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05000313/FIN-2018003-05Arkansas Nuclear2018Q3Failure to Maintain Main Feedwater Pump B Discharge Pressure in Band Caused a Reactor TripThe inspectors reviewed a self-revealed, Green finding and associated non-cited violation of Arkansas Nuclear One, Unit 1, Technical Specifications 5.4.1.a, for the licensees failure to implement Procedure OP-1102.002, Plant Startup, Revision 106. Specifically, control room operators failed to maintain main feedwater pump discharge pressure in the required band to control flow to the steam generators during a plant startup. As a result, the only operating main feedwater pump tripped on high discharge pressure, causing an automatic reactor trip.
05000251/FIN-2018003-02Turkey Point2018Q3Inoperable Auxiliary Feedwater Steam Supply Flow PathA self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion V, Procedures, was identified when FPL failed to ensure that the torque arm of the 4A steam generator (SG) auxiliary feedwater (AFW) steam supply valve, MOV-4-1403, remained engaged with its valve stem key. A disengaged torque arm subsequently caused the geared limit switch settings for the 4-1403 motor operator to become out of sync with the valve travel and rendered the AFW 4A SG supply flow path inoperable.
05000390/FIN-2018003-03Watts Bar2018Q3Failure to Collect Compensatory Samples for an Out-of-Service Effluent MonitorThe inspectors identified a Green finding and associated NCV of TS 5.7.2.3 when the licensee failed to take compensatory samples in accordance with Table 1.1-1 of the Offsite Dose Calculation Manual when the Unit 1 steam generator blowdown effluent monitor was out of service. Specifically, radiation monitor 1-RM-90-120/121 was inoperable from April 27 to May 27, 2018, and compensatory samples were not collected and analyzed within the required frequency of at least once per 24 hours.
05000313/FIN-2018011-03Arkansas Nuclear2018Q3Failure to Evaluate the Effects and the Suitability of Components in Containment from a Main Steam Line Break.The team identified an unresolved item (URI) related to the containment environment that would result from a main steam line break. Specifically, for ANO Unit 1 the licensee did not analyze the containment temperature, or evaluate the suitability of components in containment for the effects of a main steam line break (MSLB) accident. The Final Safety Analysis Report states, in part, that "At the end of Cycle 19, the original once through steam generators (OTSGs) were replaced. In support of Cycle 20 operation, an evaluation of the containment pressure/temperature response with the replacement OTSGs for loss of coolant accidents (LOCA) and MSLB was performed. For the MLSB, the containment pressure response with the replacement OTSGs was bounded by the current analysis. The post-MSLB temperature response w ith the replacement OTSGs would be worse. Entergy Operations, Inc. has adopted NUREG-0458 into the AN0-1 licensing basis which recognizes that the post-MSLB atmosphere may become superheated, but the temperature spike is of such short duration that the thermal lag of any SSC inside containment will not increase significantly. Consequently, the initial temperature peak does not define operating limits on any system, structure, or component (SSC) and the long-term containment temperature (which is essentially the saturation temperature) dominates the temperature response of SSCs. Therefore, as long as the peak MSLB pressure is less than the peak pressure following a LOCA, the temperature response of SSCs will still be defined by the LOCA." The NRC issued several bulletins subsequent to the issuance of NUREG-0458. Specifically IEB-79-01, as supplemented, and NRC Order CLI 80-21 state, in part, that "The Guidelines leave open the question of what standard will be applied to replacement parts in operating plants. Unless there are sound reasons to the contrary, the 1974 standard in NUREG-0588 will apply. The Guidelines and NUREG-0588 apply progressively less strict standards to the older plants. The justification for this position was not articulated at the time the older plants were grandfathered from the provisions of Reg. Guide 1.89." The NRC issued a Safety Evaluation Report to ANO, which states, in part, "A final rule on environmental qualification of electric equipment important to safety for nuclear power plants became effective on February 22, 1983. This rule, Section 50.49 of 10 CFR 50, specifies the requirements of electrical equipment important to safety located in a harsh environment. In accordance with this rule, equipment for Arkansas Unit 1 may be qualified to the criteria specified in either the DOR Guidelines or NUREG-0588, except for replacement equipment. Replacement equipment installed subsequent to February 22, 1983 must be qualified in accordance with the provisions of 10 CFR 50.49, using the guidance of Regulatory Guide 1.89, unless there are sound reasons to the contrary." The NRC issued Information Notice 85-39 states, in part, that the "Qualification of some replacement equipment was based on previously allowed DOR guidelines that stated "equipment is considered qualified for main steam line break environmental conditions if it was qualified for a loss-of-coolant accident environment in plants with automatic spray systems not subject to disabling single component failures." This basis of qualification is not acceptable without additional justification for replacement equipment that was procured and installed after February 22, 1983." The replacement steam generators have several design differences compared to the original steam generators. Specifically, the replacement steam generators were designed with larger secondary volumes, more tubes, flow-restricting venturis, and different materials (Alloy 690 vs. Alloy 600). Because the replacement steam generators were installed in 2005 (after 10 CFR 50.49 became effective on February 22, 1983) all replacement equipment must be qualified using the guidance of NUREG-0588 or Regulatory Guide 1.89. In addition, as stated above the licensee did not analyze or quantify the containment temperature that would result from a MSLB, and instead compared the containment pressures and the mass/energy releases that would result from a MSLB using the superseded guidance of NUREG-0458. The NRC team identified that there are several parameters that could have changed with the replacement steam generators which could impact the containment response. Specifically, input parameters such as: sub-compartment analysis, net positive suction head analysis, containment volume, heat sinks, properties of materials, heat transfer coefficients, initial conditions, and possibly cooling water temperature may affect the containment temperature response.
05000483/FIN-2018003-01Callaway2018Q3Failure to perform 10 CFR 50.59 evaluation for compensatory measures associated with stagnant, inactive loopThe inspectors identified an unresolved item related to implementation of 10 CFR 50.59, Evaluations Changes, Tests and Experiments, for the licensees failure to perform an adequate evaluation for compensatory measures for a stagnant, inactive loop. The inspectors identified an unresolved item related to implementation of 10 CFR 50.59, Evaluations Changes, Tests and Experiments, for the licensees failure to perform an adequate evaluation for compensatory measures for a stagnant, inactive loop. The licensee enacted compensatory measures to support atmospheric dump valve/turbine-driven AFW pump operability due to an issue identified for natural circulation cooldown with a faulted steam generator (i.e., inactive loop). A reduction in the Technical Specification 3.4.16 dose equivalent iodine (DEI) limit (from 1Ci/gm to 0.4Ci/gm) was imposed without a 10 CFR 50.59 evaluation and/or license amendment. Specifically, the licensee did not consider the compensatory measure of reducing Technical Specification 3.4.16 limits on DEI-131 as a change to technical specifications.The licensee considered this a temporary action that did not meet the intent of 10 CFR 50.90 for a technical specification change.
05000247/FIN-2018003-04Indian Point2018Q3Inadequate Procedure for Turbine Startup Caused a Reactor TripA self-revealing Green NCV of TS 5.4.1, Procedures, was identified because Entergy did not provide adequate guidance in 2-SOP-26.4, Turbine Generator Startup, Synchronization, Voltage Control, and Shutdown. Specifically, Entergy did not provide adequate procedural direction to ensure the main turbine control oil stop valve Z was in the correct position. As a result, the steam generator water level exceeded the trip setpoint for the main boiler feed pumps which led the operators to insert a manual reactor trip.
05000348/FIN-2018002-08Farley2018Q2Licensee-Identified Violation

Violation: Farley Nuclear Plant Unit 2 Technical Specifications (TS) limiting condition for operation (LCO) 3.7.5, Auxiliary Feedwater System, required all three auxiliary feedwater (AFW) trains shall be operable in modes 1, 2, and 3. For Condition A, one steam supply to turbine driven AFW pump inoperable, the required action A.1 was to restore the affected equipment to operable status within the required completion time of 7 days. If the required action and associated completion time is not met, action statement, Condition C required that the unit be in mode 3 within 6 hours and mode 4 within 12 hours. TS Surveillance Requirement (SR) 3.7.5.5 required verification that the turbine driven AFW pump steam admission valves open when air is supplied from their respective air accumulators.

Contrary to the above, the licensee determined the steam admission valve (Q2N12HV3235B) was inoperable longer than the required action completion time of 7 days between May 6, 2016 and October 15, 2017, while Unit 2 was in modes 1, 2, and 3. Unit 2 was not placed in mode 3 or 4 as required by condition C of TS LCO 3.7.5. On October 31, 2017, a turbine-driven auxiliary feedwater (TDAFW) pump steam admission valve (Q2N12HV3235B) was tested with a flow scan analysis device during a refueling outage, while the plant was in Mode 6. This valve is the B-train steam admission valve that supplies steam to the TDAFW pump from the 2C steam generator. There is a redundant A-train steam admission valve that supplies steam from the 2B steam generator. During valve flow scan testing of the valve actuator it was discovered that air was leaking past the actuator piston o-ring seal inside the valve air actuator. Air leakage was measured greater than 10 psig per minute which was significant enough that the valve would not meet surveillance requirement (SR) 3.7.5.5 when instrument air was supplied solely from the valves associated air accumulator. Although the valve would stroke open with air supplied only from the accumulator, the SR 2-hour acceptance criteria to maintain the valve open could not be met. Each steam admission valve has an air accumulator associated with it. The air accumulator is designed to provide a sufficient quantity of air to ensure operation of the valve during a loss of power event or other failure of the normal instrument air supply for a period of two hours. Also, the inspectors determined that the licensee missed an opportunity to determine the cause of the o-ring failure since the o-ring was discarded during actuator rework. Procedure NMP-ES-001, Equipment Reliability Process Description, requires the preservation of physical evidence when failures occur.
05000316/FIN-2018002-01Cook2018Q2Steam Dump Closure Caused by Human ErrorOn May 10, 2018, a Green self-revealed finding and associated Non-Cited Violation occurred when licensee personnel caused the Unit 2 steam dump valves to the condenser to close. Specifically, when tuning the controller for the steam dump valves, licensee personnel left the controller in automatic, resulting in the closure of all the steam dump valves. This caused both the steam generator power operated relief valves and a steam generator safety valve to lift.
