, which had an overcurrent lockout. Operators manually started 22 RHR pump to restore RHR cooling.

However, prior to restoring the normal supply power to Bus 3A, 23 EDG tripped on overcurrent which resulted in a second loss of RIM event. The cause for the Bus 3A supply breaker tripping was inadequate procedural guidance resulting in excessive loads being energized on Buses 3A and 6A. The direct cause for 23 EDG tripping was cracked solder joints on the automatic voltage regulator (AVR). Corrective actions included revising 2-PT-R084C and replacing the voltage regulator. The event had no effect on public health and safety.

On 10/1/2016 at 0512 CDT with Unit 1 at 99 percent power the plant experienced a turbine trip and automatic reactor trip as a result of inadvertent closure of the 1 A Steam Generator Main Steam Isolation Valve (MSIV).

This caused a rapid pressure reduction in the remaining two Steam Generators' steam lines, resulting in a Safety Injection (SI). The 1 A MSIV closure was caused by failure of its test solenoid in conjunction with other air system leakage, which vented air pressure from the 1A MSIV actuator. An inadequate technical justification allowed the improper deactivation of the preventive maintenance (PM) task of the test solenoid valve in 2004. Decision making by control room personnel not to strictly adhere to an Annunciator Response Procedure was a contributing cause to the reactor trip being automatic versus manual, and led to the SI.

Following the reactor trip and SI the 1 A MSIV test solenoid was replaced and check valves on the 1 A MSIV steam line were tested and replaced. The technical justifications of a sample of previously extended or deleted PMs strategies will be reviewed and corrected. The PM for the Unit 1 solenoid will be reinstated.

Procedure use and adherence standards have been reinforced with Operations personnel, simulator just-in- time training was conducted for all crews, and further causal analysis is planned to investigate operations fundamental performance gaps. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of the reactor protection system, Emergency Core Cooling System (ECCS) injection into the Reactor Coolant System, and automatic actuation of the AFW system.

On September 10, 2016, with the Davis-Besse Nuclear Power Station (DBNPS) operating at approximately 100 percent power, rainwater intrusion into the Main Generator Automatic Voltage Regulator (AVR) cabinet due to an open roof vent caused a lockout of the Main Generator, resulting in a trip of the Main Turbine and Reactor. Following the Reactor trip, the Steam Feedwater Rupture Control System (SFRCS) actuated due to high Steam Generator 1 level and initiated the Auxiliary Feedwater System. The most probable cause of the SFRCS actuation was a failed operational amplifier in the Integrated Control System (ICS), causing the ICS to not reduce Feedwater flow to Steam Generator 1 following the Reactor trip. , Completed corrective actions include closing the roof vents, sealing the top of the AVR cabinet, improved configuration control of the vents, and replacement of the failed ICS module. Scheduled corrective actions include presenting a case study to improve recognition of elevated risk issues, and review of the ICS by a multi-functional team to address system performance concerns.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in automatic actuation of the Reactor Protection System, and an automatic actuation of the Auxiliary Feedwater System.