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On September 29, 2015, at 0900 hours, the 'B' train of the Standby Gas Treatment System (SGTS) was declared inoperable as part of surveillance test SE-030-002B (24-Month Control Structure Ventilation System Operability Test Div II 'B' SGTS).

During the test, personnel also commenced testing of the Unit 1 Reactor Pressure Vessel water level instrumentation per SI- 180-306 (24-Month Calibration of RWCU PCIS Secondary Containment Isolation and CREOASS Initiation of Reactor Vessel Water Level 2 and MSIV Isolation on Reactor Vessel Water Level 1 for channels LITS-B21-1N026A and B21-1N026C). At 1030 hours, level instrument LITS-B21-1N026A failed its test acceptance criteria, resulting in entry into the Action Statement for TS 3.3.6.2, Condition A. This failed instrument channel is part of the initiation logic for the 'A' train of SGTS. In accordance with TS 3.0.6, since the SGTS is a support system, a loss of safety function determination was performed and concluded the 'A' train of SGTS was inoperable. With both the 'A' and 'B' trains of SGTS inoperable, the Action Statement for TS 3.6.4.3, Condition D, was entered at 1050 hours. At 1456 hours on September 29, 2015, an 8-hour Event Notification (#51432) was made to the NRC per 10 CFR 50.72(b)(3)(v)(c) for a condition that could have prevented the fullfilment of the safety function of the SGTS. On September 30, 2015, during panel walkdowns, it was identified that the 'B' CREOAS system flow controller was still in manual and had not been restored to auto after completion of SE-030-002B on September 29, 2015. As a result, the TS 3.7.3 Action Statement for CREOAS system was entered for the 'B' train being inoperable. In accordance with 10 CFR 50.73(a)(2)(v)(C),this LER is being submitted for any event or condition that at the time of discovery, could have prevented the fulfillment of the safety function of SGTS and the CREOAS system.

Apparent cause: Loss of safety function was not recognized and mitigated when scheduling a surveillance test concurrent with the planned inoperability of the opposite division. Key corrective action: Revise surveillance procedures for instrumentation involving RPS, ECCS initiation, Primary Containment Isolation System (PCIS) and the Secondary Containment Isolation System, to include information on equipment impacts for instruments removed from service, and that redundant equipment is to be operable. There were no actual consequences to the health and safety of the public.

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.

On February 6, 2014, Susquehanna Steam Electric Station (SSES) discovered a previously unrecognized failure to enter Technical Specification (TS) LCO 3.4.10 when on 27 occasions during the past 3 years, the Reactor Pressure Vessel (RPV) pressure dropped below 0 psig during past reactor startups and shutdowns. At the time of discovery, both units were operating in Mode 1 at 100 percent thermal power. All systems were performing as designed. This LER is being submitted to the NRC in accordance with 10 CFR 50.73(a)(2)(i)(B) for a condition prohibited by TS 3.4.10 since the condition existed for a time longer than permitted by the TS.

The apparent cause of the failure to enter the LCO was the condition was procedurally allowed and aligned with training provided to the licensed operators. As a result, operating with the RPV being below 0 psig was not recognized as a condition prohibited by TS until the receipt and evaluation of INPO OE 309129. There were no actual or potential consequences to the health and safety of the public as a result of this event. The 27 instances did not challenge any design or safety limit. Nuclear safety was not compromised because the negative (vacuum) internal pressures identified do not invalidate any analyses for the SSES RPVs.

Completed Action: 1) The Unit 2 operating procedure for reactor startup and heatup has been revised to proceduralize plant start-up with the MSIVs closed and then opening them between 10 and 40 psig RPV pressure. Startup in this manner maintains RPV pressure above 0 psig at all times and minimizes level transients caused by pressure changes when opening the MSIVs, and 2) Operators were trained on the revised reactor startup and heatup procedure.

Planned Action: Prior to startup from the 2014 Unit 1 refueling outage, the Unit 1 operating procedure for reactor startup and heatup will be revised to be consistent with the changes that were made to the corresponding Unit 2 procedure.

On April 27, 2012, it was determined that PPL Susquehanna, LLC (PPL) failed to enter Unit 1 Technical Specification (TS) 3.6.4.2, "Secondary Containment Isolation Valves" Limiting Condition for Operation (LCO) when the primary containment nitrogen makeup line spectacle flange (1S2104) was rotated in the open position in Modes 1, 2 and 3.

