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 Report dateSiteEvent description
05000387/LER-2016-00610 May 2016Susquehanna

The condition reported by this Licensee Event Report (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 considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS).

Between 3/16/2016 and 4/11/2016, Susquehanna Steam Electric Station (SSES) performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities on Unit 1 while in Mode 5 without an operable secondary containment, as expected and allowed by the enforcement guidance. Although NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 allows the implementation of interim actions as an alternative to full compliance, this condition is still considered a condition prohibited by TS 3.6.4.1. The OPDRV activities were planned activities that were completed under the guidance of plant procedures and are considered to have low safety significance based on 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 Specifications Task Force (TSTF) traveler associated with generic resolution of this issue.

05000387/LER-2015-00630 March 2016Susquehanna

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.

05000387/LER-2015-00815 December 2015SusquehannaOn November 10, 2015, during the completion of an evaluation for a failed surveillance test that occurred on September 22, 2015, a condition was identified that in 2014, a degraded Reactor Protection System (RPS) Electrical Protection Assembly (EPA) breaker logic card had been installed in the Unit 1 Reactor Protection System, resulting in an unplanned inoperability of the 'A' train of the Unit 1 RPS. On September 22, 2015, during the performance of routine 'A' train of the Alternate RPS power supply, could not be determined because the function did not operate at as low as approximately 40 Hertz (Hz). At approximately 40Hz, the undervoltage characteristic took over and issued the trip. The Technical Specification (TS) 3.3.8.2.2 Surveillance Requirement (SR) underfrequency allowable value is > 57 Hz. The UF trip setpoint test was subsequently attempted multiple times with the same result. Because the UF trip setpoint was not achieved, TS 3.3.8.2.2 was not met. Based on the occurrence of a prior failure on September 3, 2000 for the same logic card with the same symptoms as the failure that occurred on September 22, 2015, it was concluded that there is firm evidence that the condition existed prior to discovery on September 22, 2015. Specifically, the condition existed from the time the logic card was installed in the Unit 1 'A' train of RPS on September 25, 2014. Because this condition existed for a period longer than allowed by TS, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS 3.3.8.2.2. The direct cause of the failure of the 1A Alternate RPS breaker was due to an intermittently degraded circuit logic card. The apparent cause was due to the installation of a poor quality spare electrical protection logic card in 2014. The failed logic card was subsequently replaced and the Unit 1 Alternate RPS EPA breaker was declared operable on September 22, 2015. Planned Action: Evaluate vendor diagnosis and repair results for the failed EPA breaker logic card. There were no actual consequences to the health and safety of the public as a result of this event.
05000388/LER-2015-0033 June 2015Susquehanna

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.

05000387/LER-2014-0031 May 2014Susquehanna

On March 4, 2014 at 0025 EST, during Technical Specification (TS) surveillance SR 3.6.4.1.5, drawdown testing of Secondary Containment failed to meet acceptance criteria of SR 3.6.4.1.5 due to maximum flow rate exceeding the allowable value. The testing was performed with the Unit 1 Railroad Bay aligned as Zone III to verify integrity while aligned in a previously untested alignment. The untested alignment was with the Unit 2 Reactor Building HVAC shutdown and a controlled Zone II Secondary Containment breech established. Actual in-leakage while in the untested alignment was 3301 cubic feet per minute (cfm), which is in excess of the TS SR 3.6.4.1.5 acceptance criteria of less than or equal to 2885 cfm. This event was determined to be reportable as an 8 hour ENS (# 49867) in accordance with 10 CFR 50.72(b)(3)(v)(c) for a loss of safety function. There is no redundant Susquehanna Secondary Containment system. This LER is being submitted in accordance with 10 CFR 50.73(a)(2)(v)(C), for an event or condition that at the time of discovery, could have prevented the fulfillment of the safety function of Secondary Containment to control the release of radioactive material.

The direct cause of this event was due to air in-leakage into Secondary Containment past Door-101 and the Truck Bay Access Hatch Cover 2H24. The apparent cause was due to inadequate margin for the untested configuration with Unit 2 Reactor Building HVAC shutdown and a controlled Zone II Secondary Containment breach established.

