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On September 6, 2017 at 1157, Nine Mile Point Unit 1 experienced an 'automatic reactor scram due to reactor vessel low water level. The automatic Reactor Protection System (RPS) actuation and reactor scram is reportable per 10 CFR 50.72 (b)(2)(iv)(B) and 10 CFR 50.73(a)(2)(iv)(A) as any event or condition that resulted in a manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B). Following the automatic scram all plant systems responded per design including High Pressure Coolant Injection (HPCI) System automatic initiation.

HPCI is a flow control mode of the normal feedwater systems, and is not an Emergency Core Cooling System.

The root cause of the scram was a failed power supply within the Proportional Amplifier, PAM-ID23E. This power supply failure resulted in the output from the module dropping out causing the #13 Feedwater Pump Flow Control Valve to close. The corrective action taken was the replacement of the failed Feedwater Level Control module, PAM- ID23E.

On August 18, 2017, at 8:55 p.m. CDT, an automatic reactor scram occurred while the plant was operating at 100 percent power. The operators promptly established control of reactor water level and pressure, and a controlled plant cooldown was commenced. The initial scram signal was a flow-biased thermal power trip on the average power range monitors.

This action closely followed a planned shift of the master feedwater controller from channel "B" to channel "A.

Troubleshooting discovered that the feedwater level channel select relay had failed such that no signal was present on the "A" channel. When that channel was selected, the feedwater system erroneously sensed that reactor water level was low, and caused all three feedwater regulating valves to move fully open. At the same time, the false low water level signal was sensed in the control circuitry for the reactor recirculation system, resulting in an automatic shift of the recirculation pumps to slow speed. The resultant decrease in core flow caused the flow-biased thermal power trip in the average power range monitors, actuating the reactor scram. The failed feedwater system relay was replaced with an updated model with gold contacts. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv) as an event resulting in the automatic actuation of the reactor protection system.

On November 5, 2016, at 0404, a Reactor Protection System (RPS) actuation occurred due to a valid scram discharge volume high water level signal. This actuation was the result of a Redundant Reactivity Control System (RRCS) Alternate Rod Insertion (ARI) signal that was inadvertently generated during testing. The reactor was in cold shutdown at the time of the RPS actuation, with all control rods inserted. The Reactor Coolant System (RCS) pressure was 830 psig to support excess flow check valve testing, and shutdown cooling was removed from service. When the RRCS/ARI actuated, the B reactor recirculation pump tripped as expected, and the scram air header depressurized as expected.

The depressurization of the scram air header is a design feature of the ARI. The ARI signal established the control rod drive (CRD) system scram flow path. This resulted in a high water level in the scram discharge volume (SDV), an expected response. High water level in the scram discharge volume is an actuation signal for the RPS.

This is a condition reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of a listed system. The cause of the RRCS/ARI actuation is inadequate procedural guidance which resulted in a personnel error associated with partial procedure performance.

During Refueling Outage 29 (RE-29), Cooper Nuclear Station implemented the guidance of Enforcement Guidance Memorandum (EGM) 11-003, Revision 3, "Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel," dated January 15, 2016. Consistent with EGM 11-003, Revision 3, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel activities, and Required Action C.2 of Technical Specification (TS) 3.6.4.1 was not completed.

EGM 11-003, Revision 3, was implemented four times during RE-29. These conditions are being reported as conditions prohibited by TS.

Implementation of EGM 11-003, Revision 3, during RE-29 was a planned activity. As such, there were no root cause evaluations of the events. Consistent with the guidance provided in EGM 11-003, Revision 3, Nebraska Public Power District will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after issuance of the Notice of Availability of the TSTF traveler.

- 005 -00 Cooper Nuclear Station 05000- 298 2016 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

PLANT STATUS

Cooper Nuclear Station (CNS) was in Mode 5, Refueling, at 0 percent power, at the time of the events.

BACKGROUND

On January 15, 2016, the Nuclear Regulatory Commission issued Enforcement Guidance Memorandum (EGM) 11-003, Revision 3, "Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel." EGM 11-003, Revision 3, provides generic enforcement discretion to allow implementation of specific interim actions as an alternative to full compliance with plant technical specifications related to Secondary Containment operability during Mode 5 Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities. To ensure compliance with interim actions specified in the EGM, CNS added guidance to plant Procedure 0.50.5, "Outage Shutdown Safety.