This condition was identified as a result of questions raised regarding the need to enter TS LCO 3.6.4.2, in addition to TS LCO 3.6.1.3, "Containment Systems Primary Containment Isolation Valves," when the Unit 1 and Unit 2 spectacle flanges were rotated to the open position. A review of the Unit 1 and Unit 2 control room logs for the past three years identified that on two occasions in 2011 (January 28, 2011 and June 25, 2011), the Unit 1 spectacle flange was open for greater than the combined completion times for TS 3.6.4.2, Condition C.1 and D.1 (4 hours and 12 hours, respectively) of 16 hours. As a result, these events are reportable in accordance with 10 CFR 50.73(a)(2)(i)(B), as a condition prohibited by Technical Specifications.

The cause of the event was less than adequate guidance specified in Operations procedures and status control mechanisms for controlling Secondary Containment.

This event had no impact on the health and safety of the public. The Unit 1 and Unit 2 primary containment nitrogen makeup supply line spectacle flanges have been deleted from the Unit 1 and 2 TS Bases Table B3.6.4.2-2, "Secondary Containment Ventilation System Passive Isolation Valves or Devices.

On April 22, 2010, at 1051 hours, Susquehanna Steam Electric Station Unit 1 experienced an automatic reactor scram, from 32% power, on low reactor water level (ENS 45866). The low level condition occurred during planned testing of a new digital feedwater Integrated Control System (ICS), which included upgrades to the feedwater level control system, the reactor feed pump turbine speed controls, and the reactor recirculation speed controls. During testing at low power conditions, the second of three reactor feed pumps (RFP) was placed in automatic flow control mode for the first time with the goal of parallel automatic operation of two RFPs. A reactor water level transient occurred when the second RFP began feeding into the reactor. The resulting concurrent flow reduction of both RFPs quickly lowered water level to the low level scram setpoint. Corrective actions were taken to adjust the ICS speed controller gain and master feedwater level controller gain.

At approximately 2301 hours on May 14, 2010, Unit 1 automatically scrammed from 66% power due to a main turbine trip on high reactor water level (ENS 45930). The high level condition occurred during additional planned testing of the digital ICS, which involved the trip of one of the four condensate pumps. The high reactor water level transient was attributed to a large feedwater flow/steam flow mismatch caused by insufficient gain on the ICS master feedwater level control system master water level controller in response to large transient conditions. Corrective actions were taken to increase the system gains for large transients using "gap" control on the ICS level controller and flow controller.

The root cause analyses concluded the process used in the development and implementation of the ICS gains/tuning factors did not adequately use risk considerations, independent oversight, analytical tools and techniques, operating experience and appropriate resource management. Also, the station's post-event analysis of the April scram did not adequately evaluate the extent of condition or extent of cause and represents a missed opportunity to prevent the May scram. Planned corrective actions include providing guidance for developing and implementing control system tuning parameters, using the plant simulator for non-training purposes and post-event analysis. There were no actual adverse consequences to the health and safety of the public as a result of these events. The RPS responded as expected. All control rods fully inserted.

These events are being reported under 10 CFR 50.73(a)(2)(iv)(A) due to the actuation of the RPS and RCIC.

On February 25, 2011 at 2027, the Unit 1 High Pressure Coolant Injection (HPCI) Steam Supply Inboard Isolation Valve (HV155F002) was declared inoperable as a result of a packing leak. HPCI was subsequently declared inoperable at 2136 hours on February 25, 2011 as a result of closing the inoperable inboard isolation valve. Subsequently, the HPCI outboard isolation valve was also closed and deactivated. An 8-hour report was made since HPCI is a single train safety system and the event resulted in a loss of safety function. Since inspection of HV155F002 indicated that the grease was completely washed away from the valve stem and an engineering analysis showed inadequate margin to assure the valve would stroke under design basis conditions with no grease on the stem, a determination was made that HV155F002 was inoperable for some time prior to entry into LCO 3.6.1.3. As a result, this was a condition prohibited by Technical Specifications.

The root cause was determined to be a failure to recognize the implications of gland liner failure and the failure modes and mechanisms on the packing system during changes to gland design. Causal factors were less than adequate technical rigor during design of the gland liner and less than adequate attention to detail during fabrication of the liner.

Key corrective actions that are planned include: 1) replacing the brass lined packing gland with a bronze lined packing gland for each valve with a brass liner; 2) performing a design review of gland liner modification documents to ensure all design considerations for packing gland liners are appropriately addressed, and 3) revising applicable procedures to ensure that packing gland liners are inspected during all future re-packs.

On June 15, 2006 with Unit 1 in Mode 1 at 100% power, the Control Room completed preparations to transfer Division B of the Reactor Protection System (RPS) from its normal power supply to its alternate source. The transfer momentarily de-energizes that division of RPS and results in a half-scram. During the 2006 Refuel Outage, a new Power Range Neutron Monitoring System (PRNMS) was installed. Because of differences in the original monitoring system logic and PRNMS logic, the transfer resulted in a full scram.

The event was determined to be reportable under 10 CFR 50.72; reference ENS Notification EN #42642.