05000382/FIN-2018002-02Waterford2018Q210 CFR 50.59 Evaluation Associated with Emergency Feedwater Logic ModificationThe licensee changed the emergency feedwater logic, as described in the Updated Final Safety Analysis Report (UFSAR), Section 7.3.1.1.6, from flow control mode to level control mode during a safety injection actuation signal. To accomplish this change, the licensee had to modify the following logic system signals and setpoints: steam generator critical level, steam generator lo level, steam generator lo-lo level, safety injection actuation, control board manual control, and the steam generator lo-lo level annunciator. The NRC team questioned whether the emergency feedwater modification required additional information to determine if the 10 CFR 50.59 evaluation was adequate, or if NRC approval was needed for the change. Specifically, the NRC team questioned if the emergency feedwater logic change: used a method of evaluation other than what was described in the UFSAR (e.g. the use of the TRANFLOW program) or would result in a more than minimal increase in the likelihood of occurrence of a malfunction of a system important to safety. Specifically, because the emergency feedwater logic change introduced the potential to overcool the reactor, and substituted a previous automatic action for manual operator action, the NRC team questioned if the change and associated 50.59 evaluation addressed these concerns. Planned Closure Actions: The NRC and the licensee are working to gather more information related to the Final Safety Analysis Report-described methods for steam generator analyses and if the change resulted in a more-than-minimal increase in risk. Specifically, the licensee plans to provide an analysis that demonstrates the emergency feedwater logic change would not result in a more than minimal increase in the likelihood of an overcooling accident. Licensee Actions: The licensee has implemented a compensatory measure to take manual control of the emergency feedwater system during a safety injection signal such that an overcooling event will be prevented. Corrective Action References: CR-WF3-2017-06067, CR-WF3-2017-05882, CR-WF3-2017-05173
05000400/FIN-2018002-05Harris2018Q2Failure to Follow Secondary Water Chemistry Plan for Elevated Levels of Secondary Water ImpuritiesAn NRC-identified Green NCV of TS 6.8.4.c, Secondary Water Chemistry, was identified for the licensees failure to follow secondary water chemistry control requirements in accordance with procedure CSD-CP-HNP-0002, Harris Secondary Water Chemistry Strategic Plan. . Specifically, the licensee remained at 100% power for approximately 10 hours after entering secondary water chemistry Action Level 3 due to elevated chlorine and sulfates chemical impurity concentrations, which was contrary to the procedure requirements to downpower the unit to below 5% power as quickly as safe plant operation permits. This unit downpower delay allowed additional time for the chemical impurities to adversely affect the steam generators.
05000275/FIN-2018008-06Diablo Canyon2018Q2Minor ViolationPerformance Deficiency: Failure to install safety-related pressure transmitters (PTs) in accordance with engineering design documents, without documented authorization and prior approval for deviation from that design. Unit 2 Steam Generator pressure transmitters PT-544A and PT-534A were not installed per design. The design called for mounting the PTs on independent unistruts but, contrary to this, the transmitters were installed on a common unistrut. Though the new mounting configurations were documented and analyzed in SAPNs 50881613 and 50881415, Work Order 68039185 which installed the PTs did not record the deviation from originally designed mounting configuration. The licensee attributed the failure to install per original design to human error and initiated SAPN 50976632 to evaluate it. Screening: The performance deficiency is minor in that the current configuration was evaluated not to affect the seismic or structural qualification. Enforcement: This failure to comply with 10 CFR Part 50, Domestic licensing of production and utilization facilities, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, Criterion III, Design Control, constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.
05000400/FIN-2018002-07Harris2018Q2Minor ViolationA minor, self-revealing violation of TS 6.8.1.a, Procedures and Programs,was identified for failure to follow procedure AD-OP-ALL-0200, Clearance and Tagging. On April 7, 2018, while the plant was in Mode 3 at 0 percent power, the licensee isolated breaker DP-1A-1 circuit 28 in accordance with clearance OPS-1-18-5015-DEH MODS-0093. Isolating this breaker caused an unexpected auto start signal for both motor driven auxiliary feedwater (MDAFW) pumps for a loss of last running main feed pump despite the 1B main feedwater pump still being in operation. Both MDAFWs started and operators manually secured the 1B main feedwater pump to maintain proper feedwater flow to the steam generators. TS 6.8.1.a, requires, in part, that written procedures be implemented covering activities referenced in Regulatory Guide 1.33, Revision 2, dated February 1978, including safety-related activities carried out during operation of the reactor plant. Procedure AD-OP-ALL-0200, Section 5.5, step 4, states Clearance impacts must be evaluated to ensure that effects on systems and components outside of the boundary are identified and are acceptable, or properly dispositioned. Contrary to this requirement, the licensee did not identify that the isolation of breaker DP-1A-1 circuit 28 would cause the MDAFWs to auto start in Mode 3 when developing clearance OPS-1-18-5015-DEH MODS-0093. Screening: The violation is minor because the impact to the plant was minimal; the unit was in Mode 3 throughout the event, the reactor remained subcritical, and feedwater flow to the steam generators was not lost. Enforcement: Because the performance deficiency is minor, it will not be subject to enforcement action in accordance with the NRCs Enforcement Policy. The licensee entered this issue into their CAP as NCR 02196873. The associated LER is closed.
05000400/FIN-2018002-04Harris2018Q2Failure to Implement Adequate Steam Generator Blowdown Demineralizer Control ProceduresA self-revealing Green NCV of Technical Specifications (TS) 6.8.1.a, Procedures and Programs, was identified for licensees failure to establish and implement adequate steam generator blowdown demineralizer control operating procedures resulting in exceeding secondary water chemistry Action Level 3 criteria for impurities in the steam generators. Specifically, the licensee did not implement adequate isolation valve controls between the demineralizer resin regeneration system and the feedwater system during resin regeneration activities. This open path allowed leakage of sulfates and chlorides into the feedwater system. The level of these impurities exceeded the secondary chemistry Action Level 3 threshold and resulted in an unplanned shutdown.
05000289/FIN-2018001-01Three Mile Island2018Q1Enforcement Action (EA)-EA-18-029: Multiple Examples of Nonconforming to Design for Tornado Missile ProtectionResulting from a systematic review of plant design and licensing basis Exelon determined four nonconforming conditions where components that could be depended upon to safely shutdown the reactor were not adequately protected from tornado missiles. These conditions include diesel fuel oil and day tank vents, borated water supplies, and once through steam generator pressure control isolation valves.Corrective Action(s): In accordance with the guidance in Regulatory Issues Summary 2015-06 Tornado Missile Protection (ML15020A419) and EGM 15-002, Revision 1, Enforcement Discretion for Tornado Generated Missile Protection Non-Compliance, (ML16355A286) the licensee implemented compensatory measures to maintain the equipment in a degraded but operable condition. These actions include verifying that procedures, training,and equipment are in place to take appropriate action in the event of a tornado watch or warning and establishing a heightened level of awareness and preparedness to tornado missile vulnerabilities. To restore full compliance, the licensee intends to evaluate the vulnerabilities utilizing approved methodologies and submitting a license amendment request per the timeline in Enforcement Guidance Memorandum 15-002, Revision 1.Corrective Action Reference(s):Issue Reports04081290, 04085589, 04085596, 04085607Enforcement:Violation: 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that the applicable regulatory requirements and the design basis for SSCs are correctly translated into specifications, drawing, procedures, and instructions. Contrary to the above, from April 19, 1974, until December 6, 2018, Exelon failed to correctly translate the design basis for protection against tornado-generated missiles into their specifications and procedures. Specifically, Exelon did not adequately protect TMI Unit 1 diesel fuel oil and day tank vents, borated water supplies, and once through steam generatorpressure control isolation valves from tornado generated missiles.Severity/Significance: For violations warranting enforcement discretion, Inspection Manual Chapter 0612 does not require a detailed risk evaluation, however, safety significance characterization is appropriate. The NRC Enforcement Policy, Section 2.2.1 states, in part, that, whenever possible, the NRC uses risk information in assessing the safety significance of violations. Accordingly, the NRC concluded that this issue is of low risk significance based on a generic and bounding risk evaluations performed in support of the resolution of tornado-generated missile non-compliances.Basis for Discretion: Because this violation was identified during the discretion period covered by EGM 15-002, Revision 1, and because Exelon has implemented compensatory measures, the NRC is exercising enforcement discretion, is not issuing enforcement action, and is allowing continued reactor operation.
05000255/FIN-2018001-03Palisades2018Q1Licensee-Identified ViolationA violation of very low safety significance (Green) was identified by the licensee, has been entered into the licensees corrective action program, and is being treated as a Non-Cited Violation consistent with Section 2.3.2 of the Enforcement Policy. Enforcement:Violation: Technical Specification 3.7.6 requires that the combined useable volume of the Condensate Storage Tank (CST) and Primary Makeup Storage Tank (T81) shall be greater or equal than 100,000 gallons. LCO 3.7.6, Condition A states that if the useable volume is not within this limit then A.1 Verify OPERABILITY of backup water supplies in 4 hours andA.2 Restore condensate volume to within limit in 7 days. Condition B states that if the Required Action and associated Completion Time is not met then B.1 Be in MODE 3 in 6 hours and B.2 Be in MODE 4 without reliance on steam generators for heat removal in 30 hours. Contrary to the above, on December 7, 2017 and March 3, 2016, the licensee failed to enter and comply with the actions required by LCO 3.7.6 Condition A and Condition B when Primary Makeup Tank Makeup Control Valve CV2008 could not be fully opened, resulting in a combined useable volume of the CST and T81 of less than 100,000 gallons.Significance/Severity Level: The inspectors answered No to all the questions in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, because even though the CST and T81 volume were considered inoperable by the TS requirements, there was not a loss of safety function because credited backup water sources were available and operable.Therefore, the finding screened as Green.Corrective Action References: The licensee entered these issues into their CAP as CRPLP20175589, CRPLP20175554, CRPLP20175551, and CRPLP20161116
05000445/FIN-2018001-03Comanche Peak2018Q1Failure to Provide an Adequate ProcedureThe inspectors identified a Green,non-cited violation of Technical Specification 5.4.1, Procedures, associated with the licensees failure to provide procedures appropriate to the circumstances. Specifically, station procedure INC-2085, Rework and Replacement of I&C Equipment, did not contain adequate instructions for wiring current to pressure (I/P) converters for safety related components which resulted in the steam generator atmospheric relief valve I/P converters being placed in a seismically unqualified configuration. This finding was entered into the licensees corrective action program as Condition Report CR-2017-011922.
