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On September 13, 2017, with the Davis-Besse Nuclear Power Station operating at approximately 100 percent power, Auxiliary Feed Water (AFW) Pump Turbine 1 experienced high inboard bearing temperature during performance of quarterly Surveillance Testing. The turbine was tripped, and disassembly revealed damage to the journal bearing. The bearirig was replaced, and following successful post maintenance testing, AFW Train 1 was declared Operable on September 16. The cause of the bearing damage was an improperly marked oil sight glass, which allowed operation with improper bearing lubrication. The improper markings were due to the maintenance work instruction for replacing the sight glass not including dimensions or guidance for setting required operational bands.

On September 26, 2017, it was identified that low inboard bearing oil level had likely existed since completion of the previous quarterly surveillance test on June 21, when an oil sample was taken following testing but the bearing was not refilled due to the improperly marked sight glass. This issue is being reported in accordance with 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented the fulfillment of the safety function, and in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.

On August 15, 2017, Callaway Plant was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, Callaway Plant personnel determined that the minimum-flow recirculation lines for the turbine-driven auxiliary feedwater pump (TDAFP) and both motor-driven auxiliary feedwater pumps (MDAFPs) could be damaged if a postulated tornado-generated missile were to penetrate the condensate storage tank (CST) valve house and strike the lines. In response, Operations declared all three auxiliary feedwater pumps inoperable.

Compensatory measures were implemented consistent with Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance." Upon completion of the initial compensatory measures, the TDAFP and MDAFPs were declared Operable but nonconforming.

Subsequent to the condition identified on August 15, 2017, continued investigation of tornado missile vulnerabilities led to discovery that the exposed steam exhaust stacks for the main steam safety valves and atmospheric steam dump valves, as well as the exposed vents for the diesel generator fuel oil storage and day tanks, were also susceptible to tornado missile damage to the extent that compliance with General Design Criterion 2 is not ensured. Compensatory measures were then promptly implemented for these conditions, as well, in accordance with EGM 15-002 such that the affected systems have been evaluated to be nonconforming but Operable.

It has been determined that the identified noncomformances are an original plant design legacy issue. Long-term resolution for establishing compliance is under development and will be completed within the time frame described in the EGM.

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

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

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

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

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

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

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

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

On August 9, 2016, Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A was entered for Unit 2 main steam isolation valve SGE-UV-171 (MSIV 171) train A actuator to perform a nitrogen pre-charge check.

The check identified low nitrogen pre-charge pressure on the train A accumulator. An engineering evaluation determined that the MSIV 171 train A actuator was inoperable since July 30, 2016 due to a nitrogen leak on the accumulator. This inoperability period exceeded the 7-day required action completion time for one MSIV actuator train. The MSIV 171 train A actuator was restored to operable status and LCO 3.7.2, Condition A was exited on August 9, 2016. The accumulator leak was repaired on October 5, 2016. Insufficient monitoring, trending, and understanding of reservoir hydraulic fluid level trends in relation to the nitrogen pre-charge required for MSIV operability led to the extended inoperability period.

Operator training will be revised to improve understanding of the system and the limitations of the hydraulic fluid level alarm. Additional corrective actions will revise procedures to provide enhanced rigor for the control of operations condition monitoring thresholds for an MSIV to ensure appropriate response times. Maintenance procedures will also be revised to provide more explicit guidance to minimize the potential for leaks. In the past 3 years, PVNGS has not reported a similar event to the NRC.

On March 4, 2016, during the performance of surveillance procedure 2-PT-R006, Main Steam Safety Valve (MSSV) MS-45B failed to lift within the Technical Specification (TS) as- ' found required range of +/- 3% of the setpoint pressure. Valve MS-45B lifted at 1125 psig, 29 psig outside its acceptance range of 1034 to 1096 psig and 5.7% above its 1065 psig setpoint. The valve was declared inoperable, then subsequently restored to operability upon two successful lifts within the required setpoint range without the need for adjustment. Nine other MSSVs that were tested lifted within the as-found required setpoint range. The apparent cause for the failure was internal friction due to spindle rod wear, which causes the spindle rod to bind against internal components.