EVENT DESCRIPTION

During Refueling Outage 29 (RE-29), CNS implemented the guidance of EGM 11-003, Revision 3, four times. Consistent with EGM 11-003, Revision 3, Secondary Containment operability was not maintained during OPDRV activities, and Required Action C.2 of Technical Specification (TS) 3.6.4.1 was not completed.

The following provides the dates which EGM 11-003 was implemented:

1. On October 1 and 2, 2016, the EGM was utilized to allow work on Reactor Recirculation Pump A (RR-P-A) and RR-P-B without the jet pump plugs installed while performing Surveillance Procedure 6.1SGT.401, "SGT A Fan Capacity Test, SGT B Cooling Flow Test and Check Valve 1ST (Div 1).

2. From October 2-5, 2016, the EGM was utilized to allow work on RR-P-A, RR-P-B, Control Rod Drive (CRD) withdrawal/bypass operations and Hydraulic Control Unit (HCU) 42-31 during repairs to Main Steam Air Operated Valve 86B.

3. On October 6, 2016, the EGM was utilized to work on RR-P-A and RR-P-B without the jet pump plugs installed while draining Reactor Core Isolation Cooling 12 Relief Valve and flushing Main Steam Isolation Valves (MSIV).

4. From October 19-25, 2016, the EGM was utilized to work on RR-P-A. While using the EGM, work was also performed on CRD-V-113s (freeze seal), CRD Drive Venting, and CRD-V-105 (10-43) (freeze seal). These OPDRVs were in progress while Secondary Containment was inoperable for MSIV 86A and 86B repair, Reactor Building (RB) personnel airlock seal repair, shift of RB ventilation, Service Water Valve 531 draining and Residual Heat Removal Valve 57/67 draining.

Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- 298 Cooper Nuclear Station 2016 - 005 - 00

3. LER NUMBER

BASIS FOR REPORT

These events are reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as conditions prohibited by CNS TS 3.6.4.1, which prohibits performing activities identified as OPDRVs in MODE 5 while secondary containment is inoperable.

SAFETY SIGNIFICANCE

As discussed in EGM 11-003, Revision 3, enforcement discretion is appropriate because the issues have low safety significance since licensees must implement compensatory measures to provide an adequate level of safety when using the discretion. To ensure compliance with the interim actions specified in the EGM, CNS added guidance to plant Procedure 0.50.5. This procedure was implemented for the OPDRV activities during which Secondary Containment was not operable.

CAUSE

Implementation of EGM 11-003, Revision 3, during RE-29 was a planned activity. As such, there were no root cause evaluations of the events.

CORRECTIVE ACTIONS

CNS will submit a license amendment request to adopt the Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue, within 12 months after issuance of the Notice of Availability of the TSTF traveler.

PREVIOUS EVENTS

During RE-28, CNS implemented EGM 11-003, Revision 2, seven times. These events were reported under one License Event Report, LER 2014-004-00.

On April 30, 2016, at 1804 hours, during the plant startup following the 1M38 maintenance outage, a reactor SCRAM was manually inserted by the Control Room Operators during post maintenance testing following work on the 'D' Reactor Recirculation Pump (RRP) mechanical seal. The SCRAM was initiated since leakage was discovered by a rising trend in drywell unidentified leakage during plant startup. The seal had been replaced during the maintenance outage. The SCRAM was selected as the preferred method of shutting down the reactor due to low decay heat conditions following the outage.

ENS 51895 was submitted on April 30, 2016, as required by 10 CFR 50.72 (b)(2)(iv)(B). This issue is reportable under 10 CFR 50.73(a)(2)(iv)(A), for any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(B).

