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05000410/FIN-2018002-012018Q2Nine Mile PointFailure to Ensure Proper Control of the Standby Gas Treatment System Damper Valve, 2GTS*V2000B, Within Procedures, Materials, and Design Control MeasuresThe inspectors identified a Green finding and associated NCVof 10 CFRPart 50, Appendix B, Criterion III, Design Control, when Exelon failed to ensure proper control of the SGTS damper valve 2GTS*V2000B within procedures, materials, and design control measures. Specifically, on April 15, 2018 operators attempted to run B SGTS for containment purge; however, no flow was observed and the system was secured. Operators discovered the 2GTS*V2000B closed due to the failure of the operating mechanism to maintain control of the valve position.
05000220/FIN-2018002-022018Q2Nine Mile PointInadequate Procedure Causes Water Hammer Condition Resulting in Isolation and Inoperability of the 12 Train of the Emergency Condenser SystemThe inspectors identified a Green finding and associated NCVof 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, when Exelon did not provide appropriate quantitative or qualitative criteria and guidance to operators in procedure N1- OP- 13 Emergency Cooling System to return an emergency condenser loop to service without inducing a water hammer condition which caused operators to re-isolate the emergency condenser loop and declare it inoperable
05000272/FIN-2018001-032018Q1SalemFailure 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.
05000334/FIN-2018001-022018Q1Beaver ValleyLicensee-Identified ViolationTechnical Specification 5.5.2 (c), Radioactive Effluent Controls Program, requires monitoring, sampling, and analysis of gaseous effluents. Contrary to the above, from 1989 to the present, the sample pump flow rates through several isokinetic nozzles was too high to allow for accurate monitoring and representative sampling. In 1989, automatic flow control features of some effluent monitoring instruments were disabled and in 2016, several new monitors were installed on the same isokinetic nozzle sample lines. Both of these actions prevents accurate monitoring and representative sampling.Significance/Severity: The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process. The inspectors determined that finding was of very low safety significance (Green).Corrective Action Reference(s): CR-2017-04211 and CR-2018-00283
05000272/FIN-2018001-022018Q1SalemInadequate Procedure Step Results in Service Water Strainer TripA self-revealing Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations(10 CFR), Appendix B, Criterion V, was identified because PSEG procedure WC-AA-111, Predefine Process, Revision 8, step 4.8.11, did not adequately prescribe activities that affected the quality of the safety-related 11 service water (SW) strainer. Specifically, step 4.8.11 did not adequately prescribe controls associated with the performance of partial PM activities that affected the quality of the safety-related structures, systems and components (SSCs). Consequently, the 11 SW corrosion control sacrificial anodes were not replaced prior to the PM overdue date and eventually broke into pieces, which rendered the 11 SW pump and strainer inoperable and unavailable from June 8 11, 2017.
05000219/FIN-2018001-022018Q1Oyster CreekEnforcement Action (EA)-18-007: No. 2 Emergency Diesel Generator Ring Lug FailureOn October 9, 2017, during a routine surveillance load test, the No. 2 emergency diesel generator failed approximately 5 minutes into the run due to a broken ring lug on a current transformer. Laboratory analysis of the broken ring lug determined that the ring lug failed due to fatigue cracking that was initiated due to stresses caused by bending and twisting of the electrical lug. Exelon last conducted a load surveillance on the No. 2 emergency diesel generator on September 25, 2017. Corrective Actions: Corrective actions included replacement on the broken ring lug on the No. 2 emergency diesel generator, extent of condition inspections on the No. 1 and No. 2 emergency diesel generators for additional bent or twisted ring lug connectors, and revision to the electrical ring lug installation and emergency diesel generator procedures to include inspection for bent or twisted ring lugs. Corrective Action Reference(s): Issue report 4060815 Enforcement:Violation: Oyster Creek Technical Specification 3.7.C.2.b states, in part, that if one diesel generator becomes inoperable during power operation, the reactor may remain in operation for a period not to exceed 7 days. Contrary to the above, on October 9, 2017, it was recognized that one diesel generator was inoperable for greater than the technical specification allowed outage time of 7 days, and Oyster Creek continued power operation. Specifically, on October 9, 2017, No. 2 emergency diesel generator failed to run during a routine surveillance test due to a broken ring lug on a current transformer, which resulted in a total inoperability time of 6.5 months.Severity/Significance: For violations warranting enforcement discretion, Inspection Manual Chapter 0612 does not require a detailed risk evaluation, however, safety significance characterization is appropriate. A Region I Senior Reactor Analyst (SRA) performed a best estimate analysis of the safety significance using the Oyster Creek Standardized Plant Analysis Risk (SPAR) model, Version 8.50 and Systems Analysis Programs for Hands-On Integrated Reliability Evaluations (SAPHIRE). The evaluation