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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 October 31, 2017, while in Mode 6 and at 0% power level, the Turbine-Driven Auxiliary Feedwater (TDAFW) pump B-Train steam admission valve from the 2C Steam Generator failed to meet Technical Specification ('I'S) Surveillance Requirement (SR) 3.7.5,5. This SR requires that the valve's associated air accumulator provide sufficient air to ensure operation of the TDAFW pump during a loss of power or other failure of the normal air supply.

During the performance of a flow scan analysis it was identified that the air-operated actuator piston was leaking by the actuator ' o-ring. Although the steam admission valve would stroke open, the 2-hour acceptance criteria could not be met. It is likely that the steam admission valve was inoperable longer than allowed by the Required Action Statement (7 days) following the spring 2016 refueling outage when it passed its last associated surveillance. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

Corrective actions included actuator repair during the outage and further evaluating the preventive maintenance frequency.

NRC FORM 386 (04.2017)

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 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 May 8, 2017, the Tennessee Valley Authority was presented with as-found testing results indicating that four of the thirteen Main Steam Relief Valves (MSRVs) from Browns Ferry Nuclear Plant, Unit 2, were outside the +/- 3 percent setpoint band required for their operability. Troubleshooting determined that three MSRVs exceeded their setpoints when their valve discs failed by corrosion bonding to their valve seats. The valve discs were previously platinum coated to prevent this, but the valve seat's rough Stellite surface caused the coating to delaminate. This was the first Unit 2 MSRV service interval to implement the improved surface treatment since a resolution to the delamination issue was identified in 2015. The valve which failed below its setpoint band was determined to have a faulty pilot spring.

These four MSRVs were found to have been inoperable for an indeterminate period of time between April 9, 2015, and February 25, 2017, and longer than permitted by Technical Specifications. The affected valves remained capable of maintaining reactor pressure within American Society of Mechanical Engineers code limits. Additionally, the valves' ability to open under remote-manual operation, activation through the Automatic Depressurization System, or MSRV Automatic Actuation Logics were not affected. The valves remained capable of performing their required safety function.

Corrective Actions were to replace all thirteen Unit 2 MSRV pilot valves with pilot valves which had the platinum coating applied in accordance with the revised procedure, and to analyze the pilot valves of the inoperable MSRVs.

The pilot spring was replaced inside the valve which failed below its specification.

On April 20, 2017 during outage 1R28 Local Leak Rate Testing (Appendix J), AO-2-86C, "13 Outboard Main Steam Isolation Valve," had an unacceptable as-found leak rate. The measured leakage rate was 187.8 standard cubic feet per hour (scfh) which exceeds the Monticello Nuclear Generating (MNGP) Technical Specification (TS) Surveillance Requirement (SR) 3.6.1.3.12 limit of 100 scfh.

AO-2-86C was declared inoperable and the valve was subsequently disassembled to make repairs.

The valve's stem, discs, upper/lower wedges, disc retainer, and wedge pin were replaced and retested.

The as-left leak rate after completion of the work was 2.64 scfh.

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-2-86C likely had 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 by the inboard valve.

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 April 10, 2017, the Personnel Airlock, X-2, failed to meet local leak rate test acceptance criteria. This failure is reportable under 10 CFR 50.73(a)(2)(i)(B), any operation or condition which was prohibited by the plant's Technical Specifications.

On April 22, 2017, the High Pressure Coolant Injection System turbine exhaust line check valves both failed to meet local leak rate test acceptance criteria. The test volume for each valve could not be pressurized when flow was greater than 100 Standard Liters per Minute. Significant air flow was coming out of the test vent, indicating that each check valve was either degraded or not seated.

This failure resulted in the current Refueling Outage summation of Type B and Type C testing results exceeding the 10 CFR 50, Appendix J local leak rate test criteria limit of 0.6 La and the primary containment total leakage criteria limit of 1.0 La. This created an event that is reportable under 10 CFR 50.73(a)(2)(i)(B), any operation or condition which was prohibited by the plant's Technical Specifications,10 CFR 50.73(a)(2)(ii)(A), any event or condition that resulted in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded, 10 CFR 50.73(a)(2)(v)(C), any condition that could have prevented the fulfillment of a safety function of a system needed to control the release of radioactive material, and 10 CFR 50.73(a)(2)(v)(D), any condition that could have prevented the fulfillment of a safety function of a system needed to mitigate the consequences of an accident.

There was no impact to public health and safety from this condition.

On March 23, 2017, at 0941, Eastern Daylight Time (EDT), with Unit 2 in Mode 1 at 100% power, the Unit 2 Containment CEQ Fan #1 Backdraft Damper opening force exceeded the Technical Specification (TS) Surveillance Requirement (SR) limit.

Maintenance was performed on the damper and operability of the Unit 2 CEQ Fan #1 was restored at 1724 EDT. A past operability evaluation was performed and determined that the condition likely existed since maintenance was performed to lubricate the damper on February 24, 2017. As a result, the Unit 2 CEQ Fan #1 was inoperable longer than allowed by TS. During this time, the Unit 2 CEQ Fan #2 was declared inoperable to perform surveillance testing on March 2, 2017, from 0938 Eastern Standard Time (EST) until 1326 EST. This resulted in both trains being inoperable simultaneously for a short period of time.

The cause of the elevated force required to open the Unit 2 CEQ Fan #1 Backdraft Damper was determined to be that the lubrication Preventive Maintenance (PM) work order instructions were not adequate and did not provide adequate Post-Maintenance Testing (PMT) instruction. Corrective action is to revise model work order tasks to provide additional details and appropriate PMT. The risk significance of this condition has been determined to not constitute a significant increase in risk.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) and 10 CFR 50.73(a)(2)(v)(D).