Corrective actions were modification of MS-45B and twelve other MSSVs, and the replacement of their spindle rods. The event had no effect on public health and safety.

On August 13, 2015, at approximately 2106, the Unit 3 main steam isolation valve SGE-UV-181 (MSIV-181) B actuator train was declared inoperable and Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A, was entered due to a failed fitting on the air supply line. To correct the condition the failed fitting was replaced and an additional pipe support was installed on the air-line. Following retests, the MSIV-181 B actuator train was restored to operable status and LCO 3.7.2, MSIV-181 B actuator train on May 19, 2015. The investigation of this condition following the second failure determined the MSIV-181 B actuator train air-line configuration was modified in the spring 2015 Unit 3 refueling outage and was inoperable from the time Unit 3 entered Mode 4 on May 1, 2015, at 0258, following the outage because the air-line tubing was not adequately supported following the design change.

The cause of the failure was lack of adequate guidance to perform a walk down during the PVNGS design equivalent change (DEC) process. The lack of a local inspection of actual plant conditions resulted in the latent condition (i.e., vibratory displacement of the affected air-line combined with inadequate tubing support) remaining unnoticed prior to the component failure. Immediate corrective actions to replace the failed fittings and add additional support were completed on August 15, 2015.

An additional corrective action will revise procedural guidance and associated documents.

No similar conditions have been reported by PVNGS in the last three years.

On May 9, 2015, with the Davis-Besse Nuclear Power Station (DBNPS) operating in Mode 1 at approximately 100 percent power, a steam leak was identified in the Turbine Building. A rapid shutdown was initiated, and the reactor was manually tripped at 1909 hours from approxjrnately 30 percent power.

The Steam Feedwater Rupture Control System was manually initiated to isolate the leak and start the Auxiliary Feedwater System. The cause of the leak was failure of a four-inch pipe in the Moisture Separator Reheater System due to Flow Accelerated Corrosion (FAC). An incorrect data input caused the FAC software model to underestimate the predicted wear rate, so inspections were not performed to identify the piping wall thinning prior to failure. Additionally, a previous event was not evaluated to ensure the proposed corrective actions would encompass a validation of all critical data inputs. Corrective Actions include improvements in the fidelity of the data in the FAC Software model, and improvements in the Corrective Action Program with respect to Root Cause Evaluations.

This issue is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a manual actuation of the Reactor Protection System and the Auxiliary Feedwater System.

On February 27, 2015, during the performance of surveillance procedure 3-PT-R006A, three main steam safety valves (MSSV) (MS-46-2, MS-45-4 and MS-47-4) failed their As-Found lift.

set point test. Per the test, these valves must lift at +/- 30 of their required setting.

During the test, 7 other MSSVs tested passed their As-Found test criteria.

Technical Specification (TS) 3.7.1 (Main Steam Safety Valves) requires the MSSVs to be operable in accordance with TS Table 3.7.1-1 and Table 3.7.1-2.

Due to the number of failures, during power ascension the remaining MSSVs were tested and two failed (MS-46-2, MS-46-3).

MSSV MS-46-2 had previously failed and had maintenance performed therefore the failure was considered a post maintenance test failure.

MS-46-3 failed its first lift test by 0.60 but met test lift criteria on the second and third test.

TS Surveillance Requirement (SR) 3.7.1.1 requires each MSSV be verified to lift per Table 3.7.1-2 in accordance with the In-service Testing Program. Operability of the MSSVs includes the ability to open within the set point tolerances. The direct cause of the failure of these valves was severely worn spindle rods.

The apparent cause for the failure of MS-47-4 and MS-46-2 was internal friction due to spindle vibration.

The apparent cause of the failure of.MS-45-4 was reuse of a worn spindle. The apparent cause of the failure of MS-46-3 is foreign material.