At 2100 hours, on January 23, 2016, the Perry Nuclear Power Plant (PNPP) commenced a reactor shutdown to investigate unidentified leakage in the drywell. At 2122 hours, drywell unidentified leakage exceeded Technical Specification (TS) limits necessitating a plant shutdown as required by TSs. At 0357 hours, on January 24, 2016, while performing the shutdown required by plant TSs, the average power range monitors (APRM) became inoperable due to a calibration setpoint being out of tolerance in the nonconservative direction following a transfer of the reactor recirculation pumps to slow speed. This resulted in a loss of safety function for the APRMs. At 1007 hours, on January 24, 2016, with the plant at 8 percent power, during a feedwater shift to place the motor feed pump in service, reactor water level rose to the level 8 setpoint and the reactor protection system (RPS) automatically initiated, shutting down the reactor. Following the shutdown, a small leak was identified on the reactor recirculation loop "A" pump discharge valve vent line. The recirculation loop is part of the reactor coolant system; this resulted in a degraded condition and a condition prohibited by TS due to pressure boundary leakage.

The cause of the recirculation loop vent line leak was that the weld connecting the root appendage was not performed per the design drawing. The APRM calibration issue was caused by a change to the feedwater flow input to the heat balance. The cause of the reactor level rise and subsequent high water level scram was due to operator error in monitoring and manipulating feedwater system indications and controls.

The safety significance of this event is considered to be small. These events are being reported under; 50.73(a)(2)(i)(A), for completion of any plant shutdown required by the plant's TS; 50.73(a)(2)(ii)(A) for a condition resulting in the plant's principle safety barrier being seriously degraded; 50.73(a)(2)(i)(B) for a violation of Technical Specifications; 50.73(a)(2)(iv)(A) for actuation of the RPS while critical; and 50.73(a)(2)(v)(A) for a loss of safety function.

On November 23, 2015, a trip of the # 11 Reactor Recirculation Pump occurred, followed by a Group 1 isolation which resulted in a reactor scram. A post scram troubleshooting investigation determined a large spike in differential pressure occurred in the 'C' main steam flow instrumentation line at the time of the Group 1 initiation event.

The root cause of this event was determined to be legacy foreign material present in the 'C' main steam flow instrumentation line. This foreign material obstructed the instrumentation line and resulted in the momentary sensed high steam flow. The sensed high steam flow was not due to an actual high steam flow condition in the 'C' main steam line.

Since the presence of foreign material in the instrument line is a legacy issue, the corrective action for the root cause was to remove the foreign material. The corrective action for the trip of the reactor recirculation pump, will be to revise the fleet procedure to require verification of torque on accessible electrical connections for critical components which are bench tested and also to ensure that accessible soldered and crimped electrical terminations are inspected for sians of dearadation durina bench testina.

On September 28, 2015, at 20:46, with the Hope Creek reactor operating at 100% power, a human error during surveillance testing resulted in the actuation of the Redundant Reactivity Control System (RRCS), and subsequently, an automatic reactor scram on a valid low water level signal. At the time of the transient, a surveillance test of division 1 of the RRCS system was in progress. The test simulates a high reactor pressure signal. Plant data show the signal was entered in both channels of division 1 of the RRCS system. The resulting system actuation caused a trip of both Reactor Recirculation Pumps, and the actuation of the Alternate Rod Insertion (ARI) function of the RRCS system. As a result of these two actuations, reactor power lowered, causing reactor water level to lower to the Reactor Protection System (RPS) trip set point of +12.5 inches. The RPS initiated an automatic reactor scram. Reactor operators recovered water level to within the desired band using the feedwater system. Reactor pressure was maintained using turbine bypass valves discharging to the main condenser.

This report is being submitted under 10 CFR 50.73(a)(2)(iv)(A), as an event or condition that resulted in the actuation of the Reactor Protection System.

The condition reported by this LER was an expected condition, which was the result of planned activities in support of a routine refueling outage. As described in the LER, the U.S. Nuclear Regulatory Commission (NRC) provided enforcement guidance, applicable to boiling water reactor licensees, that allows the reported condition.

Although this allowance is provided by the NRC's enforcement guidance, the planned activities are still reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS).

Between May 13, 2015 and June 13, 2015, Columbia Generating Station (Columbia) performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities while in Mode 5 without an operable secondary containment, as expected and allowed by NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 2.