Following the automatic scram, the Unit 1 reactor water level decreased to --36". Reactor Core Isolation Cooling (RCIC) initiated and was within the instrumentation tolerance for the Level 2 setpoint of -38" to initiate High Pressure Coolant Injection (HPCI). Once reactor water level recovered, the normal feedwater system was utilized to maintain the normal operating level (+35"). Level 3 (+13") and Level 2 (-38") Primary Containment Isolation signals were received and all safety systems functioned as expected. The actuation of RPS, RCIC and HPCI systems and Primary Containment isolations are unplanned actuations of systems that are designed to mitigate the consequences of significant events and are reportable per 10 CFR 50.73(a)(2)(iv)(A).

This event resulted in no actual adverse consequences to the health and safety of the public.

On March 3, 2006, Susquehanna operators began the process of shutting down Unit 1 for its 14th Refueling and Inspection Outage. As had previously been experienced during Unit 1's last shutdown in October 2005, the station anticipated that some control rods would exhibit slow settling because of excessive rod-to-fuel channel friction. It was conservatively determined that those rods which failed to settle into their targeted latched position in a reasonable period of time would be declared inoperable. Technical Specification 3.1.3, "Control Rod Operability," would be entered when nine rods had been declared inoperable. Entry into TS 3.1.3.f requires that the Unit be taken to Mode 3, Hot Shutdown, within 12 hours.

At the time the ninth control rod was declared inoperable at 0517 hours on March 4, Unit 1 had already been reduced to approximately 0% power. The controlled shutdown continued until 0743 hours when insertion of all rods was completed and Mode 3 had been entered by placing the mode switch to the Shutdown position. Although entry into the shutdown Tech Spec could have been avoided by inserting a manual scram before LCO control rod operability limits were threatened, station management instead implemented a decision strategy that emphasized a controlled shutdown of the Unit.

Even though the plant shutdown was planned and in-progress, the shutdown became a Technical Specifica:ion mandate at 0517 hours on March 4 when the ninth control rod was declared inoperable. Accordingly, this event is being reported as a Tech Spec required shutdown per 10 CFR 50.73(a)(2)(i)(A). There were no safety consequences or compromises to public health and safety as a result of this event.

On March 2, 2005, during performance of the as-found LLRT for the 'A' RHR Shutdown Cooling containment penetration X-13A line, the penetration failed to pressurize. During the as-found LLRT for the 'B' RHR Shutdown Cooling containment penetration X-13B line on March 4, 2005, the penetration failed to pressurize.

Subsequent investigation identified leakage past the inboard HV251F050A and B RHR Shutdown Cooling testable check valves. Both valves were disassembled for examination and were found to have significant damage on the body and disk seats.

The cause of the LLRT failure was determined to be HV251F050A and B gross seat leakage. The seat damage was caused by fretting of the valve seats due to cyclic disk motion during plant operation. The valve disks were permitted to move due to pressure across the valves being equalized during the operating cycle and vibration and/or pump pressure pulses from the Reactor Recirculation system provided the motive force for the cyclic disk motion.

The valves were repaired and satisfactory as-left LLRT results were obtained. Core flow restrictions were imposed for Unit 2 fuel cycle 13 to prevent damage to the HV251F050A and B valves. Planned corrective actions include evaluation of a possible modification solution to provide a differential pressure across the check valve.

Also, Unit 2 procedure TP-264-034, Reactor Recirculation/RHR Injection Loop Hydraulic Response evaluation will be performed to allow stroking of the Unit 2 HV251F015A and B outboard isolation valves at power, and monitoring of vibration effects. There were no actual safety consequences as a result of the damage found in the check valves.

At 00:53 on September 24,2003 with Unit 1 in Mode 1 at 100% power, an automatic reactor scram occurred in response to low reactor water level conditions. While performing required testing of the 'C' Reactor Feed Pump Turbine (RFPT), a control room operator incorrectly manipulated the 'a RFPT lockout key switch instead of the Reset pushbutton thus causing the turbine to trip. Although the 'A' and 'B' Reactor Feed Pumps increased speed in an attempt to maintain reactor inventory levels, the reactor automatically scrammed when water level reached the Low-Level RPS initiation setpoint. HPCI and RCIC automatically initiated to assist the operating Feed Pumps with level restoration. Numerous Primary Containment Isolations occurred as designed during the transient. Susquehanna was designed to withstand a single REPT trip without experiencing a Rx Low-Level Scram. This event suggests that previous changes made at Susquehanna have affected the plant's integrated response to the loss of a single RFPT and have cumulatively resulted in a reduction of the originally designed operating margin. The RFPT trip has been attributed to human performance error. Error prevention techniques will be reinforced to support desired human performance attributes. The scram that resulted following the human performance error has been attributed to the reduction in operating margin resulting from inadequate identification of operating margin requirements in plant change processes.