Completed Actions: 1) Secondary Containment ventilation was realigned to a known previously successfully tested alignment, 2) Installed shielding on the Core Spray piping adjacent to the Control Structure to gain margin in SSES's analysis for Control Room Operator dose post-accident, and 3) Revised the Unit 1 and Unit 2 Tech Spec Bases 3.6.4.1 to increase SGTS Exhaust Flow Rate.

Planned Actions: 1) Repair/replace the bottom seal plate and the top and bottom seals on Door-101, 2) Caulk joints for 2H24 Hatch, and 3) Re-perform Secondary Containment drawdown tests per SE-170-011 for Zone I / Ill aligned in the untested configuration.

There were no actual consequences to the health and safety of the public as a result of this event.

05000387/LER-2014-0011 April 2014Susquehanna

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.

05000388/LER-2012-00419 February 2013Susquehanna

At approximately 1731 hours on December 19, 2012, with the unit operating at approximately 18% power, Susquehanna Steam Electric Station Unit 2 automatically scrammed on low reactor pressure vessel (RPV) level (Level 3, +13 inches) while transitioning the 'A' reactor feed pump from discharge pressure mode to flow control mode. All control rods inserted and both reactor recirculation pumps tripped. Reactor water level lowered to approximately -29 inches causing Level 3 (+13 inches) isolations.

There were no automatic Emergency Core Cooling System initiations. No steam relief valves opened during the event. All safety systems operated as expected.

The scram and associated actuations were reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A) in EN 48607 at 2029 on December 19, 2012. These events are also reportable as an LER in accordance with 10 CFR 50.73(a)(2)(iv)(A).

The root causes of the event were: 1) decision making without a formal evaluation of impacts that reflected a conditioned operator response and inadequate risk evaluation of activities and 2) missed opportunities to identify and provide compensation for the design of the integrated control system logic interface with the valve breaker power.

Key corrective actions included: 1) providing operator training, 2) providing an equipment reliability update to crews, 3) issuing an Operations directive to minimize the knowledge based decisions, 4) revising the Units 1 and 2 reactor feed pump operating procedures, and 5) placing caution signs on the applicable valve breakers indicating that opening the breakers impacts Integrated Control System (ICS) logic. Key corrective actions planned include: 1) defining operator specific skill of the craft work activity actions in an Operations administrative procedure, 2) implementing changes to the station procedure use and adherence procedure, and 3) creating new or revised guidance on the need to identify actions to respond to or compensate for single point vulnerabilities.

There were no adverse consequences to the health and safety of the public as a result of this event.

FORM 366 (10-2010) X JB ISV Yes (10-2010) LICENSEE EVENT REPORT (LER)

05000387/LER-2012-00426 June 2012Susquehanna

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.

05000387/LER-2011-00413 February 2012Susquehanna

On December 6, 2011, Susquehanna Steam Electric Station declared the common "C" Emergency Diesel Generator (EDG) (EIIS: EK) inoperable due to loss of firing from cylinder 8R during surveillance testing. LCO 3.8.1 was entered, the "E" Emergency Diesel Generator was substituted for the "C" EDG and the LCO exited. The direct cause of the loss of firing was due to interruption of the spray pattern in the fuel injection nozzle and partial blockage. The root causes were determined to be 1) the work package to install the delivery valve springs was insufficient, 2) the work crew proceeded using an inadequate work package and 3) Quality Control activities were insufficient to prevent the incorrect reassembly of the fuel injector pump components. Immediate corrective action was to replace the 12 fuel injection pumps. Additional corrective actions include revision to the procedure on work package standards, reinforcement of stopping work when the work package is inadequate, and revision to the procedure on Quality Control Inspection Program to include guidance on construction, formatting, wording and use of notes and verification steps in hold point development.

A review of past maintenance on the "C" EDG determined that the EDG was inoperable from the time maintenance was performed on September 21, 2011 until it was shutdown on December 6, 2011 because it could not have fulfilled its mission time.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.