Corrective actions included testing all 20 MSSVs and adjusting their set point to be within +/- 1% of design set pressure. Installed new spindles and bronze wear sleeves on valves MS-46-4, MS-46-2, MS-47-4, MS-48-2, MS-49-2, MS-49-1, MS-49-3, and replaced the spindle on valve MS-45-4. The Unit 3 MSSV test frequency will be changed from 4 years to 2 years until all modifications are implemented and IPEC is confident the issue is resolved. The event had no effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

On April 5, 2014, with Millstone Power Station Unit 2 at 100% power in Mode 1, the Enclosure Building was rendered inoperable during a maintenance activity. The condition was created at approximately 1025 and restored to operable status at 1300 on April 5, 2014. Plant Technical Specification (TS) 3.6.5.2 requires that the Enclosure Building shall be operable in Modes 1, 2, 3, and 4. The TS 3.6.5.2 Action is to restore the Enclosure Building to operable status within 24 hours or be in cold shutdown within the next 36 hours.

Therefore, the TS 3.6.5.2 Action requirements were met.

Since the Enclosure Building was inoperable from approximately 1025 until restored at 1300, the safety function of the Enclosure Building to limit radiological releases or mitigate the consequences in the event of a design basis accident could not be assured. The condition was created as the result of a human performance error while performing a maintenance activity associated with the Enclosure Building boundary.

Since this was a human performance error, the event and lessons learned were communicated to the Millstone Site as a Station Human Performance Clock Reset.

On October 23, 2013, while operating at 100% power in mode 1, two main steam safety valve setpoints were found outside the +/- 1% tolerance of table 3.7-2 of technical specification 3/4.7.1.1. Three other valves were tested and setpoints were found to be within tolerance. Upon discovery of the out of tolerance conditions, the two setpoints were adjusted to within technical specification tolerances which restored compliance with the technical specifications. The cause was determined to be setpoint drift incompatible with analysis specified criteria. The corrective action will be implementation of a revised safety analysis that accommodates increased setpoint drift and supports revised technical specification setpoints.

Main steam safety valves are used to satisfy American Society of Mechanical Engineers code requirements for overpressure protection. The limiting accident analysis has more margin available than the measured deviation from setpoint, so the impact on safety is very minor.

Shearon Harris Nuclear Power Plant, Unit 1 05000400

On December 22, 2012, Unit 1 entered Mode 3 during startup from the End of Cycle (EOC) 20 Refueling Outage (RFO) with the turbine driven AFW pump unknowingly inoperable, in violation of LCO 3.0.4. It was also determined during a reportability review that the Completion Time requirement of LCO 3.7.5 for re-entering Mode 4 was retroactively violated by 44 minutes.

Maintenance work had been performed on the pump during the RFO. Although the pump was believed to be operable following the completion of the maintenance, it failed its TS required surveillance test (the test can only be performed in Mode 3 when sufficient steam pressure exists to operate the pump). The cause of this event was determined to be human performance error by the maintenance technician during the assembly of the turbine and pump. In addition, the governing maintenance procedure was deficient in that it lacked detail concerning the required orientation of a turbine component during the assembly process. Planned corrective actions in response to this event include providing remedial actions to ensure maintenance technicians understand the requirements of human performance tool use and enhancing the maintenance procedure to include additional detail governing the assembly process. There was no safety significance to this event. During the time that the turbine driven AFW pump was inoperable while Unit 1 was in Mode 3, both motor driven AFW pumps were operable and remained capable of automatically starting and providing the required flow to the steam generators. Throughout this event, no situation existed that would have resulted in a demand for an AFW System automatic start. Therefore, this event did not affect the health and safety of the public.

On Wednesday, August 22, 2012, Three Mile Island, Unit 1, was conducting a Technical Specification required (T.S. 3.1.6.6) plant shutdown to repair a leak on a pressurizer heater bundle. At 8:01:26 AM with the plant at 30% power, the reactor tripped by Reactor Protection System (RPS) actuation on high reactor coolant system (RCS) pressure. The high RCS pressure setpoint was reached due to a loss of suction to the main feedwater pumps when the only operating condensate booster pump tripped. A "counting circuit" relay stuck in the energized position when the number of operating condensate booster pumps was reduced to one, CO-P-2C. The remaining condensate booster pump tripped when one of the two operating condensate pumps was secured. Suction to the main feedwater pumps was severely reduced and produced a loss of feedwater (LOFW) event and caused RCS pressure to rise and RPS to actuate on high pressure.