05000364/FIN-2018001-02Farley2018Q1Enforcement Action (EA)-18-025:Unit 2 Main Steam Safety Valve (MSSV) Lift Pressure Outside of Technical Specification LimitsOn October 26, 2017, MSSV Q2N11V0012E was removed from service at Farley Nuclear Plant Unit 2 during a refueling outage, and on November 1, 2017 the valve was tested with steam at an offsite facility. As-found lift testing determined that the valve opened at 1171 psig steam pressure, which was 9 psig high outside the plant technical specification (TS) allowable lift setting range of 1096 psig to 1162 psig. The valve had been in service prior to the plant beginning commercial operation on July 30, 1981, until it was removed from the main steam system on October 26, 2017. The licensee last tested the valve, while installed on the main steam system, on April 5, 2016. The test results indicated the lift pressure was within +/- 1% of the TS 3.7.1 required set pressure of 1129 psig, and no set pressure adjustment was necessary for the valve. The licensee determined that the MSSV high as-found lift set-point did not have an adverse impact on the main steam system over-pressurization protection, since the valve as-found lift setpoint was lower than 110% of steam generator design pressure (1194 psig), and this condition would not have resulted in a loss of safety function. Therefore, the plant remained bounded by the accident analysis in the Final Safety Analysis Report (FSAR), based on the as-found condition. Corrective Action(s): The valve was replaced with an operable MSSV during the refueling outage prior to plant startup.Corrective Action Reference(s): The licensee entered this issue into their Corrective Action Program (CAP) as condition report (CR) 10426186 as found test results for MSSV Q2N11V0012E. Violation: Farley Nuclear Plant, Unit 2 Technical Specifications (TS) limiting condition for operation (LCO) 3.7.1, Main Steam Safety Valves (MSSVs), required five MSSVs per steam generator to be operable. Per TS Table 3.7.1-2, MSSV Q2N11V0012E must have a lift setting within the range of 1096 psig to 1162 psig, while the Unit was in modes 1, 2, and 3. With one MSSV inoperable and the Moderator Temperature Coefficient (MTC) zero or negative at all power levels, Action Statement, Condition A, Required Action A.1, required reducing thermal power to 87% RTP within 4 hours. If the required action and associated completion time is not met, Action Statement, Condition C, required that the unit be in mode 3 within 6 hours.Contrary to the above, the licensee determined the MSSV setting was outside the TS limits longer than 10 hours during the operating cycle between May 11, 2016 and October 15, 2017, while the Unit was in modes 1, 2, and 3. Severity/Significance: The inspection assessed the severity of the violation using Section 6.1 of the Enforcement Policy and determined the significance is appropriately characterized at Severity Level IV, due to the inappreciable potential safety consequences. The significance of this violation was informed, in part, using IMC 0609, Appendix A, The Significance Determination Process (SDP) for findings at Power, dated June 19, 2012. Basis for Discretion: The NRC exercised enforcement discretion in accordance with Section3.10 of the Enforcement Policy because the MSSV as-found lift pressure issue was not reasonably foreseeable and preventable. The inspectors reached this conclusion due to the fact that the licensee last tested the valve satisfactorily, while installed on the main steam system, on April 5, 2016, and during the period of time that the valve was in service, following May 11, 2016, there was no indication of valve degradation (e.g. seat leakage)
05000272/FIN-2018001-03Salem2018Q1Failure to Establish Containment Integrity during Plant StartupThe inspectors determined there was a self-revealing Green non-cited violation (NCV)of Technical Specification (TS) 6.8.1, Procedures and Programs, when PSEG did not follow procedure S1.OP-SO.SG-0002, Maintaining Steam Generators in Wet Layup, Revision 10, step 5.7.7L, to close the 14 steam generator (SG) blowdown manual nitrogen supply valves prior to entry into MODE 4 on November 7, 2017, and MODE 3 on November 9, 2017. Specifically, 14 SG blowdown manual nitrogen supply valves were left open during startup transition from MODE 5 through MODE 3 (Hot Standby), which resulted in a steam leak into the Unit 1 auxiliary building (AB) through an actual open pathway upstream of the 14 SG blowdown containment isolation valve.
05000335/FIN-2018001-01Saint Lucie2018Q1Improper Evaluation of LCV-9005 position setpoints Leads to AFASOn November 19, 2013, during reactor startup activities, feedwater bypass valves, A (LCV-9005) and B (LCV-9006), were found to be operating at different throttle positions while maintaining their respective steam generator water levels. Valves LCV-9005 and 9006 were both originally installed in April 1978. LCV-9005 was replaced in 1994, with an equivalent valve, due to obsolescence. The original valve had a full open stroke length of 1.5 inches (in.), while the new equivalent valve had a full open stroke length of 2 in. to provide the same flow as the original valve. When installed, LCV-9005 was set up to limit its stroke length to 1.5 in., matching the replaced valve, and the associated drawings were never revised to show that the new valve had a full 2 in. open stroke length. In 2009, the distributed control system (DCS) was installed utilizing these drawings and was setup under the assumption that both valves, LCV-9005 and LCV-9006, were the same model valves and stroke lengths.The DCS system was designed to provide a signal to throttle the feedwater bypass valves following a reactor trip to 20 percent open to provide approximately 5 percent feed flow in order to recover steam generator water levels utilizing main feedwater. During Unit 2 startup activities in November 2013, the licensee noted a discrepancy in the valve positions for LCV-9006 and LCV-9005 when they were providing steam generator water level control. The licensee placed the issue in the corrective action program under Action Request (AR) 1921720 and determined that it was necessary to evaluate a revision of the LCV-9005 DCS setpoint, which was accomplished by an engineering condition evaluation under AR 1925428. The engineering condition evaluation was inadequate in that it failed to recognize the differences in the two different model valves, and therefore failed to provide adequate corrective actions to address performance issues associated with these differences.The final recommendation from AR 1925428 was that the current LCV-9005 setting did not impose any risk to the plant operation, as the 2A steam generator level had been within acceptable range with no control room alarm observed. Therefore, no setpoint change was required at that point.On October 26, 2017, following a Unit 2 trip, LCV-9005 was sent a digital DCS demand signal to be 20 percent open. Since the valve was locally set to have a maximum stroke of 1.5 in. instead of 2 in. open, the actual flow through the valve was less than 5 percent. This resulted in flow lower than needed to maintain 2A steam generator level, and caused level to lower, which eventually resulted in an actuation of the A train auxiliary feedwater actuation system (AFAS). Corrective Action(s):The licensee implemented corrective actions to: 1) properly set up LCV-9005 in order for it to have a full stroke length of 2 inches so that it could provide the required feedwater flow and, 2) update associated drawings to include correct stroke lengths.Corrective Action Reference(s): This issue was entered into the licensees CAP as AR 2232869
05000443/FIN-2017004-03Seabrook2017Q4Inadequate Procedure Implementation Results in a Manual Reactor TripA self-revealing Green finding was identified for inadequate implementation of procedure MA 4.5, Configuration Control, Revision 18. Specifically, maintenance technicians failed to properly implement MA 4.5 while backfilling steam generator instrumentation, and inadvertently left an instrumentation valve partially open instead of fully open. This resulted in slow response of the instrument, and ultimately a high steam generator level, a feedwater isolation signal and a manual reactor trip. NextEra promptly rechecked other similar valves, then performed a root cause evaluation that eventually led to additional technician training and improved configuration controls during such evolutions. This finding is more than minor because it is associated with the configuration control attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to effectively implement MA 4.5 resulted in a valve being left out of its required position, a subsequent lack of steam generator water level control during low power operations, and ultimately required a manual reactor trip. In accordance with IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green), because the fin ding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. Additionally, the finding has a cross-cutting aspect in the area of Human Performance, Work Management, because the organization did not implement a process of planning, controlling, and executing the work activity such that nuclear safety was the overriding priority. Specifically, NextEra did not ensure that a steam generator backfilling activity was properly executed, which resulted in the slow response of a steam generator level indication, the overfeeding of the steam generator, a feedwater isolation signal, and the ultimate requirement to trip the reactor. (H.5)
05000247/FIN-2017010-01Indian Point2017Q4Inadequate Diesel Fuel Oil Temperature ProtectionThe NRC identified a finding for the failure to assure that diesel powered Diverse and Flexible Coping Strategies (FLEX) equipment would be reliable to mitigate postulated beyond-design basis external events during very low temperature conditions. Specifically, at temperatures below 21F, portable FLEX equipment, such as emergency diesels, steam generator and reactor makeup pumps, and transfer pumps, were susceptible to conditions in which they would not have been capable of starting and operating due to fuel crystalizing or gelling. (CR-IP2-2017-04902/IP3-2017-05574)The failure to ensure that the portable diesel equipment could function within the required temperature range was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The significance of the finding was evaluated using NRC Inspection Manual Chapter 0609, Appendix O, Significance Determination Process for Mitigating Strategies and Spent Fuel Pool Instrumentation (Orders EA-12-049 and EA-12-051), dated October 7, 2016, and Appendix M, Significance Determination Process Using Qualitative Criteria, dated April 12, 2012. The event of concern was determined to be a seismic event greater than 0.3g resulting in a loss of offsite power during extreme cold weather events. A bounding evaluation was performed in accordance with Step 4.1.1 of Appendix M. Indian Point declared full compliance with the order on August 12, 2016. The preliminary review of available weather conditions for the site, from the time of full compliance, shows that the temperature was below the cloud point of the fuel for over 200 hours. The Indian Point Unit 3 External Initiator Risk Informed Notebook was utilized to estimate the risk and was determined to adequately model the risk of both units. Utilizing Table 5.3.2, sequences that included emergency power, auxiliary feedwater, and high pressure makeup were evaluated. Assuming a 200 hour exposure and the unavailability of all diesel driven FLEX equipment the risk was determined to less than 1E-7/yr. Therefore, the finding was determined to have a very low risk significance. The finding had a cross-cutting aspect in the Avoiding Complacency of the Human Performance area because the licensee failed to ensure that all susceptible elements of the mitigation strategies were designed, maintained, or operated in such a manner that they could reliably function over then entire temperature spectrum for beyond-design basis external events. (H.12)
05000251/FIN-2017004-03Turkey Point2017Q4Inadequate Installation of Outdoor Use Electrical Enclosures Results in Manual Reactor TripA self-revealing finding (FIN) was identified for failure to ensure the 4B and 4C main feedwater regulating valve (MFRV) control circuits remained free from the effects of water intrusion or condensation in electrical enclosures. Specifically, a hand selector switch (HSS) enclosure for the 4C MFRV redundant positioners was flooded during wind-driven rain and resulted in the 4C MFRV failing closed, lowering 4C steam generator water level, and a subsequent Unit 4 manual reactor trip initiated by control room operators.Engineering Change (EC) 246879 appropriately selected NEMA-4X rated enclosures for the HSSs but associated SPEC-C-065 did not provide critical configuration details for the enclosure installations. Water collected in the 4B and 4C MFRV positioner HSS enclosures because the penetrations were on top of the enclosures and not properly sealed and the bottom of the enclosure did not have a weep hole.This performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and adversely affected the cornerstones objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations, because the failure resulted in lowering steam generator water levels and caused control room operators to complete a fast load reduction and manually trip the reactor. In accordance with NRC IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, the inspectors determined that the issue had very low safety significance because it only caused a reactor trip and did not cause the loss of mitigating equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Since EC 246879 and associated work orders were completed in 2013, the inspectors determined the finding was not indicative of current licensee performance and was not assigned a cross-cutting aspect.