There were no actual adverse consequences to the health and safety of the public as a result of this event.

05000387/LER-2010-0021 February 2012Susquehanna

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.

05000387/LER-2011-0021 February 2012Susquehanna

On January 25, 2011, Susquehanna Steam Electric Station Unit 1 reactor was manually scrammed due to an unisolable extraction steam system leak in the 1C Feedwater Heater Bay area (EllS: SJ). Reactor power was lowered from 98.4% to 65% prior to the scram. Non-safety-related electrical equipment exposed to the condensing steam began malfunctioning. Attempts to isolate the source of the leakage were unsuccessful. Based on continued indications of an unisolable steam leak, the decision was made to shut down the unit. The mode switch was placed in shutdown. All rods inserted. Reactor water level lowered to minus 31 inches causing a Level 3 (plus 13 inches) isolation. The Reactor Core Isolation Cooling System (RCIC) (El IS: BN) automatically initiated on a minus 30 inch level signal and was manually secured after water level was restored. Reactor water level was maintained at the normal operating band using feedwater. No steam relief valves opened. All safety systems (RPS and PCIS) operated as expected. The direct cause of the unisolable leak was the loss of a bleeder trip valve cover plug. The two root causes were 1.) Less than adequate (LTA) management oversight of the work activity and work planning process and 2.) Deficient work instruction and task assignment for the Bleeder Trip Valve (BTV) repair task. Corrective actions were to replace and seal weld the cover plug on the affected valve and to seal weld the cover plugs on other valves of similar design. Other key corrective actions included planning procedure changes related to threaded pipe assemblies, evaluation and training of maintenance foremen, implementation of a more risk informed screening process, procedure changes and an enhanced coaching card on procedure use and adherence, and management observations using the revised coaching card.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) due to the manual scram and the Reactor Protection System initiation. There were no actual adverse consequences to the fuel, any safety-related plant equipment, or to the health and safety of the public as a result of this event since the dose consequences from the additional leakage would not have exceeded regulatory limits.

05000387/LER-2011-00326 April 2011Susquehanna

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.

05000388/LER-2009-00226 October 2009Susquehanna

On August 25, 2009, while performing pre-start checks to place Unit 2 Residual Heat Removal (RHR) loop in Suppression Pool Cooling, a field operator identified that Unit 2 Emergency Service Water (ESW) cooling valves 211193 and 211194 were unlocked and in the closed position. These valves, which supply ESW cooling water from the 'B' ESW loop to Unit 2 'C' RHR pump unit cooler and motor oil cooler, are required to be locked open. Investigation revealed that ESW cooling valves 211193 and 211194 were closed on April 28, 2009, following restoration of a clearance order associated with a modification to install new stainless steel and cross-tie piping from the 2C motor cooler to the 'A' loop of ESW. 'Because the valves had been closed since April 28, 2009, the Unit 2 'C' RHR pump was rendered inoperable for approximately 4 months. As such, TS LCO 3.5.1, action statements were not met.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B), for a condition prohibited by Technical Specifications.

The cause of the event was human performance error by station personnel for failure to follow the guidance in procedure NDAP-QA-0302. This resulted in a loss of status control for ESW cooling valves 211193 and 211194 for a period of 4 months.

Corrective actions taken included verification that all Unit 1 and 2 locked open ESW valves going to any ECCS equipment were in the correct position. A written communication was provided to all operators regarding this event. Planned corrective actions include incorporating procedure NDAP-QA-0302 into annual pre-outage training for all operators.

The actual consequence of this event is the Unit 2 'C' RHR pump was inoperable for approximately 4 months, which resulted in TS LCO 3.5.1 action statement not being met. The potential consequences, given the worst case single failure for the ESW and RHR Service Water (SW) systems is that with no cooling water to the Unit 2 'C' RHR pump unit cooler and motor cooler, the pump would be expected to eventually fail resulting in SSES not having the minimum ECCS equipment required for long term cooling of Unit 2.