Emergency feedwater (EFW) automatically actuated on low steam generator level ( This LER is being submitted pursuant to the requirements of 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(2)(iv)(B).

At 1230 on December 3, 2011, with Millstone Power Station Unit 2 operating at 100 percent power in Mode 1, the control room was notified that a door sweep became dislodged on a door credited as a boundary door for the Enclosure Building. Operators declared the door inoperable and entered the Action for plant Technical Specification (TS) 3.6.5.2 Enclosure Building at 1235. TS 3.6.5.2 Action requires that the Enclosure Building be restored to operable status with 24 hours or be in Cold Shutdown within the next 36 hours. Repairs to the door were completed and operators exited the Action at 1524 on December 3, 2011. The last known time where the door sweep was not dislodged was within 18 hours of the time of discovery.

The operability of the Enclosure Building ensures that the release of radioactive materials from the primary containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analyses. Since there is no bounding analysis on the impact of this size opening on the ability to complete the safety function, this condition is being reported pursuant to 10 CFR 50.73(a)(2)(v)(C) as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

The direct cause of the door seal failure was that the mounting hardware (screws) loosened and fell out. The apparent cause is the door was not being properly maintained. The door was repaired. Doors that are part of the Enclosure Building boundary have been added to the preventive maintenance program.

On April 3, 2011, with Millstone Power Station Unit 2 (MPS2) in a refueling outage at 0% power in Mode 5, data taken during plant shutdown indicated that the Enclosure Building Filtration System had not met acceptance criteria rendering the Enclosure Building inoperable while MPS2 was in Mode 4. Plant Technical Specification (TS) 3.6.5.2 requires that the Enclosure Building shall be operable in Modes 1, 2, 3, and 4. The TS 3.6.5.2 Action requirements were met. Since the Enclosure Building did not meet the acceptance criteria, the safety function of the Enclosure Building to limit radiological releases in the event of a design basis accident could not be assured.

The direct cause for not meeting the Enclosure Building acceptance criteria was that sliding bushings on the main steam safety valves (MSSVs) exhaust piping had dislodged and not reseated. The apparent cause of this event was determined to be a design/application deficiency in the use of MSSV exhaust piping sliding bushings as an Enclosure Building boundary. A design change was implemented that no longer relies on the MSSV sliding bushings as Enclosure Building boundaries. Instead, improved boot seals located on the MSSV exhaust piping form the boundary for the MSSVs.

This condition is being reported pursuant to 10CFR50.73(a)(2)(v)(C) as an event or -condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On February 18, 2010, at 8:24 a.m., Unit 1 experienced an automatic, reactor trip from 92.8 percent power. The 12B Reactor Coolant Pump (RCP) tripped and the Reactor Protective System actuated on Reactor Coolant System low floW. The 12B RCP tripped due to a phase to ground short near one of the current transformers for the 12B RCP bus 14P differential / ground current protection. The ground fault was not isolated close,to the source due to a failed ground protection relay in breaker 252-2202 the feeder breaker from Service Transformer P-13000-2 to the Unit 1 RCP buses. This resulted in Service Transformer P-13000-2 being deenergized.

The loss of P-13000-2 resulted in a loss of the normal power supply to 14 4 kV bus. This caused the 1B Emergency Diesel Generator to start and supply power to 14 4 kV bus.

The cause of the fault was a phase to ground short near one of the current transformers for the 12B RCP bus differential/ground current protection due to water intrusion. This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to Reactor Protective System actuation and automatic start of the 1B Emergency Diesel Generator. Corrective actions include revision to a relay test procedure and improved management of roof issues.