In February and March 2017, three Main Steam Safety Relief Valve (SRV) body assemblies (main body and pilot assembly) and the remaining five SRV pilot assemblies were tested at National Technical Systems Laboratories (formerly Wyle Laboratories). These SRVs had been removed from Cooper Nuclear Station during Refueling Outage 29 in the Fall of 2016. One SRV pilot assembly failed the as-found lift pressure testing; another SRV pilot assembly was conservatively considered a failure due to lack of as-found lift pressure test data since it was inadvertently disassembled prior to performing the as-found lift pressure test.

There were two causes for the failures. One of the SRV pilot assemblies failed due to corrosion bonding; the other SRV pilot assembly failed due to a lack of a barrier to prevent inadvertent disassembly of the SRV pilot prior to testing.

Although the Technical Specifications limits related to the set point lift pressures of the SRV pilot valve assemblies were exceeded, an analysis indicates that the design basis pressures to ensure safety of the reactor vessel and its pressure related appurtenances were not challenged. Public safety was not at risk. Safety to plant personnel and plant equipment was not at risk.

Refueling Outage 22 commenced on January 14, 2017 at James A. FitzPatrick Nuclear Power Plant (JAF). With the plant in Mode 2 at 0613, the initial Drywell inspection identified a through wall leak on the 3/4 inch vent line off of the bonnet of the motor operated gate valve on the suction side of Reactor Water Recirculation Pump 'A'. This condition was determined to constitute Reactor Coolant Pressure Boundary (RCPB) leakage, which is prohibited by Technical Specification (TS) Limiting Condition for Operation (LCO) 3.4.4. The average reactor coolant temperature decreased to less than 212 degrees F and the plant was in Mode 4 at 1530 of the same day, which is within the applicable TS LCO 3.4.4 required completion time.

The condition of a through wall leak on the RCPB is reportable pursuant to 10 CFR 50.73(a)(2)(ii), as a condition of the nuclear plant, including its principle safety barriers, being seriously degraded.

On June 30, 2016, at 0829, with the Davis-Besse Nuclear Power Station in Mode 1 and at approximately 100 percent power, a level transmitter for Safety Features Actuation System (SFAS) Channel 1 was declared inoperable for scheduled maintenance and Technical Specification (TS) Limiting Condition of Operation (LCO) 3.3.5 Condition A was entered. At 2342 hours a power supply in SFAS Channel 2 failed and a separate TS LCO 3.3.5 Condition A was entered. Upon recognition that two channels of SFAS were inoperable, TS LCO 3.3.5 Condition B was entered at 0245 and then exited at 0330 with the use of compensatory actions to restore SFAS Channel 1 operability. After further review, it was determined the compensatory actions could not be credited and TS LCO 3.3.5, Condition B was re- entered at 1325. SFAS Channel 1 was restored and declared operable at 1351 hours.

Causes of the event were the Shift Manager failed to initially recognize that TS LCO Conditions A and B had been met; followed by Station Personnel failing to effectively implement required processes. The root cause was that Station Management failed to recognize that a normalized deviation had occurred that resulted in TS noncompliance. Corrective Actions include specific refresher training to all applicable personnel, revising relevant documents, and developing an event Case Study for training purposes. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by the plant's Technical Specifications.

On October 8, 2016, the Shearon Harris Nuclear Power Plant was reducing power to enter a planned refueling outage (RFO-20). The plant was at approximately 8 percent power in Mode 1 when the unit experienced an unplanned reactor trip with a safety injection (SI) and main steam line isolation (MSLI). A malfunction of the turbine controller during turbine mechanical overspeed trip testing caused an excessive draw of steam flow from the Steam Generators (SGs). This caused the Engineering Safety Features Actuation System instruments to detect a valid change in SG pressure and initiate a rate compensated Low Steam Line Pressure signal. This signal initiated a SI and MSLI, which in turn initiated reactor trip, turbine trip, feedwater isolation, and closed the main steam isolation valves.

Degraded equipment within the turbine controller resulted in excessive opening of the governor valves; this was caused by an inadequate supply of hydraulic oil to meet the increased system demand during testing. Insufficient hydraulic accumulator capacity was available to support system demand. One accumulator was known to be out-of-service; a second was discovered post-event. Also, a hydraulic oil pressure switch used for turbine control was not functioning properly. The equipment deficiencies have been corrected.

Changes have been made to the testing procedure to validate at least four accumulators are in service prior to testing. The Power Operation (Mode 2 to Mode 1) procedure will also be revised to validate at least four accumulators are in service. A new calibration procedure will be implemented for the deficient oil pressure switch to ensure better quality control over verifying switch function.

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 24, 2016, at 20:40 hours, during reactor cooldown for Refueling Outage 29, Cooper Nuclear Station control room operators closed the inboard Main Steam Isolation Valves (MSIV) to minimize steam flow to control the reactor cooldown rate. Reactor pressure was controlled using the Main Steam Line Drains; and the condensate/feed system was available for reactor water level control.

On September 25, 2016, at 01:03 hours, while equalizing pressure across the MSIVs to below 200 psid, a differential pressure of 190 psid was established. Upon opening MS-AO-80A, a Group 1 isolation was immediately received due to a Main Steam Line high flow signal. The control room operators subsequently equalized pressure and successfully opened MS-AO-80A, as well as the remaining MSIVs, at 18:52 hours.

The cause of the event was insufficient procedure guidance exists regarding limitations on opening the MSIVs. To correct this, the applicable procedure has been revised to change the differential pressure limitations for opening MSIVs from 200 psid to 80 psid.

The safety significance of the event is low and did not pose a threat to the health and safety of the public.

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.