05000387/LER-2007-00215 August 2007SusquehannaOn June 20, 2007, with Susquehanna Unit 1 in Mode 1 at 100% power, it was determined that an unrecognized condition had existed at the Engineered Safeguard Service Water (ESSW) pump house that, administratively, rendered a single loop of Residual Heat Removal inoperable for the suppression pool cooling mode of operation. This condition was created in August 2002 when, for security related purposes, an access door to the pump house was permanently sealed with concrete block. Because the door was being relied upon in station procedures to provide an air circulation path necessary to mitigate the effects of a divisional HVAC failure in the ESSW pump house, this modification placed the station outside of its design basis relative to single failure requirements for the pump house ventilation system. Both an inadequate implementation of the corrective action process and process weaknesses associated with the handling of a complex modification implemented in 1985 contributed to this situation. In response to this event, PPL has "gagged" two pump house dampers to the open position. This measure will ensure circulation cooling in the event of a divisional HVAC failure until a permanent corrective measure can be implemented to address this single failure issue. Susquehanna's FSAR will be revised to address and recognize any design features or operator actions associated with this final resolution when implemented. Additionally, Susquehanna's modification program now requires performance of a failure modes and effects analysis that would have identified the latent, adverse consequences created through implementation of the 1985 modification. The program now also incorporates a formal impact evaluation process that makes it more difficult to implement a change like the 2002 modification without recognizing potential impacts on operational and design basis requirements. Finally, Susquehanna's corrective action program is significantly more robust than it was in the 1990's when actions to update the FSAR were not properly incorporated and taken to completion. This situation is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by the plant's Technical Specifications. There were no safety consequences or compromises to public health and safety as a result of this event.
05000387/LER-2006-00525 October 2006Susquehanna

On August 31, 2006 with Susquehanna Unit 1 in Mode 1 at 100%, the High Pressure Coolant Injection System's Turbine Stop Valve did not, on an intermittent basis, attain complete closure during surveillance testing. This is significant because the HPCI ramp generator will not reset if the Stop Valve is not fully closed. Without a functioning ramp generator, HPCI would likely experience 1 or 2 overspeed trips before the governor could successfully control turbine speed. As such, Tech Spec mandated response times may not have been achieved for HPCI system starts initiated during actual emergency conditions. Friction between the valve's actuator shaft and the rod bushing, brought on by corrosion, is the most likely cause for the HPCI Stop Valve's inability to fully close. Periodic replacement of the rod bushing is necessary to maintain proper operation. Investigation has revealed that an administrative error which occurred in the 1990's permitted this valve's rod bushing to remain in place beyond its ten-year intended replacement frequency. Had the rod bushing been replaced per its intended schedule, this failure would not have occurred. The rod bushing has since been replaced. Additionally, the preventive maintenance schedule has been recalculated to ensure the next rod bushing replacement conforms to the intended replacement frequency.

This situation is being reported in accordance with 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of a safety function required to mitigate the consequences of an accident.

There were no actual adverse consequences to the health and safety of the public as a result of this event.

05000387/LER-2006-00427 September 2006Susquehanna

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.

05000387/LER-2006-00326 July 2006Susquehanna

This is a voluntary report of an event which does not specifically meet established reporting criteria. The situation discussed in this report is most closely related to the reporting criteria of 10CFR50.73(a)(2)(vii). During Susquehanna Unit 1's 14th Refueling Outage, two Motor Operated Valves (MOV) in the station's Generic Letter 89-10 program failed to stroke when called upon to do so. The first failure occurred on March 27, 2006 when the suppression pool suction valve for the 'D' Residual Heat Removal (RHR) pump failed to close during system functional testing. Similarly, on April 6, the suction valve for the 'C' RHR pump failed to stroke during system alignment. In both cases, the immediate cause of the valve failure was excessive wear on the internal stem nut threads of each valve. The failures did not cause RHR trains to become inoperable. Analysis has concluded that the visual inspection of valve stem grease for particulates is an ineffective means of monitoring long term stem nut thread wear. Additionally, routine preventive maintenance did not require periodic inspections of the stem nut itself. When inspections were performed, procedural guidance was not adequate. In response to these failures, Susquehanna has conducted inspections of those MOVs most susceptible to stem nut wear and has replaced stem nuts when appropriate. Additional inspections are planned. In the longer term, the station intends to incorporate changes to its MOV preventive maintenance program and to begin using MOV diagnostic data for monitoring stem nut thread wear.