Although EGM 11-003, Revision 2, allows implementation of interim actions as an alternative to full compliance, this condition is still considered a condition prohibited by Technical Specification (TS) 3.6.4.1. The OPDRV activities were planned activities that were completed under the guidance of plant procedures and work instructions and are considered to have low safety significance based on the interim actions taken. Since these actions were deliberate, no cause determination was necessary. A license amendment request will be submitted following NRC approval of the Technical Specification Task Force (TSTF) traveler associated with generic resolution of this issue.

26158 R6 NRC Form 366 (01-2014) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by intemet e-mail to Inf000llects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

On April 10, 2015, at 2100 hours, a planned shutdown for the Susquehanna Unit 2 refueling outage commenced. With shutdown in progress and at approximately 37% power for balance of plant operations, a pre-job brief was conducted in preparation for placing an Auxiliary Boiler in service and placing the Main Turbine Steam Seals on Auxiliary Steam.

At 2129 hours, the 'A' Auxiliary Boiler was placed in service per procedure OP-027-001, "Aux Boiler System," and the Main Turbine Steam Seals were placed on auxiliary steam via valve 221008, "SJAE and Steam Seal Aux Supply !so Vlv." At approximately 2330 hours, the procedure was resumed which directed closure of valve 221008 when Auxiliary Boiler temporary load is no longer needed. At this point, temporary load was no longer needed but auxiliary steam was still flowing through valve 221008, supplying steam to the Unit 2 Main Turbine Steam Seals. The valve was subsquenty closed, which isolated steam to the U2 Main Turbine Steam Seals, allowing air in-leakage into the Main Condenser, causing condenser vacuum to degrade. At 2346 hours, Unit 2 automatically scrammed from approximately 37 percent power due to a the Main Turbine trip on loss of condenser vacuum.

Root Cause: Personnel involved with auxiliary boiler startup did not adhere to Operator Fundamentals and effectively apply appropriate Human Performance error-reduction tools specific to understanding and anticipating the impact of component operation prior to its operation. Completed Action: Procedure OP-027-001, "Auxiliary Boiler System," was revised to caution operators of the potential for isolating auxiliary steam to the Main steam seals and/or Steam Jet Air Ejectors when securing temporary loading of the auxiliary boilers. Key Planned Action: Provide initial licensed and non-licensed operator classroom and job performance measure or dynamic learning activity training with focus on: STAR, Questioning Attitude, Pre job Brief, and understand and anticipate the impact of component operation prior to its operation. Safety Significance: There were no actual consequences to the health and safety of the public as a result of this event.

During Refueling Outage 28 (RE-28), Cooper Nuclear Station implemented the guidance of Enforcement Guidance Memorandum (EGM) 11-003, Revision 2, "Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel," dated December 13, 2013. Consistent with EGM 11-003, Revision 2, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel activities, and Required Action C.2 of Technical Specification 3.6.4.1 was not completed.

EGM 11-003, Revision 2, was implemented seven times during RE-28. These conditions are being reported as conditions prohibited by Technical Specifications.

Implementation of EGM 11-003, Revision 2, during RE-28 was a planned activity. As such, there were no root cause evaluations of the events. Consistent with the guidance provided in EGM 11-003, Revision 2, Nebraska Public Power District will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after the issuance of the Notice of Availability of the TSTF traveler.

(NMP2) Reactor Building was breached when workers opened both inner and outer airlock doors, R261-1 and R261-2, simultaneously while passing through. The integrity of the airlock was re-established within 4 to 5 seconds when one of the doors was closed and latched. A second opening of both airlock doors occurred at 1140 that same day. Secondary containment differential pressure never exceeded the minimum Technical Specification limit of 0.25 inch of vacuum water gauge. These events are significant in that the secondary containment was momentarily breached during replacement of the Reactor Recirculation Pump "B" seal, an activity which had the potential for draining the reactor vessel (OPDRV).

The causal analysis identified that workers did not use their human performance verification tools to ensure the opposing outer door of the airlock was closed prior to opening the inner door. Corrective actions taken include coaching and counseling for workers involved in the event on the importance of applying their human performance tools of self-checking and peer-checking when passing through secondary containment doors. A previous LER submitted on a similar event could not be identified.