05000395/FIN-2017007-01Summer2017Q4Failure to Verify the Adequacy of Design for the EFW system when Supplied by SWThe NRC identified a non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to verify the emergency feedwater (EFW) pumps would be capable of taking suction from service water for an indefinite period of time as required by Updated Final Safety Analysis Report Section 10.4.9.2. The licensee entered this issue into their corrective action program (CAP) as condition report (CR) 17-05528 and performed an operability determination to verify the EFW pumps remained operable. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to evaluate worst-case design conditions resulted in a reasonable doubt that the EFW pumps could provide cooling water to the steam generators and perform their design basis function. The team determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, and component (SSC), and the SSC maintained its operability. The team determined that no crosscutting aspect was applicable because the finding did not reflect current licensee performance
05000348/FIN-2017009-01Farley2017Q4Failure to Report a Condition Which was Prohibited by Technical SpecificationsThe NRC identified a Severity Level IV (SL IV) non-cited violation of 10 CFR 50.73(a)(2)(i)(b) for failure to report plant operation prohibited by Technical Specification (TS) 3.3.2. Specifically, the licensee failed to perform a past operability evaluation and failed to recognize for having two steam flow channels on the 1 C steam generator inoperable longer than allowed by TS 3.3.2. Consequently, this condition was not discussed and reported on the Licensee Event Report (LER) 2016-007-00 or 2016-007-001. The issue was entered into the licensees CAP as condition report 10413856.This violation adversely affected the NRCs ability to perform its regulatory function; the NRC relies on licensees ability to identify and report conditions or events meeting the criteria specified in the regulations. The licensee did not evaluate past operability and failed to recognize, for the purpose of reportability, that the point of discovery occurred when the data was collected. Because this issue affected the NRC's ability to perform its regulatory function, it was evaluated using the traditional enforcement process. Consistent with the guidance in Section 6.9, Paragraph d.9, of the NRC Enforcement Policy and Guidance in Section 2.3.2.a, this finding was determined to be a Severity Level IV non-cited violation. This finding has no cross-cutting aspect as it was strictly associated with a traditional enforcement violation.
05000446/FIN-2017003-01Comanche Peak2017Q3Failure to Promptly Correct a Condition Adverse to QualityThe inspectors identified a non- cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, associated with the licensees failure to take timely corrective actions for a condition adverse to quality. Specifically, the licensee failed to take corrective actions for a leak in the hydraulic snubbers for the Unit 2, loop 3 steam generator, resulting in the level in the hydraulic fluid reservoir going below the minimum level in the sight glass on multiple occasions. This issue does not represent an immediate safety concern because the licensee took action to refill the hydraulic fluid reservoir. The licensee entered this issue into its corrective action program as Condition Report CR -2017- 009071. The licensees failure to take timely and adequate corrective actions to correct a condition adverse to quality was a performance deficiency. The performance deficiency is more than minor , and therefore a finding, because it is associated with the protection against the external events performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences . Specifically, the failure to correct the leak resulted in the hydraulic fluid reservoir level dropping below the minimum sight glass level , and loss of reasonable assurance of adequate oil in the snubbers to support their operation. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A , Significance Determination Process for Findings At -Power , Exhibit 4 , External Events Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because: (1) the loss of the equipment by itself during the external initiating event it was intended to mitigate would not cause a plant trip or initiating event, would not de grade two or more train s of a multi -train system or function, and would not degrade one or more trains of a system that supports a risk significant system or function, and (2) the finding did not involve the total loss of any safety function that contributes to external event initiated core damage accident sequences. The finding has a human performance cross -cutting aspect associated with work management , in that, the licensee failed to ensure that the process of planning, controlling, and executing work 3 activities was implemented to ensure nuclear safety was the overriding priority (H.5 )
05000445/FIN-2017002-03Comanche Peak2017Q2Relays not Environmentally QualifiedGreen. The inspectors identified a non- cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, associated with the licensees failure to assure that design changes were subject to design control measures commensurate with those applied to the original design. Specifically, the licensee changed internal components for safety -related, steam generator atmospheric relief valve booster relays but failed to verify that these new components could withstand the environment created during a high energy line break. This issue does not represent an immediate safety concern because the licensee performed an operability determination which established a reasonable expectation for operability, and implemented corrective actions to replace the relays with qualified relays. The licensee 4 entered this issue into the corrective action program for resolution as Condition Report CR- 2017- 006236. The failure to ensure that changes to the facility were subject to design control measures commensurate with those applied to the original design was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the associated objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Attachment 04, Initial Characterization of Findings, dated October 7, 2016, and Inspection Manual Chapter 0609, Appendix A, Significance Determination Process for Findings At -Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding was of very low safety significance (Green) because the finding: (1) was not a deficiency affecting the design and qualification of a mitigating structure, system, or component, and did not result in a loss of operability or functionality, (2) did not represent a loss of system and/or function, (3) did not represent an actual loss of function of at least a single train for longer than its allowed outage time, or two separate safety systems out -of-service for longer than their technical specification allowed outage time, and (4) does not represent an actual loss of function of one or more non- technical specification trains of equipment designated as high safety -significant for greater than 24 hours in accordance with the licensees maintenance rule program. The inspectors did not assign a cross -cutting aspect because the performance deficiency was not reflective of present performance
05000391/FIN-2017002-01Watts Bar2017Q2Inadequate Chemistry Procedure Results in Inoperable Containment Isolation ValvesSL IV. A self-revealed severity level (SL) IV non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when implementing an inadequate procedure resulted in rendering the steam generator chemistry sample containment isolation valves inoperable. The licensee entered this issue into their corrective action program as CR 1160910. The inspectors determined that the use of an inadequate procedure that rendered the containment isolation valves inoperable was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC-2517, Appendix C, because the use of an inadequate procedure rendered the containment isolation valves inoperable. The inspectors determined this finding to be of very low safety significance because it did not represent a breakdown of the licensees quality assurance program. This finding had a cross-cutting aspect in the work management component of the Human Performance cross-cutting area because the work process did not include the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities (H.5).
05000445/FIN-2017001-01Comanche Peak2017Q1Failure to Maintain B.5.b Equipment in a State of Readiness to Support Mitigation StrategiesGreen. The inspectors identified a non-cited violation of 10 CFR 50.54(hh)(2), Conditions of Licenses, involving the licensees failure to maintain available equipment needed to implement mitigating strategies to provide makeup to steam generators following loss of large areas of the plant due to explosions or fire. Specifically, the licensee failed to maintain available a portable alternate mitigation equipment pump related to the steam generator makeup strategy. As an immediate corrective action the licensee put temporary heaters in place for the alternate mitigation equipment pump to ensure the equipment was stored at temperatures greater than 32 degrees Fahrenheit pending further evaluation. The licensee entered this issue into their corrective action program as Condition Report CR-2016-010832. The failure to maintain all necessary equipment available to implement mitigating strategies as required by regulations and conditions of the operating license was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Inspection Manual Chapter 0609, Appendix L, B.5.b Significance Determination Process, dated December 24, 2009, the inspectors determined the finding was of very low safety significance (Green) because it resulted in an unrecoverable unavailability of an individual mitigating strategy but did not result in multiple unavailable mitigating strategies, or loss of all on-site, self-powered, portable pumping capability. The inspectors did not assign a cross-cutting aspect because the performance deficiency was not reflective of present performance.