There were no actual adverse consequences to the health and safety of the public as a result of this event.

05000387/LER-2006-00125 April 2006Susquehanna

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.

05000387/LER-2005-00221 December 2005Susquehanna

On October 28, 2005 at 1600 hours, Susquehanna operators began the process of shutting down Unit 1 for a planned maintenance outage to address known control cell friction issues. The cell friction issues had manifested during Unit 1's 14th fuel cycle when multiple control rods failed to settle into their targeted latched position. At the time of the shutdown, four control rods had been declared inoperable because of excessive rod to fuel channel friction. Other rods, previously known to exhibit slow settling characteristics, would be inserted during the controlled shutdown. It was conservatively determined that any control rods experiencing long settling times would be declared inoperable so that the shutdown would not be slowed by additional testing necessary to prove operability. 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 2332 hours on October 28, Unit 1 had already been reduced to 18% power. The controlled shutdown continued until 0805 hours on October 29, 2005 when insertion of all rods was completed and Mode 3 had been entered by placing the mode switch to the Shutdown position. Entry into the shutdown TS occurred because of a decision strategy that emphasized timely shutdown progress. Additional operability testing, if performed, would have likely precluded any need to enter the TS.

With no substantive benefit attainable from such testing, the strategy was sound.

Even though the plant shutdown was planned and in-progress, the shutdown became a Technical Specification mandate at 2332 hours on October 28 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.

05000388/LER-2005-00418 July 2005Susquehanna

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.

05000387/LER-2002-00620 February 2004Susquehanna

At approximately 0230 hours on October 3, 2002, a fire occurred on Startup Transformer (ST) No. 20.

The transformer fire was extinguished by the transformer's automatic deluge system. Unit 1 was in MODE 1 - Power Operation operating at 100% power and Unit 2 was in MODE 2 -Startup. Unit 2 was manually scrammed due to a loss of both Reactor Recirculation pumps. Unit 1 continued operation at 100% power. The fire was extinguished quickly and caused no significant impact to adjacent systems or structures. An Emergency Plan Unusual Event was declared at 0315 when it was determined that two explosions also occurred. The Unusual Event was terminated at 0552 on October 3, 2002.

ST No. 20 was replaced and declared operable on October 10, 2002. This event was reported in the final conclusions of PPL's investigation of the transformer failure. The conclusion of this investigation was that the root cause was an undetectable internal fault. This internal fault could have originated from several possible sources. It was also determined that the primary and backup lockout relays did not actuate as expected during the event. The lockout relays provide electrical protection for the ST-20 Startup Transformer and function automatically to protect the transformer. The failure of the primary and backup lockout relays to actuate did not cause the event. Corrective actions have been developed and implemented with sufficient breadth to address the possible causes of both the transformer and the protective relay failures. No safety barriers were affected by this event. There were no consequences to the health and safety of the public as a result of this event.

05000387/LER-2003-00619 November 2003Susquehanna

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)

05000387/LER-2003-00411 August 2003Susquehanna

On June 11, 2003 at 1217 hours, the 'A' Control Structure (CS) chiller tripped while the 'B' CS chiller was inoperable for planned maintenance. With the 'A' and 'B' CS chillers inoperable, both trains of the Control Room Emergency Outside Air Supply (CREOAS) system and the Control Room Floor Cooling system were inoperable. In addition, the emergency source of cooling water to the Unit 1 Emergency Switchgear Room Coolers was inoperable. � With two trains of the CREOAS system and Control Room Floor Cooling inoperable, Unit 1 and Unit 2 entered Technical Specification (TS) 3.0.3 and a controlled shutdown of the units was commenced. A four-hour ENS notification was made to the NRC at 1407 hours on June 11, 2003 in accordance with 10 CFR 50.72(b)(2)(i) due to the initiation of a TS-required plant shutdown. This LER is being submitted in accordance with 10 CFR 50.73(a)(2)(v)(D), for a condition that could have prevented the fulfillment of a safety function and 10CFR 50.73(a)(2)(i)(B).