On September 22, 2009, Progress Energy Florida, Inc., (PEF) Crystal River Unit 3 (CR-3) was in MODE 1 (POWER OPERATION) at approximately 100% RATED THERMAL POWER. While performing surveillance procedure SP-650, "ASME Code Safety Valves Test," on the 'A' Once Through Steam Generator, the lift setpoint for Main Steam Safety Valve (MSSV) MSV-34 was found above its maximum allowable tolerance. Subsequently, three of ten tested MSSVs were found to have lift setpoints above/below their maximum allowable tolerance. Improved Technical Specification (ITS) 3.7.1 states that the MSSVs shall be operable as specified in Table 3.7.1-1 in MODES 1, 2 and 3. To be operable, the MSSV lift setpoints must be within the maximum allowable tolerance of ± 3%. The existence of similar discrepancies in multiple relief valves is an indication that the discrepancies may have developed over a period of time.

Therefore, PEF concludes that multiple MSSVs were inoperable during plant operation for a period longer than allowed by ITS and the condition is reportable under 10CFR50.73(a)(2)(i)(B).

This condition does not represent a reduction in the public health and safety. The selected cause is possible failure to provide critical information to the vendor for valve rebuild. The three MSSVs were adjusted and retested satisfactorily. Similar occurrences were reported to the NRC in Licensee Event Reports 50-302/2001-002-00 and 50-302/2003-002-00.

At 11:00, on August 24, 2009, Progress Energy Florida, Inc. (PEF), Crystal River Unit 3 (CR-3) was operating in MODE 1 (POWER OPERATION) at 100 percent RATED THERMAL POWER when the Control Room staff received multiple alarms and observed the Group 7 control rods fully insert into the reactor core. The reactor was manually tripped prior to automatic actuation of the Reactor Protection System (RPS). Prior to this event, electricians were implementing Preventive Maintenance procedure PM-126, "Electrical Checks of CRD (Control Rod Drive) Power Train." When the Integrated Control System was placed in Automatic, the output driver within the Group 7 programmer caused an erroneous phase sequence to the control rod drive stators, culminating in inadequate magnetic force to restrain the rods from dropping during movement. The RPS responded as expected to the manual trip signal, control rods fully inserted and safety systems functioned as required. No reduction in the public health and safety was created. The programmer failure was caused by inadvertent test jumper contact while using an improperly fused test jumper. This caused an over-current failure of the output driver within the programmer. The programmer was replaced and PM-126 was placed on administrative hold.

This report is submitted under 10CFR50.73(a)(2)(iv)(A). No previous similar occurrence has been reported to the NRC.

NRC FORM 366 (9-2007) PRINTED ON RECYCLED PAPER

On March 10, 2009, during the performance of surveillance procedure 3-PT-R006A, main steam safety valves (MSSV) MS-45-1 and MS-48-3 failed their As-Found lift set point test.T In accordance with the test, these valves must lift at +/- 3% of their required setting. Valve MS-45-1 lifted at 1112.7 psig outside its acceptance range of 1034 to 1096 psig. Valve MS-48-3 lifted at 1165.1 psig outside its acceptance range of 1077 to 1143 psig. All other MSSVs tested passed their As-Found test criteria and were left within +/- 1% of their required setting in accordance with the test procedure.

Technical Specification (TS) 3.7.1,"Main Steam Safety Valves," requires the MSSVs to be operable in accordance with TS Table 3.7.1-1 and Table 3.7.1.-2.TTS Surveillance Requirement (SR)T 3.7.1.1 requires each MSSV be verified to lift per Table 3.7.1-2 in accordance with the Inservice Testing Program. Operability of the MSSVs includes the ability to open within the setpoint tolerances. As these two valves were found outside their limit they failed their As-Found testing. Section In accordance with NUREG-1022,T 3.2.2, reporting guidelines, the existence of similar discrepancies in multiple valves is an indication that the discrepancy may have arose over a period of time, and therefore existed during plant operation and is reportable.TThe apparent cause of the two MSSVs lifting greater than 3% of their nominal setpoint is indeterminate but most likely caused by setpoint drift.T Corrective actions included adjusting the valves, subsequent maintenance during the refueling outage, and re-testing with an As-Left setting within the +/- 1% As-Left set point criteria.T The event had no effect on public health and safety

With the plant in MODE 1 at 100% power on April 3 and 4, 2008, set pressure "simmer" testing of Millstone Power Station Unit 2 (MPS2) main steam safety valves (MSSVs) was conducted per plant procedures. During the testing, eight MSSVs failed to lift within the (+1- 3%) acceptance criteria of Technical Specification (TS) 3.7.1.1.