05000261/FIN-2017001-03Robinson2017Q1Licensee-Identified Violation10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non- confor mances are promptly identified. Contrary to the above, in March 2014, while performing examinations in steam generator C during forced shutdown RFO229F3, the licensee failed to identify a loose part lodged in contact with tube R37C22. The licensee identified the loose part in March 2017 during refueling outage RO30. The licensee verified that indications of the part were detectable during RFO229F3, retrieved the part, verified that degradation caused by the part met all structural integrity requirement s, plugged the tube, and removed it from service. This issue was identified in the licensees CAP as NCR 0210725. The inspectors evaluated this violation using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and 0609 Appendix A, The Significance Determination Process (SDP) for Findings At -Power, and determined that the violation was of very low safety significance (Green) because evaluations demonstrated that the tube could sustain three times the differential pressure across it during normal full power steady state operation and that the steam generator did not violate the accident leakage performance criterion
05000313/FIN-2017001-03Arkansas Nuclear2017Q1Inadvertent Reactivity AdditionGreen. Inspectors documented a Green self-revealing finding and associated non-cited violation of Unit 1 Technical Specification 5.4.1.a. Specifically, the licensee failed to properly pre-plan and perform maintenance of the integrated control system equipment that can affect the performance of safety-related equipment. The licensee failed to plan and perform post-maintenance testing on newly installed integrated control system cards before returning the system to service. As a result, the licensee failed to detect a failed card. When the associated controller was placed into automatic mode, the system responded to a false demand signal that resulted in an inadvertent rod withdrawal that required prompt operator action to terminate the power increase and restore power to the original level. To correct the failed card, the licensee installed a new card that had been tested and validated prior to installation. The licensee documented this issue in Condition Report CR-ANO-1-2016-05551. Inspectors concluded that the failure to perform a post-maintenance test prior to placing a component in service is a performance deficiency. Specifically, the work order for replacing the steam generator reactor demand circuit card did not include a verification that the system was functioning properly after the replacement card was installed in the plant. The performance deficiency is more than minor because if left uncorrected, the performance deficiency has the potential to become a more significant safety concern. Specifically, if the operator had not taken prompt action to mitigate the event, it could have resulted in a more significant plant transient and could have challenged plant equipment. In accordance with Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, issued October 7, 2016, and Exhibit 1 of IMC 00609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Issued June 19, 2012, the inspectors determined the finding to be of very low safety significance (Green) because the finding is associated with the initiating events cornerstone and did not cause a reactor trip. The finding was determined to have a cross-cutting aspect in the area of human performance associated with Work Management, because the licensee did not ensure that they followed a process of planning, controlling, and executing the work activities in a formalized manner, allowing the work order to not have complete instructions for a post-maintenance test. (H.5)
05000382/FIN-2016008-03Waterford2016Q4Failure to Include Appropriate Quantitative Acceptance Criteria for the Reconstituted Feedwater/Emergency Feedwater Monitoring Plan Associated with Steam Generator Replacement Induced VibrationThe team identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to include appropriate quantitative accept an cecriteria for determining that important activities have been satisfactorily accomplished. Specifically, the licensees reconstituted feedwater and emergency feedwater system monitoring plan, which was created to monitor both systems vibrations following the sites steam generators replacement, did not include a range for acceptable vibration levels for all The team identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to include appropriate quantitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, the licensees reconstituted feedwater and emergency feedwater system monitoring plan, which was created to monitor both systems vibrations following the sites steam generators replacement, did not include a range for acceptable vibration levels for all
05000272/FIN-2016004-01Salem2016Q4Inadequate Maintenance Procedure for Steam Generator Feedwater Pump Coupling Hub Set Screw InstallationGreen: A self-revealing Green finding (FIN) against MA-AA-716-010, Maintenance Planning Process, step 4.2.3, Revision 18, was identified for PSEGs inadequate maintenance guidance that resulted in 11 steam generator feedwater pump (SGFP) elevated vibrations and required an emergent down power to be taken out of service due to a coupling and shaft failure. PSEG entered this issue in their CAP as notification (NOTF) 20739299, conducted a prompt investigation, troubleshooting, repairs, and a completed a causal evaluation under Order 70189096. This issue was more than minor since it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened to Green in accordance with IMC 0609, Appendix A, because the finding did not represent an actual loss of function of one or more non-TS equipment trains designated as high safety-significant in accordance with PSEGs Maintenance Rule (MR) program. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience (OE), because PSEG did not ensure that the organization systematically and effectively collects, evaluates, and implements relevant internal and external operating experience in a timely manner. (P.5)
05000346/FIN-2016004-01Davis Besse2016Q4Mispositioned Instrument Air Valves Result in Plant TransientA self-revealed finding of very low safety significance was identified for the licensees failure to appropriately follow station procedures for aligning instrument air valves that support main feedwater (MFW) regulating valve operation. Specifically, two instrument air valves were not aligned to their normal operating position following planned maintenance. As a result, the Steam Generator 2 (SG 12) MFW Regulating Valve momentarily closed during routine steam feedwater rupture control system (SFRCS) surveillance testing and caused a plant transient. Corrective actions taken by the licensee, include but are not limited to, performance of an instrument air valve line up to validate no other valves were out of position; performance of SFRCS Actuation Channel 2 testing to verify no other half trips existed on SFRCS Actuation Channel 2 components; a configuration control stand-down with the instrument and control shop; and revisions to procedural guidance to perform additional valve position verification. The finding was of more than minor significance because it was associated with cornerstone attribute of configuration control and adversely affected the cornerstone objective: To limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The finding was determined to be of very low safety significance because the finding did not cause a reactor scram with the loss of mitigation equipment relied upon to transition the plant from the onset of the scram to a stable shutdown condition (e.g. loss of condenser, loss of feedwater). The inspectors determined that the finding had a cross-cutting aspect in the area of human performance. The inspectors assigned the cross-cutting aspect of Avoid Complacency to the finding because the procedural step to close valve IA1008A was marked as complete but was not performed correctly. Additionally, appropriate human performance error reduction tools were not adequately used to ensure valve manipulations were performed as intended. (H.12)
05000382/FIN-2016008-04Waterford2016Q4Departure from Approved Method to Determine Steam Generator Internal Loads During Main Steam Line BreakThe team identified a Severity Level IV non-cited violation of 10 CFR 50.59(c)(2),Changes, Tests, and Experiments, for the licensees failure to obtain a license amendment prior to implementing a proposed change, test, or experiment that would result in a departure from a method of evaluation described in the final safety analysis report (as updated) used in establishing the design bases or in the safety analyses. Specifically, the licensee departed from their approved CEFLASH-4A methodology to determine steam generator internal differential loads caused by a main steam line break to an unapproved TRANFLOW methodology. In response to this issue, the licensee entered the issue into the corrective action program as Condition Report CR-WF3-2016-07639 and initiated actions to prepare a new evaluation under current regulatory guidelines or to submit a license amendment request to the NRC.The licensees failure to obtain a license amendment prior to implementing a change that resulted in a departure from a method of evaluation described in the final safety analysis report (as updated) used in establishing the design bases or in the safety analyses, as required by 10 CFR 50.59(c)(2) was a violation. In accordance with the NRC Enforcement Manual, violations of 10 CFR 50.59 are not processed through the Reactor Oversight Process significance determination process because this violation potentially impacted the ability of the NRC to perform its regulatory oversight function. Therefore, this violation was processed through traditional enforcement examples of Section 6.1 of the NRC Enforcement Policy. This violation was more-than-minor because there was a reasonable likelihood that the change would require NRC review and approval prior to implementation, similar to the more-than-minor example of a change in requirements in the NRC Enforcement Manual,Appendix E, Minor Violations Examples, dated September 9, 2013. In accordance with the NRC Enforcement Policy, the significance determination process was used to inform the significance of the failure to obtain a license amendment prior to implementing a proposed change. The departure from the original CEFLASH-4A method to the TRANFLOW method to determine differential loads on steam generator internal structures following a main steam line break event was associated with the design control attribute of the Barrier Integrity Cornerstone and adversely affected the objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012,Exhibit 1, Initiating Events Screening Questions, the issue screened as having very low safety significance (Green) because the issue would not result in the complete or partial loss of a support system that contributes to the likelihood of an initiating event, or result in the steam generators violating accident leakage performance criterion. Since the violation was determined to be Green in the significance determination process, the traditional enforcement violation was determined to be a Severity Level IV violation, consistent with the example in paragraph 6.1.d(2) of the NRC Enforcement Policy. Traditional enforcement violations are not assessed for cross-cutting aspects.
05000306/FIN-2016004-05Prairie Island2016Q4Licensee-Identified ViolationNorthern States Power CompanyMinnesota (NSPM), Prairie Island Nuclear Generating Plant Renewed Facility Operating License, Appendix B, Additional Conditions, Facility Operating License No. DPR42 and DPR60 (Amendment Nos. 206 and 193, respectively), required, in part, that The Alternate Source Term (AST) License Amendments 206/193 will be implemented after installation of the Unit 2 Replacement Steam Generators (RSGs) within 90 days after the completion of the outage in which the Unit 2 RSGs are installed. Further, implementation requirements incorporated within License Amendment 206/193 stated, in part, that prior to implementation of the AST license amendment, NSPM will revise the Prairie Island Nuclear Generating Plant design and licensing bases to indicate that the Steam Generator Water LevelNarrow Range Instruments are required to meet Regulatory Guide 1.97, Revision 2 requirements. Contrary to the above, on March 27, 2014, the licensee failed to revise the Prairie Island Nuclear Generating Plant design and licensing bases to indicate that the SGNR instruments were required to meet Regulatory Guide 1.97, Revision 2 requirements. Because the inspectors answered Yes to Question 1 under Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, the finding screened as very low safety significance (Green). The above issue was documented in the licensees CAP as CAP 1424460. Corrective actions included replacement of the SGNR instrumentation with Regulatory Guide 1.97 compliant equipment.
05000282/FIN-2016004-01Prairie Island2016Q4Baffle Former Bolting Acceptance CriteriaFrom October 17November 28, 2016, the inspectors conducted a review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS), risk-significant piping and components and containment systems. This inspection constituted one ISI sample (see Sections 1R08.1, 1R08.3 and 1R08.5 below), as defined in IP 71111.0805. .1 Piping Systems Inservice Inspection a. Inspection Scope The inspectors either observed or reviewed records of the following Non-Destructive Examinations (NDEs) mandated by the American Society of Mechanical Engineers (ASME), Section XI Code, to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement. Ultrasonic examination of tubesheet to shell for steam generator (SG) 11; Magnetic particle examination of an integral attachment support rod for SG 11; Visual examination of reactor vessel nuts and washers (1 through 16); and Unit 1 metallic containment liner visual examination in 2012. During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee had not identified any recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute. The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refueling outage to determine if the licensee applied the preservice NDEs, and acceptance criteria required by the Construction Code and ASME Code, Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of Construction Code and ASME Code Section IX. Unit 1 reactor coolant pump (RCP) seal replacements. b. Findings No findings were identified. .2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities a. Inspection Scope The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage for Unit 1. Therefore, no NRC review was completed for this inspection procedure attribute. For the Unit 1 vessel head, no examination was required pursuant to Title 10 of the Code of Federal Regulations (10 CFR), Part 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review was completed for this inspection attribute. b. Findings No findings were identified. .3 Boric Acid Corrosion Control a. Inspection Scope The inspectors performed an independent walkdown of the RCS and related lines in the containment, which had received a recent licensee boric acid walkdown, and verified whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components. The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the ASME Section XI Code. 11 RCP seal bowl. The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI. CAP 1465567; 12 RCP Seal Leakage. b. Findings No findings were identified. .4 Steam Generator Tube Inspection Activities a. Inspection Scope The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute. For the Unit 1 SGs, no examination was required pursuant to the TSs during the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute. b. Findings No findings were identified. .5 Identification and Resolution of Problems a. Inspection Scope The inspectors performed a review of ISI/SG-related problems entered into the licensees CAP, and conducted interviews with licensee staff to determine if: the licensee had established an appropriate threshold for identifying ISI/SG-related problems; the licensee had performed a root cause evaluation (if applicable) and taken appropriate corrective actions; and the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity. The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI requirements. Documents reviewed are listed in the Attachment to this report. b. Findings (1) Baffle Former Bolting Analysis Acceptance Criteria Introduction: The inspectors identified an Unresolved Item (URI) concerning the analysis that demonstrated the design adequacy of the baffle former bolting under design and licensing basis loading conditions. Description: The inspectors reviewed WCAP 17586P, Determination of Acceptable Baffle-Barrel Bolting for Prairie Island Units 1 and 2, Revision 0; WCAP15030NPA, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions under Faulted Load Conditions, dated March 2, 1999; and Safety Evaluation by the Office of Nuclear Reactor Regulation of WCAP15029, Westinghouse Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting Distributions Under Faulted Load Conditions, dated November 10, 1998. The inspectors were concerned that the licensee had evaluated the baffle former bolting using acceptance criteria different than what was reviewed and approved by the Office of Nuclear Reactor Regulation. In WCAP15030NPA, Section 4.3.2 stated that the stress allowable for primary membrane and bending of irradiated bolt material is taken to 0.9 times Sy (yield stress of baffle bolt material) for the faulted load condition. The stress allowable used in WCAP 17586P was based on ASME, Section III, Appendix F, specifically: (minimum of (0.9 times Su) ultimate stress of baffle bolt material), maximum of (0.67 times Su, Sy + 1/3 (Su - Sy)). The inspectors also reviewed 10 CFR 50.59 Screening No. 4443, Determination of Acceptable Baffle-Barrel Bolting, dated January 24, 2013, to determine whether the licensee performed a 50.59 evaluation for the use of ASME, Section III, Appendix F acceptance criteria. However, the inspectors identified that the change for the use of ASME, Section III, Appendix F acceptance criteria in lieu of the acceptance criteria contained in Section 4.3.2 of WCAP15030NPA was not explicitly reviewed in 50.59 Screening No. 4443. In response to the inspectors concern, the licensee initiated CAP 1539487, Documentation Missing in 50.59 Screening 4443, dated October 26, 2016. This issue is an URI pending evaluation of these concerns by the licensee, subsequent inspector review, and discussion with the licensee and Office of Nuclear Reactor Regulation (URI 05000282/201600401; 05000306/201600401; Baffle Former Bolting Analysis Acceptance Criteria).