The most probable cause for the CS chiller trip was due to a loose connection identified at Point 40 within the "High Bearing or High Motor Temperature" circuit. Another potential cause was a momentary loss of the "High Bearing or High Motor Temperature" circuit due to an unknown electrical transient. Thermography will be performed to check the Reactor Building (RB) and Turbine Building (TB) chillers for loose electrical connections. To prevent the station chillers from tripping due to operational perturbations, a modification will be performed to install a short time delay within the trip relays for the "High Bearing or High Motor Temperature" circuit for the CS chillers. Similar modifications to the RB and TB chillers are also being investigated. The safety significance of this event was minimal and did not impact the health and safety of the public.

05000387/LER-2003-00210 June 2003SusquehannaAt 22:35 on April 16, 2003 with Unit 1 in Mode 1 at 100% power and Unit 2 in Mode 4 at 0% power, a Secondary Containment Surveillance Test revealed that the 'B' train of the Standby Gas Treatment System (SGTS) inlet damper was inoperable. Electrical Maintenance personnel discovered that the control circuit wires external to the damper actuator had their polarities reversed. Although the polarity reversal had existed since 1998, the damper became inoperable during actuator replacement work performed in November of 2002. Additionally, it was determined that the 'A' train of SGTS was removed from service several times while the 'B' train of SGTS was inoperable. The wiring error was corrected and the 'B' train of SGTS was returned to operable status at 14:15 on April 17, 2003. A root cause analysis was performed for the event and three root causes were found. The procedure used to replace the damper actuator was not explicit enough with respect to control circuit wiring configuration. Work Management personnel did not specify the correct operability testing for the actuator replacement on the work order release in 2002 and Operations release and close out of the work order did not detect the omission. A contributing factor to the work order release errors is that station procedures and computerized workflow steps for the operability testing process contain inconsistencies. The procedures for actuator maintenance and operability testing will be revised to correct these deficiencies. This event is reportable as a Condition Prohibited by the Technical Specifications per 10 CFR 50.73(a)(2)(i)(B) and as an Event or Condition That Alone Could Prevent Fulfillment of a Safety Function per 10 CFR 50.73(a)(2)(v)(C) for Unit 1 and Unit 2. There were no actual consequences to the health and safety of the public as a result of this event since neither of the SGTS trains were required to actuate during the time they were inoperable.
05000387/LER-2003-00111 February 2003SusquehannaAt 19:36 on January 29, 2003 a Ventilation Stack Monitoring System alarm was received in the Unit 1 Control Room. The cause of the alarm was a high indicated iodine release rate from the Unit 1 Turbine Building Ventilation Exhaust Stack. Control Room personnel responded to the alarm per plant procedure. After evaluation, an Unusual Event was declared at 20:32 based on the criteria in EAL 15.1.a.A.2. Evidence gathered to date indicates that the most likely cause is a simultaneous failure of the two in-series drain valves on the delay line drain pot in the Unit 1 Offgas System. This would have created a flow path for non-condensable gases from the offgas stream to the turbine building environment and subsequently to the Unit 1 Turbine Building Ventilation Exhaust Stack. After further evaluation, it was determined that the release stream did not contain an iodine component and the release rates were well below limits established in the Technical Requirements Manual. The iodine detector was responding to Nitrogen-13. The Unusual Event was terminated within six hours at 01:25 on January 30, 2003. A Root Cause Analysis (RCA) Team has been formed to evaluate this event and to determine the causes and corrective actions. In conjunction with this RCA team, a systematic troubleshooting effort is in progress. Iodine detector sensitivity to Nitrogen-13 was previously recognized. A similar event occurred in February of 2002. The Emergency Plan was not entered for this event because an Emergency Action Level criterion was not reached. An RCA Team evaluated this event; however, the corrective actions identified by this team were not completed when this latest event occurred.
05000387/LER-2002-00526 August 2002Susquehanna

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) �

05000387/LER-2002-00421 June 2002Susquehanna

At 01:15 on April 22, 2002 with Unit 1 in Mode 1 (Power Operat on) at 17% power, plant operators initiated a manual reactor scram in response to anomalous core flow indications observed following a recirculation pump trip that had occurred at 00:16. Following the pump trip, power and flow values plotted on the Unit's power to flow map were found to be in a position left of the natural circulation line.