On January 17, 2014, leakage into the Reactor Building Closed Cooling Water (RBCCW) System was determined to be Reactor Coolant Pressure Boundary (RCPB) leakage as identified by the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS). Based on this, the TS limiting condition for operation was not met and a plant shutdown was required. The plant shutdown commenced at 2029 on January 17, 2014. There was no radioactive release from the plant. The plant was shut down without incident to repair the source of the inleakage.

The apparent cause for the RCPB leak was the lack of an established maintenance strategy in place to periodically check the condition of the heat exchanger or replace it. A crack formed in the #12 Recirculation Pump Upper Seal Heat Exchanger coil due to intergranular stress corrosion cracking.

The leaking # 12 Recirculation Pump Upper Seal Heat Exchanger was removed and the system was modified to operate without this heat exchanger by utilizing the excess capacity of the #12 Recirculation Pump Lower Seal Heat Exchanger.

On December 2, 2013, at 0903, Nine Mile Point Unit 2 (NMP2) was lowering reactor power level to remove the main turbine from service to support maintenance. During the power reduction, the Low Frequency Motor Generators (LFMGs) did not start automatically. Attempts to manually start the recirculation system pumps in slow speed were unsuccessful and a manual reactor scram was inserted due to the sudden reduction in core flow.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B). The Reactor Protection System is listed in 10 CFR 50.73(a)(2)(iv)(B).

The root cause of this event is a failure to identify that the switches in the auto transfer circuits for the reactor recirculation pumps to shift from high speed to low speed are single point vulnerable (SPV) components because they were exempted from the AP-913 classification process. Since the switches were not classified as SPV components, no mitigation strategies were developed.

Corrective actions include revision of the operating procedures to manually start the LFMG sets and not rely on the auto transfer circuitry.

There are no similar Licensee Event Reports for NMP2.

On Thursday, January 10, 2013 at 1534 hour (EST), with the reactor at 100% core thermal power, both reactor recirculation pumps unexpectedly tripped and a manual reactor scram was inserted as required by station procedures. Following the reactor scram, all rods were verified to be fully inserted and the Primary Containment Isolation System Group II (Reactor Building) and Group VI (Reactor Water Cleanup System) actuations occurred as designed due to the expected reactor water level shrink associated with the scram signal. All other plant systems responded as designed. The scram was uncomplicated and decay heat was released to the main condenser via the turbine by-pass valves.

The cause of the two reactor recirculation pumps tripping was due to the inadvertent seal-in of a relay (pump trip interlock) in the Low Pressure Coolant Injection (LPCI) Loop Select Logic circuitry within the Residual Heat Removal (RHR) System during surveillance testing. When the logic was reset at completion of testing, a normally open relay contact (which was inadvertently closed) interlocked with the recirculation pumps circuit, sent a trip signal to their drive motor breakers.

Corrective action has been taken to revise the subject surveillance procedure with steps to reinstall relay covers and added a verifier to observe relay status/ state prior to resetting the relay logic circuit.

This event had no impact on the health and/or safety of the public.

On September 15, 2012, Unit 1 began a forced outage to replace a 1B recirculation pump seal. On September 17, with the unit in Mode 4, a clearance was hung on the 1B recirculation loop and the recirculation pump suction and discharge isolation valves were isolated to provide the reactor coolant system boundary. After the valves were isolated, there was approximately 10 gpm of leakage by the seats.

On September 19, 2012, at approximately 0330 hours Eastern Daylight Time (EDT), secondary containment airlock doors were opened to facilitate additional ventilation flow to the reactor building, thereby improving working conditions. The decision to open the secondary containment airlock doors was based on BSEP established guidance that leakage through mechanical joints (e.g., valve or flange packing leaks, seat leakage through an isolation valve, flange leakage) is not an Operation with a Potential for Draining the Reactor Vessel (OPDRV). The NRC Senior Resident Inspector questioned this position and, ultimately, the NRC concluded that the activity did constitute an OPDRV. Conducting an OPDRV activity coincident with secondary containment being inoperable constituted operation prohibited by Technical Specification (TS) 3.6.4.1 and is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B).

The cause of this event was inappropriate application of guidance in plant procedure 001-01.01, "BNP Conduct of Operations Supplement." The immediate corrective action was to re-establish secondary containment.