05000313/FIN-2016004-04Arkansas Nuclear2016Q4Licensee-Identified ViolationDuring the fall 2016 Unit 1 refueling outage, the licensee foreign object search and retrieval (FOSAR) inspections in the steam generator bowls and reactor vessel identified a number of foreign objects, including an 8-inch metal rod. Discussions with the licensee indicated that some of the debris constituted foreign material that should have been prevented from being introduced into the RCS by the foreign material exclusion program. The inspectors concluded that the foreign material was most likely introduced during the previous refueling outage. During the prior operating cycle, the licensees chemistry sampling identified increased RCS activity, and subsequent fuel bundle examinations of fuel removed from the core identified wear marks through the cladding of two adjacent fuel pins. The fuel assembly with the damage was not placed back into the RCS. Since there was no evidence of broken components inside the RCS, the licensee concluded that the most likely cause was the introduction of foreign material. While it was not possible to determine whether any of the foreign material had actually caused the fuel damage, the inspectors concluded that the licensee had failed to control foreign material and prevent it from entering the RCS. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions, procedures, or drawings of a type appropriate to the circumstances. Licensee Procedure EN-MA-118, Foreign Material Exclusion, Revision 10, an Appendix B quality-related procedure, provides instructions for controlling foreign material. Procedure EN-MA-118, Step 5.5, requires, in part, that all material and tools that were introduced to the FME zone are accounted for. Contrary to the above, between January 25, and March 1, 2015, the licensee failed to ensure that all material and tools that were introduced to the FME zone were accounted for. Specifically, the licensee failed to maintain adequate FME control, leading to two damaged cladding pins and slightly elevated dose rates in the RCS piping, as well as another piece of metallic FME in the vessel, as documented in CR-ANO-1-2016-03340. This issue was documented in the licensees corrective action program under CR-ANO-1-2016-03521. Corrective actions taken include a search for the foreign material and permanent removal of the fuel assembly from the core. Prior to 2012, the NRCs Significance Determination Process in IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, contained guidance to screen all more than minor performance deficiencies affecting fuel barriers to very low safety significance. The inspection manual chapters were restructured in 2012, and the screening was inadvertently omitted, though the NRC was in the process of reinstating that same guidance. Therefore, after consultation with the Office of Nuclear Reactor Regulation, the inspectors determined that this finding is of very low safety significance (Green).
05000346/FIN-2016010-01Davis Besse2016Q310 CFR 50.59 Evaluation Failed to Consider Change to Seismic Licensing BasisA finding of very-low safety significance and an associated NCV of Title 10 of the Code of Federal Regulations (CFR), Part 50.59(b)(1), Changes, Tests, and Experiments, (effective January 1, 1991) was identified by the inspector for the licensees failure to maintain records that included a written safety evaluation which provided the bases for determining that the change to seismic licensing basis damping in calculations to support removal of snubbers under modification 90-0079 did not involve an unreviewed safety question. Specifically, licensee safety evaluation SE91-0046 did not provide a suitable basis for concluding that there was no increase in the probability of occurrence of a malfunction of equipment important to safety previously evaluated in the safety analysis report, in that it did not address how the basis for the NRCs-approval of the seismic design of the reactor coolant system continued to be met with respect to the steam generator slider support (Lubrite plate) damping. In particular, a May 31, 1983, NRC Safety Evaluation Report approved the licensees use of 0.15g safe shutdown earthquake ground acceleration in its seismic analysis for reactor coolant system design, in part, because there is sufficient conservatism and margin in the piping systems components and supports at Davis-Besse Unit 1 to ensure safe shutdown and continued shutdown heat removal in the event of a safe shutdown earthquake having a ground acceleration of 0.20g. The licensee subsequently adopted a significantly higher damping value for the steam generator slider support while maintaining a 0.15g acceleration for the design without addressing how sufficient conservatism and margin otherwise continued to be met. The licensee entered this issue into its corrective action program. The inspector determined that the licensees failure to provide in its 10 CFR 50.59 evaluation, SE91-0046, a suitable basis for the determination that the use of damping higher than established in the seismic licensing basis for the reactor coolant system, specifically the steam generator slider support, was not an unreviewed safety question was a performance deficiency. The issue of concern was determined to be more than minor because the performance deficiency impacted the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers (reactor coolant system) protect the public from radionuclide releases caused by accidents or events and the design control attribute to maintain functionality of the reactor coolant system. The inspector evaluated the underlying technical issue using IMC 0609, The Significance Determination Process for Findings at Power, Appendix A, Exhibit 1, Initiating Events Screening Questions. The inspector answered No to all the questions in Exhibit 1. In particular, because the reactor coolant system remained operable (capable of performing its safety function during a seismic event), the finding was determined to have very-low safety significance (Green) corresponding to a Severity Level IV violation per Example 6.1.d.2 of the NRC Enforcement Policy. The inspector did not identify a cross-cutting aspect associated with the finding because the finding was not representative of current performance.
05000346/FIN-2016003-02Davis Besse2016Q3Inadequate Modification Design Control Measures Result in Reactor Protection System InoperabilityA self-revealed finding of very low safety significance and an associated NCV of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion III, Design Control, were identified for the licensees failure to have adequately prepared and implemented a permanent plant modification associated with steam generator (SG) replacement during the units 18th RFO in 2014. Specifically, in conjunction with SG replacement the licensee had also replaced a significant amount of reactor coolant system (RCS) piping and instrumentation, including all RCS hot leg resistance temperature detectors (RTDs). The RTD housings were improperly insulated during the modification, such that over the ensuing reactor operating cycle the RTD wiring insulation degraded to the extent that nearly all the RTDs were rendered inoperable. This issue was entered into the licensees CAP. Corrective actions by the licensee included replacement of the degraded RTDs. This finding was of more than minor safety significance because it affected the attribute of design control of the Mitigating Systems cornerstone of reactor safety, and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of the units RPS. Specifically, the inspectors determined that the licensees failure to have properly designed and implemented the insulation packages for the RTD housings ultimately resulted in the overheating and degradation of the RTD wiring insulation and inoperability of the RTDs associated with the RCS high temperature and RCS pressure/temperature reactor trips. The finding was determined to be of very low safety significance based on a detailed risk analysis that yielded a change in core damage frequency (CDF) of less than 1E7 events per year. The inspectors determined that the finding had a cross-cutting aspect in the area of human performance. The inspectors assigned the cross-cutting aspect of Field Presence to the finding because the licensees SG replacement project management team failed to reinforce the importance of close communication between responsible engineers with overlapping and interfacing modification packages, and did not adequately promote effective work execution through the use of clearly defined work documents that were written and structured to minimize the likelihood for human error. (H.2)
05000336/FIN-2016008-01Millstone2016Q3Unapproved OMA in Lieu of Meeting III.G.2 Fire Protection Requirements for Fire Area R-14, Lower 4kV Switchgear Room and Cable VaultThe team identified a finding of very low safety significance (Green) involving a noncited violation of Millstone Power Station, Unit 2, Renewed Facility Operating License Condition 2.C.(3) to implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report (FSAR). Specifically, Dominion failed to maintain the #2 steam generator (SG) atmospheric dump valve (ADV) free from fire damage, which may have affected the availability to maintain hot shutdown conditions from the main control room for a fire in Fire Area R-14, Lower 4.16kV Switchgear Room and Cable Vault. Dominion promptly entered this safe shutdown issue into their corrective action program as condition report (CR) 1043458. Immediate corrective actions included implementing compensatory measures in the form of fire watches for fire area R-14 that are being tracked by Reasonable Assurance of Safety (RAS) determination 3037040. Longer term corrective actions included submitting an exemption request to the NRC for use of a local operator manual action (OMA) to operate the #2 SG ADV in lieu of meeting fire protection requirements for fire area R-14. The team considered Dominions immediate and longer term corrective actions appropriate. The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to an external event to prevent undesirable consequences in the event of a fire. Specifically, the use of an OMA during post-fire safe shutdown is not as reliable as normal systems operation which could be utilized had the requirements of 10 CFR Part 50, Appendix R, Section III.G.2 been met and, therefore, prevented fire damage to credited components and/or cables, specifically the #2 SG ADV. The inspectors used IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase 1 and determined the reactor is able to reach and maintain a hot safe shutdown condition because the SG ADVs are used for transition to cold shutdown, therefore this finding was of very low safety significance (Green). This finding does not have a cross cutting aspect because the performance deficiency occurred greater than three years ago when the June 30, 2011 exemption request letter to the NRC was supplemented by letter on February 29, 2012, and is not indicative of current licensee performance.