Corrective actions have been initiated to strengthen station operating margin controls within plant change processes. This event is reportable for Unit 1 as an unplanned actuation of systems that mitigate the consequences of significant events per 10 CFR 50.73(a)(2)(iv)(A). There were no actual adverse consequences to the fuel, any plant equipment, or to the health and safety of the public as a result of this event.

NRC 1011W 366 (7-200I)

On July 26, 2002 at 19:30 with both Unit 1 and Unit 2 in Mode 1 at 100% power, a Maintenance Mechanic observed that argon gas had been used to backfill a NUHOMS® 52-B Dry Shielded Canister (DSC) instead of helium gas. The condition was discovered after the DSC vent and siphon port covers and the outer top cover were installed and welded into place, but prior to transporting the DSC from the reactor building to the Independent Spent Fuel Storage Installation. All dry fuel storage activities on the refueling floor were suspended. A procedure was developed to breach the outer top cover, remove the argon gas from the DSC, confirm and verify it was backfilled with helium gas and weld repair the outer top cover. Repair of the DSC was completed on August 11, 2002. The event occurred when maintenance mechanics erroneously connected the DSC backfill skid to argon compressed gas cylinders, rather than helium compressed gas cylinders. Management review identified that latent organizational weaknesses contributed to this human error event. In response to this event, dry fuel storage work crews received non-routine training to emphasize the need to read labeling when selecting gas cylinders. Routine procedures will be revised to require verification of the correct backfill gas prior to loading other DSCs. Maintenance shift turnover practices will be improved and pre-job checklists will emphasize important tasks. The identified latent organizational weaknesses have been entered into the corrective action process and will be further evaluated. This event is reportable under 10CFR72.75(d)(2), as a significant reduction in the effectiveness of the storage confinement system. However, since there was margin available in the other design parameters, there were no nuclear safety consequences as a result of the event. An analysis of the condition determined that the cladding temperature of the fuel stored in the DSC would not exceed the design basis fuel cladding temperature for the NUHOMS® design. It was also determined with a high degree of confidence that the DSCs already stored in the horizontal storage modules were backfilled with the correct helium gas. Therefore, there were no actual adverse consequences to the health and safety of the public as a result of this event.

NRC FORM 368 (7.2001) �

On March 4, 2002 at 01:20 with Unit 1 in Mode 4 at 0% power, an Instrumentation and Control Technician performing a 24 month logic system functional test observed that an Anticipated Transient Without Scram (ATWS) Recirculation Pump Trip (RPT) 4.16 kV breaker did not trip as required. The Truck Operated Cell (TOC) switch contact in the rear of the associated 4.16 kV switchgear cubicle had failed to make-up properly.

The TOC had excessive drive shaft and gear rotary motion, which allowed the TOC to over-travel when the breaker was "racked-in". The breaker was "racked-out" and returned to the "racked-in" position. The contact was checked for proper continuity and the logic system functional test was then completed successfully. The TOC was subsequently replaced with a design that is less susceptible to over-travel. An investigation showed that the contacts are not visible (i.e. "blind') when the breaker is in the "racked-in" position and there is no specific written guidance on how to verify that the contact is properly made-up. All other ATWS-RPT breakers were checked for proper contact make-up and found satisfactory. All other 4.16 kV breaker cubicles that have "blind" TOC contacts will be identified and it will be determined where verification of contact alignment is necessary. Written guidance and training for monitoring the necessary "blind" TOC contact make-up after a breaker is "racked-in" will be established. The condition may have existed since the last time the breaker had been racked-in during the previous Unit 1 refueling and inspection outage in the Spring of 2000. This event is reportable as a condition prohibited by Technical Specification 3.3.4.2 per 10CFR50.73(a)(2)(i)(B). There was not a loss of safety function associated with the event. There were no actual adverse consequences to the health and safety of the public as a result of this event.

On November 11, 2001, with Unit 1 in Mode 1 (Power Operation) at 100% power, the Control Room received the High Pressure Coolant Injection (HPCI) steam line drain pot high level alarm. Operations personnel observed that valve position indication was lost on the HPCI steam line drain to condenser inboard isolation valve and the HPCI barometric condenser pump discharge drain valve. Operations declared HPCI inoperable due to the formation of condensate at the turbine inlet with no drain path available. Maintenance personnel investigated the loss of indication and found a failed fuse. The failed fuse was caused by high current draw to a failed solenoid valve. The cause of the solenoid valve failure was accelerated aging due to a normally energized coil. The failed Unit 1 solenoid valve has been replaced. This event was of very low safety significance since redundant equipment was operable.

HPCI was returned to service within the allowed outage time given by the Technical Specifications.