The failure of two MSSVs to lift within the required set pressure range is attributed to a corrosive oxide locking action between surface layer materials of the disc-seat interface, sometimes referred to as "oxide locking" or "micro bonding".

The failure of the other six MSSVs to lift within the required set pressure is the result of differences between two Appendix B approved test methods. A Crosby Set Pressure Verification Device (SPVD) was being used for the first time at MPS2 for MSSV testing. Prior testing and "as-left" settings utilized a Dresser Hydroset system. Although both methods are Appendix B approved, there are key differences between the tests, primarily involving repeatability of results using the Hydroset System at MPS2 in determining when a valve lifts. The Crosby SPVD was used for the current as-left settings and will be used in future tests to provide consistent valve lift data. Following testing, as-left settings were within +1- 1% of set pressure to account for future drift.

On October 24, 2007, at 0917 hours, Braidwood Unit 1 entered Mode 3 while returning to power from a refueling outage.

A Mechanical Maintenance supervisor observed that insulation was installed on the five main steam (SB) header safety valves (MSSVs) for both the 1A and 1D main steam lines. On October 26, 2007, with Unit 1 in Mode 1, the insulation was removed from the valves. Following a review by the safety valve program engineer, it was determined that the insulation posed an operability issue due to the potential impact on the MSSVs setpoint. Based on information from the MSSV manufacturer, and later confirmed through testing, the insulated MSSVs were considered inoperable for a period of time greater then allowed by Technical Specifications, therefore, this event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B).

The cause of the installation of insulation and associated MSSV inoperability was the breakdown in the application of established engineering fundamentals in various parts of the Engineering Organization. The corrective actions included removal of the insulation on the MSSVs to restore the MSSVs to the condition in existence at the time the setpoints were established. On December 9, 2007, with Unit 1 in Mode 1, trevitesting was performed on three of the MSSVs to verify hat the MSSV springs were not subjected to temperatures that permanently affected valve operability. Additional actions included testing of a spare MSSV on December 15-16, 2007, mimicking actual plant conditions, to determine the MSSV operability impact of the installation of the insulation.

There were no safety consequences impacting plant or public safety as a result of this event.

With the plant in MODE 1 at 100% power on April 5, 2007 set pressure "simmer" testing of Unit 3 (MPS 3) Main Steam Safety Valves (MSSVs) was conducted per plant procedures. This testing was conducted just prior to the recent refueling outage. During the conduct of testing, two MSSVs failed to lift within the (+/- 3%) acceptance criteria. Valve 3MSS*RV22B lifted at 1221.3 psig. (1.3 psig above the set pressure range, approximately 3.1%), and 3MSS*RV22D lifted at 1232.8 psig. (12.8 psig above the set pressure range, approximately 3.8%).

3MSS*RV22B supports the B Steam Generator (SG) and valve 3MSS*RV22D supports the D SG. Both valves were subsequently adjusted/retested with the results within the required range of +/- 1%.

Based on information provided by Electric Power Research Institute Report report TR-113560 (Investigation of MSSV High First Lift Phenomenon in Dresser 3700 Series MSSVs, Sept. 2000), industry experience, MSSV test history at Millstone, and engineering judgment, the failure of the MSSVs to lift within the required set pressure range is attributed to a corrosive oxide locking action between surface layer materials of the disc-seat interface sometimes referred to as "oxide locking" or "micro bonding".

This condition is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B) "Any operation or condition prohibited by the plant's Technical Specifications.