05000443/FIN-2016007-03Seabrook2016Q3Failure to Perform Required ASME InService Testing of Manual Isolation Valves for the Atmospheric Steam Dump Valve Block ValvesThe team identified a finding of very low safety significance, involving a non-cited violation of Seabrook Technical Specification Surveillance Requirement 4.0.5, Surveillance Requirements for In-Service Inspection and Testing of American Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 Components. Specifically, the manual isolation valves for the atmospheric steam dump valves had an active safety function to close, in order to mitigate the radiological consequences of a steam generator tube rupture (SGTR) accident, but had not been placed in the Seabrook In-Service Test Program and tested, as required by the Technical Specifications and ASME Code. As a result, degraded valve performance could go uncorrected without adequate acceptance criteria to ensure that a SGTR would not result in an unacceptable increase in the consequences of that accident (e.g., a more than minor reduction in the margin between the postulated licensing basis radiological release and the regulatory limits). In response, NextEra entered the issue into their corrective action program (AR 2153195) and performed a preliminary assessment of the valves, which concluded that they were fully operable. This finding was more than minor because it was associated with the System, Structure, or Component (SSC), and Barrier Performance attribute of the Containment Barrier Cornerstone and adversely affected the cornerstone objective of ensuring the reliability of associated risk-important SSCs. The team determined that the finding was of very low safety significance (Green) because it was a deficiency confirmed not to represent an actual open pathway in the physical integrity of reactor containment and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The finding did not have a cross-cutting aspect because it was not considered indicative of current licensee performance.
05000261/FIN-2016003-01Robinson2016Q3Failure to Scope Tainter Gate Flood Protection Features in Maintenance Rule Resulting in Degraded PerformanceA self-revealing Green NCV of 10 CFR 50.65(b)(2)(ii) was identified for the failure to scope the external flood protection function of the Robinson Lake Dam spillway (Tainter) gates in the maintenance rule (MR) monitoring program. The failure to include the Tainter gates in the MR program resulted in ineffective maintenance being performed and subsequent degraded opening capability which challenged the availability of safety-related equipment during design basis rainfall events due to site flooding. The licensee took immediate corrective actions to replace/refurbish the chains to both gates and completed full open testing to restore their functionality. In addition, the licensee has developed and initiated implementation of an action plan to improve and ensure reliability of the gates, and initiated actions to revise the MR scoping program to include the Tainter gates. The issue was entered into the licensees CAP as CR 2035500. The failure to scope the flood protection function of the Lake Robinson Dam Tainter gates in the maintenance rule monitoring program was a PD. The finding is more than minor because it is associated with the protection against external factors (i.e., flood hazard) attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, failure to monitor flood protection features associated with the Tainter gates resulted in degraded gate opening performance that could have resulted in site flooding during design basis rainfall events and adversely impact multiple trains of safety-related equipment due to water intrusion. Using IMC 0609, Appendix A, The SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding involved the degradation of equipment specifically designed to mitigate flooding events. In accordance with Exhibit 4, External Events Screening Questions, the inspectors determined that the finding represented a degradation of two or more trains of a multi-train system or function during an external flooding event, therefore it required a detailed risk evaluation. A regional senior reactor analyst completed a detailed risk evaluation in accordance with NRC IMC 0609 Appendix A, and Appendix M, Significance Determination Process Using Qualitative Criteria, using the latest NRC Robinson Standardized Plant Analysis Risk model. The high uncertainty associated with estimating flood frequencies was the reason for using the NRC IMC Appendix M approach. The major analysis assumptions included a one-year exposure interval, recovery credit for opening the Tainter gates subsequent to binding of the chain, and limited credit for FLEX flooding mitigation strategies. If the rainfall produced a water surface elevation which would overtop the dam, the dam was considered failed and the ultimate heat sink lost. The rainfall frequencies requiring gate operation were estimated using a combination of National Oceanographic and Atmospheric Administration rainfall data and a probabilistic technique to establish precipitation frequency estimates performed by the licensee. The dominant sequence was a flood event inducing a non-recoverable loss of offsite power and loss of the emergency buses with a failure of the operators to manually recover the Tainter gates and failure of the operators to depressurize the steam generators to facilitate FLEX injection leading to a loss of core heat removal and core damage. The risk was mitigated by the low flood frequency, and the likely recovery of the Tainter gates prior to site flooding. There were additional conservatisms which were not applied to the result but would reduce the risk. These included the fact that the plant would be shutdown prior to flooding impacting safety-related equipment, which would reduce decay heat cooling required, and additional FLEX flooding strategies which could provide cooling even if the dam was lost. The risk increase due to the performance deficiency was < 1.0E-6/year, a Green finding of very low safety significance. The licensees analysis and full scope probabilistic risk assessment model produced a similar result. The inspectors determined that since the scoping of plant systems had occurred more than three years in the past, the finding did not represent current plant performance and therefore did not have a cross-cutting aspect associated with it.
05000318/FIN-2016002-03Calvert Cliffs2016Q2Failure to Implement Engineering Change Procedures Results in Plant TripThe inspectors documented a self-revealing, Green finding for Exelons failure to implement procedures for engineering changes. Specifically, Exelon failed to address the full scope and critical parameters associated with a modification to a steam generator feed pump (SGFP). As a result, the 22 SGFP turbine pedestal studs were improperly torqued, resulting in the SGFP shifting, becoming misaligned, and eventually resulting in the failure of the turbine to pump coupling. This resulted in the unexpected tripping of the 22 SGFP on December 1, 2015, and operators inserting a manual reactor trip as required by procedure. The inspectors determined that Exelons failure to properly implement procedures CNG-CM-1.01-1003, Design Inputs and Change Impact Screen, Revision 00601, Attachment 12; CNG-CM-1.01-2000, Scoping and Identification of Critical Components, Revision 00201; and CNG-FES-007, Preparation of Design Inputs and Change Impact Screen, Revision 00010 was a performance deficiency that was a performance deficiency that was within Exelons ability to foresee and prevent. Exelons corrective actions included, replacing the failed coupling, verifying the torque on the 21 SGFP using a HYTORCTM, and developing an adverse condition monitoring plan for Unit 1s SGFPs. Exelon conducted a root cause evaluation (RCE) and developed corrective actions to preclude repetition (CAPR) including implementation of Exelon procedure HU-AA-1212, Technical Task Risk/Rigor Assessment, Pre-Job Brief, Independent Third Party Review, and Post-Job Review, Revision 007 and conducting critical parameters and rigor training for engineering personnel including the expectations for three pass reviews and verification of assumptions. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and IMC 0612, Appendix E, Examples of Minor Issues and determined the issue is more than minor because it was associated with the Design Control Attribute of the Initiating Events Cornerstone and adversely impacted the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the performance deficiency resulted in a reactor trip from full power on December 1, 2015. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, issued on June 19, 2012, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, Initiating Events Screening Questions, issued on June 19, 2012 and determined the finding to be of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that the finding had a cross-cutting aspect in the area of Human Performance, Documentation, because Exelon failed to develop and maintain complete and accurate engineering change packages (ECP), work orders (WO), and maintenance procedures.(H.7)
05000498/FIN-2016002-02South Texas2016Q2Failure to Control Steam Generator Water Levels at Low PowerThe inspectors documented a self-revealed, non-cited violation of Technical Specification 6.8.1.a, Procedures, for failure to implement procedures for power operation as described in Regulatory Guide 1.33, Revision 2, Appendix A, Section 2.g, dated February 1978. Specifically, the procedure the licensee used for low power operation failed to include adequate instructions for the control of steam generator water levels, which resulted in a plant cooldown, a letdown isolation, a pressurizer power-operated relief valve lift, and unplanned entry into two technical specification action statements. The licensee entered this issue into the corrective action program as Condition Report 2015-26657. The inspectors determined that the failure to control steam generator water levels due to an inadequate procedure during lower power operations was a performance deficiency. The performance deficiency is more than minor because it is associated with the procedure quality attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to control steam generator water levels resulted in a plant cooldown, a reactor coolant system letdown isolation, a pressurizer power-operated relief valve to lift, and unplanned entry into two technical specification action statements. The inspectors screened this finding using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, dated June 19, 2012. The finding screened as Green per Section B. of Exhibit 1, Initiating Events Screening Questions, because the finding did not result in exceeding the reactor coolant system leak rate for a small loss-of-coolant accident, did not affect other systems used to mitigate a loss-of-coolant accident resulting in a total loss of their function, and did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Inspectors determined the finding had a cross-cutting aspect of training in the human performance area because the organization failed to provide training and ensure knowledge was transferred to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. Specifically, because the licensee provided start-up training and simulator based training, skill of the craft vice detailed procedures was thought to be adequate for controlling steam generator water levels at low power (H.9).
05000443/FIN-2016002-01Seabrook2016Q2Automatic Initiation of Emergency Feedwater Resulting from Performance of Procedural Steps in a Manner Prohibited by Documented InstructionsA self-revealing Green NCV of 10 CFR, Appendix B, Criterion V, Instructions Procedures, and Drawings, was identified, because NextEra did not ensure that activities affecting quality were accomplished in accordance with documented instructions. Specifically, while implementing a procedure following a plant trip that occurred on March 2, 2016, NextEra staff performed steps of a procedure in a manner that was prohibited by a departmental instruction, leading to an automatic initiation of emergency feedwater (EFW) to maintain adequate steam generator (SG) level. NextEra entered this issue into their corrective action program (CAP) and subsequently initiated a root cause evaluation to determine the factors which contributed to the event. Additionally, NextEra took corrective actions (C/As) to provide additional training and guidance for their staff and to resolve issues with existing procedures, which were determined to have been contributing factors during the event. The inspectors determined that this performance deficiency was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone, and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability (loss of FW) and challenge critical safety functions during shutdown as well as power operations. In accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that this finding was of very low safety significance (Green) because the performance deficiency did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Challenge the Unknown, because NextEra did not ensure that individuals stopped when faced with uncertain conditions. Specifically, the individuals involved did not adequately challenge the basis for a decision to disregard a department instruction.