This was unexpected because a second recirculation pump continued to provide forced circulation.

While no power flux oscillations were observed, Operations Management elected to scram the reactor because operators were uncertain about core flow indications and plant procedures did not provide a clear response to the observed conditions. Investigation revealed that past industry and internal experience provided insight into the flow instrumentation logic that resulted in a plotted position left of the natural circulation line. Susquehanna's previous response to this information did not adequately educate operators on, or initiate procedural changes to address, this anticipated instrument behavior.

To preclude recurrence of this event, procedures now direct operators to utilize a core plate differential pressure correlation in lieu of core flow instrumentation during low flow, single-loop operation. Should an operator plot a point to the left of the natural circulation line despite this tool, procedures have been modified to provide clear direction for reactor scram. Operators have been trained on these changes.

This event is reportable for Unit 1 as an unplanned actuation of systems that mitigate the consequences of significant events per 10CFR50.73(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.

05000387/LER-2002-0033 May 2002Susquehanna

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.

05000387/LER-2002-00123 April 2002SusquehannaOn February 22, 2002 with Unit 1 at 81% power and Unit 2 at 100% power, the 'B' Control Structure (CS) Chiller (EIIS: KM) tripped when an operator placed the chiller's handswitch from 'Auto' to 'Start' following an automatic start of the equipment. The 'B' chiller automatically started when the 'A' chiller tripped during post-maintenance testing. The cause of the 'B' CS Chiller trip was lack of specific procedural guidance for the operating condition. In the absence of procedural guidance for a chiller after automatically starting, operators typically place the handswitch from 'Auto' to 'Start' to bring the equipment alignment within generic operating guidance. The handswitch "break-before-make" design imposes an additional start event on the equipment for this action, and the resulting electrical transient tripped the electrical supply breaker for the associated equipment fan. The appropriate operating procedure for the CS Chillers will be revised to provide guidance following an automatic start of the equipment to avoid similar operator-induced trips. This event is reportable as an event or condition that could have prevented fulfillment of a safety function per 10CFR50.73(a)(2)(v). Based upon the simplicity of resetting the electrical supply breaker and the short amount of time that no chillers were available, this event resulted in very low safety significance. There were no actual adverse consequences to the health and safety of the public as a result of this event.
05000387/LER-2001-0049 January 2002Susquehanna

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.

05000387/LER-2001-0038 October 2001Susquehanna

On August 7, 2001 with Unit 1 and 2 at 100% power, engineering personnel discovered an error in the reactor heat balance calculation that resulted in a 6 MegaWatt-thermal (MWth) error. Specifically, the main steam moisture fraction value was found to be non-conservative. Operation greater than the licensed maximum power level is reportable as a violation of license condition. The cause of the error was confusion over similar, closely related terms associated with entrained water in steam (moisture fraction, percent moisture). The maximum power level of Unit 1 and Unit 2 was administratively reduced by 7 MWth upon discovery of the error. The reactor heat balance calculations have been subsequently corrected to use an accurate moisture fraction value, and procedures associated with an upcoming turbine replacement project that could affect the reactor heat balance will be revised to ensure that plant test data is accurately used in the reactor heat balance calculation. Although the calculation error resulted in a non-conservative reactor power level indication, the event was not significant due to the small magnitude (0.2%) of the error. Based on consideration of the margin to analyzed maximum power level, there were no adverse consequences to the health and safety of the public as a result of this event.

NRC FORM 386 (7.2001)