05000275/FIN-2016301-01Diablo Canyon2016Q2Insufficient Procedural Direction Contained Within Procedure EOP E-2, Faulted Steam Generator IsolationThe examiners identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Specifically, Procedure EOP E-2, Faulted Steam Generator Isolation, does not contain sufficient procedural direction for isolating auxiliary feedwater flow to a faulted steam generator in the event that auxiliary feedwater control valves cannot be closed from the control room. Procedure EOP E-2, Appendix HH, Isolated Faulted Steam Generator, Step 1.d, and its associated column, Response Not Obtained, does not ensure that a faulted steam generator would remain isolated under all conditions. The Response Not Obtained column permits operators to either locally close auxiliary feedwater control valves OR secure the auxiliary feedwater pump feeding the faulted steam generator. However, due to the absence of pull-to-lock or hard stop switches for the auxiliary feedwater pumps, the possibility exists for an automatic restart of an auxiliary feedwater pump and a re-initiation of feedwater to a faulted steam generator. The failure to ensure that Procedure EOP E-2 contained sufficient direction to isolate a faulted steam generator when auxiliary feedwater flow control valves cannot be closed from the control room was a performance deficiency. This performance deficiency was of more than minor safety significance because it was associated with the procedure quality attribute of the Barrier Integrity cornerstone (reactor coolant system and containment) and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the re-initiation of feedwater to an isolated, faulted steam generator has the potential to adversely affect the reactor coolant system barrier by causing an additional unintended cooldown of the reactor coolant system, increased potential for pressurized thermal shock, and thermal stress to the steam generator u-tubes. Additionally, the containment barrier would be affected by the reinitiation of feedwater to a steam line break within containment. Using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, the team determined that the finding required a detailed risk evaluation due to the potential to affect the reactor coolant system boundary. A senior reactor analyst performed a bounding detailed risk evaluation and estimated the maximum increase in core damage frequency to be 5.9E-8/year, and therefore the finding was determined to be of very low safety significance (Green). This increase in core damage frequency was mitigated by the low probability of multiple equipment failures in the auxiliary feedwater system when combined with the low initiating event frequency of a faulted steam generator. Because the violation was of very low safety significance (Green) and the issue was entered into the licensees corrective action program as Notification 50847218, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000275/2016301; 05000323/2016301-01, Insufficient Procedural Direction Contained Within E-2, Faulted Steam Generator Isolation. This finding has a crosscutting aspect in the area of human performance associated with resources because the organization did not ensure procedures are available and adequate to support nuclear safety (H.1).
05000425/FIN-2016002-01Vogtle2016Q2Failure to properly implement a maintenance procedure caused a Reactor TripA self-revealing non-cited violation (NCV) of Technical Specifications (TS) 5.4.1.a, Procedures, was identified for the licensees failure to properly implement procedure 24750- 2, Steam Generator Level (Narrow Range) Protection Channel II 2L-519 Channel Operational Test and Channel Calibration. During testing of Unit 2 loop 1 steam generator (S/G) narrow range channel 2L-519 the channel was not removed from scan resulting in a reactor trip. The licensees immediate corrective actions were to remove the technicians performing the calibration from maintenance duties for formal remediation. The licensee documented this condition in CR 10230073. The performance deficiency (PD) was more than minor because it adversely affected the Initiating Events cornerstone objective in that the failure to properly remove channel 2L-519 from scan resulted in a reactor trip. The finding was determined to be Green because the PD did not result in a loss of mitigation equipment used to transition the reactor to a stable shutdown condition. The finding was assigned a cross cutting aspect of Avoid Complacency because maintenance technicians failed to implement appropriate error reduction tools to verify that the correct channel was removed from scan for testing.
05000382/FIN-2016002-04Waterford2016Q2Failure to Account for Starting Air Design Features in Emergency Diesel Operating ProceduresA self-revealing, Green, non-cited violation of Technical Specification 6.8, Procedures and Programs, occurred because the licensee did not establish adequate procedures for the operation of the emergency diesel generators. Specifically, prior to July 7, 2015, the licensees procedure for operating the emergency diesel generators allowed lube oil pressure to be maintained low enough to activate a design feature of the starting air system that injects starting air into the diesel cylinders, which could damage the emergency diesel generator turbocharger. The licensee entered this issue into their corrective action program as condition report CR-WF3-2015-04459. The corrective action taken to restore compliance was to increase the procedure requirement for operating lube oil pressure from 35 psig to 45 psig. The inspectors concluded that the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the procedural allowance to run the emergency diesel generator lube oil pressure at the starting air injection setpoint could have resulted in the failure of the emergency diesel generators when they were called upon to perform their safety function. The inspectors used NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, to determine the significance of the finding. The inspectors determined that the finding required a detailed risk evaluation because it represented the loss of a system or function. The detailed risk evaluation determined that the finding is of very low safety significance (Green). The senior reactor analyst estimated the increase in core damage frequency to be 4.6E-7/year and the increase in large early release frequency to be 3.9E-8/year. Dominant core damage sequences were medium break losses of coolant accidents and steam generator tube ruptures with associated losses of off-site power. Core damage was mitigated by the remaining emergency diesel generator. This finding had an Evaluation cross-cutting aspect in the area Problem Identification and Resolution, because the licensee did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensees previous evaluation performed for operating the emergency diesel generators with low lube oil pressures did not thoroughly evaluate the risk associated with the starting air system (P.2).
05000454/FIN-2016001-01Byron2016Q1Failure to Enter Technical Specification Limiting Condition for Operation Action Requirement with Auxiliary Feedwater Flow Control Valves Failed OpenThe inspectors identified an Unresolved Item (URI) associated with the concern that the licensee failed to enter a TS LCO action requirement when all air was isolated to the actuators to the auxiliary feedwater flow control valves, failing them open and unable to be throttled or closed from the control room. Description: On January 3, 2016, the licensee generated Issue Report (IR) 2607148 which requested clarifying guidance from engineering for assessing operability of the 1/2AF005AH auxiliary feedwater flow control valves to the steam generators, when air is isolated from the valve actuators. The IR stated that when procedure BISR 3.4.2200, Surveillance Calibration of Aux Feedwater to Steam Generators A, B, C and D Flow Control Loops, was performed, all air was isolated from the auxiliary feedwater flow control valves to fail them open during the calibration. This was intended to maintain operability of the auxiliary feedwater system during the calibration. At each Byron unit, each of the two auxiliary feedwater pumps had a separate flow path to each of the steam generators, and each flow path had an air-operated flow control valve, a motor-operated containment isolation valve, and a check valve in the flow path. The flow control valves used instrument air as the motive force to throttle and close the valves. Upon a loss of air to the actuator, the flow control valves were designed to fully open via spring pressure, allowing auxiliary feedwater flow to the steam generators. In 2012, the licensee installed safety-related accumulators on each auxiliary feedwater train to supply air to the auxiliary feedwater flow control valve actuators upon a loss of instrument air. This air supply was designed so that if one of the steam generators experienced a steam generator tube rupture and the containment isolation valve in the flow path to that steam generator failed to close, the control room operators could close the flow control valve to limit or isolate auxiliary feedwater flow to the failed steam generator until an equipment operator could locally secure the flow control valve in its closed position. This modification was performed to support the licensees license amendment request for a measurement uncertainty recapture uprate so that operator actions could be credited to prevent the steam generator with a ruptured tube from overfilling and challenging the containment function. Upon completion of the modifications, the licensee updated Table 15.07, Plant Systems and Equipment Credited for Transients and Accident Conditions, in the Accident Analysis section of the licensees UFSAR to include the AF Accumulator Tanks as engineered safeguard feature (ESF) equipment credited for steam generator tube rupture incidents. The safety evaluation in Chapter 10 of the UFSAR was also updated for the Auxiliary Feedwater System to state that in the event of a steam generator tube rupture, operator action was required to isolate auxiliary feedwater flow to the ruptured steam generator within certain time requirements, and that in the event that the containment isolation valve failed to close, the flow path could still be isolated by closing the AF005 valves, with air accumulators sized to ensure sufficient time for local operator action to secure the AF005 valves in the closed position. In response to IR 2607148, the licensees regulatory assurance department documented that the safety function of TS LCO 3.7.5, Auxiliary Feedwater System, was intended to be limited to supply water to the steam generators for heat removal and that this should not be changed in favor of any UFSAR design analysis. The IR concluded that Operability per the TS was not applicable, and operations did not need to place the unit in any TS condition statement with the AF005 valves failed open with no instrument air supply during the associated instrument calibrations. From the time the licensee received the measurement uncertainty recapture license amendment on February 7, 2014, through March 22, 2016, the licensee had failed open all four AF005 valves in each train of auxiliary feedwater using BISR 3.4.2200 at least five times per train, and has not entered a TS LCO during most of these time periods. The regulations stated in 10 CFR 50.26(c)(2)(ii)(C) that a TS LCO of a nuclear reactor must be established for each SSC that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that assumes the failure of/or presents a challenge to the integrity of a fission product barrier. The inspectors were concerned that when all air is isolated to the auxiliary feedwater flow control valve actuators, operators may not be able to throttle or isolate flow to a ruptured steam generator quickly enough to prevent overfill of the steam generator, assuming the motor-operated containment isolation valve fails to close, which could challenge the integrity of containment. As such, the inspectors were concerned that the licensee failed to enter a TS LCO action requirement when the air to the actuator was isolated. To determine whether a performance deficiency or violation exists, the inspectors need to determine if a TS LCO should have been established for the ability of the AF005 valves to close to mitigate a steam generator tube rupture event, and if the licensees modifications and license amendment requests properly addressed the establishment of an LCO for this function of the SSC. (URI 05000454/201600101, 05000455/201600101; Failure to Enter Technical Specification Limiting Condition for Operation Action Requirement with Auxiliary Feedwater Flow Control Valves Failed Open)
05000313/FIN-2016007-03Arkansas Nuclear2016Q1Inadequate Operating Experience EvaluationsThe team identified a Green finding for the licensees failure to evaluate operating experience as required by procedure EN-OE-100-02, Operating Experience Evaluations. This procedure allowed taking no action for operating experience issues that were applicable to the station if multiple barriers existed to preclude failure. The team identified two examples where the licensee had not correctly verified the adequacy of credited barriers and as a result, represented a vulnerability to a similar event occurring at the station. The licensees corrective actions included re-performing the operating experience evaluations and documenting the issue in the corrective action program as condition reports CR-ANO-C-2016-00463 and CR-ANO-C-2016-00782. The failure to evaluate operating experience was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to take corrective action to address the large motor and respiratory protection operating experience could result in a similar adverse condition or event at the station. The finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 Initiating Events Screening Questions, dated June 19, 2012. The team determined the finding was of very low safety significance (Green) because the finding would not result in exceeding the reactor coolant system leak rate for a small loss of coolant accident or affect systems used to mitigate a loss of coolant accident, did not cause a reactor trip and loss of mitigation equipment, did not involve the loss of a support system, did not involve a degraded steam generator tube condition, and did not impact the frequency of a fire or internal flooding event. This finding had a human performance cross-cutting aspect of Conservative Bias because the licensee failed to ensure that individuals used decision making-practices that emphasized prudent choices over those that were simply allowable. Specifically, individuals performing evaluations rationalized assumptions rather than verifying the actual conditions (H.14).