estimated the total (internal and external events risk) increase in core damage frequency (CDF) to be in the mid to high E-6/yr range, or a low to moderate safety significance. The SRA evaluated the internal events risk contribution due to the inoperability of the No. 2 emergency diesel generator for an approximate 6.5 month exposure time. The exposure time relative to when the No. 2 emergency diesel generator was no longer capable of meeting its 24 hour mission time is uncertain due to the effect of vibration induced fatigue, and therefore the method prescribed within the RASP handbook guidance was used. 9 The analyst used the guidance in Section 2.5 of the Handbook, Revision 2.0, to estimate the exposure time of 6.5 months based on the cumulative 24 hour summation of the No. 2 emergency diesel generator surveillance test proven run time. This approach is appropriate for periodically operated components that degrade during operation (i.e. vibration induced fatigue only occurs while the emergency diesel generator is in-service/operating). Given this approach, the dominant internal events, loss of offsite power were evaluated for the estimated internal risk increase. This contribution was estimated at 2E-6/yr increase in CDF. The dominant sequences involved loss of offsite power events with a concurrent failure of the No. 1 emergency diesel generator, failure of the combustion turbines, and failure to recover offsite power or recover an emergency diesel generator prior to core damage.The SRA performed various modeling changes after a review of revised calculations for DC battery life:Analysis noted that Oyster Creek Generating Station recirculation pump seals are similar in design to those tested in reports generated for Nine Mile Point Unit 1 with the use of CAN2A seals. Therefore, the failure probability of the seals in the station blackout sequence wasadjusted from 0.1 to 5E-2 similar to Nine Mile Point Unit 1 SPAR model 8.50.The failure to load shed action (DCP-XHE-XM-LSHED) in the model was calculated using the SPAR-H method and revised to 1.2E-2 versus being assumed to always fail (TRUE).Failure probabilities for 1, 2, or 3 stuck open electromatic relief valves were revised to be consistent with the previous model version 8.22 because of the isolation condenser design at Oyster Creek Generating Station which limits cycling and significantly reduces the probability of a failed open electromatic relief valve due to isolation condensers controlling pressure.The depressurization function using electromatic relief valves, if required, was calculated through SPAR-H to be 1E-2 for sequences where total seal failure is assumed (DEPSEALFAIL) (conservatively assumed limited time available).The diesel driven firewater pumps are both available and were set to calculated fault tree failure probabilities instead of always failed in the previous model. These are 2,000 gallons per minute pumps with a large supply of water and relatively simple operator actions to inject to the reactor pressure vessel. The firewater was assumed to fail at 0.1 when a total recirculation seal failure occurs due to assumed time constraints.The offsite power and the emergency diesel generator required recovery time events were increased to 24 hours for events where DC load shedding was successful, without seal failures and isolation condenser success along with diesel driven firewater success.The SRA noted the No. 2 emergency diesel generator was recoverable. In fact, the diagnosis of the failed condition was performed in a nominal 8-10 hours from the failure. Therefore, a probability of failure to recover event for the conditional case was developed. The SRA used SPAR-H as simple guidance, which conservatively supported a reasonable assumption of a 0.10 conditional probability of failure to recover the emergency diesel generator within 24 hours. The base case utilized a calculation within SPAR of 0.33 failure to recover probability for 24 hour sequences. To estimate the external risk contribution, the SRA identified that the most significant external risk contribution was from fire events. Seismic, external flooding, and high wind events were not significant contributors for the issue. From discussions with Oyster Creek Fire probabilistic risk analysts and a review of this failure condition, the increase in CDF due to the failed No. 2 emergency diesel generator for the assumed 6.5 month exposure time was estimated at 4.5E-6/yr ((8.5E-5/yr-4.5E-5/yr) x (6.5/12 months) x 0.2).The DC safety-related battery life would be at least a nominal 14 hours and longer if DC bus stripping occurred, this allows for extended isolation condenser or electromatic relief valve function, with injection from diesel driven firewater. Given the time considerations and characteristics of the failure, an assumed recovery at a failure probability of 0.2 (slightly higher than internal due to less time) was applied for the No. 2 emergency diesel generator, which was a best estimate determined through SPAR-H insights. The dominant fire sequence was a fire affecting the A and B 4kV switchgear rooms, where combustion turbine support would be lost, with failure of the No. 1 emergency diesel generator breaker to close, and failure of locally operating the isolation condenser due to eventual loss of power. The SRA noted that FLEX credit was not quantified and would result in a lower risk estimation likely in the low E-6/yr range. Combining internal and external risk contributions, the total increase in CDF was 6.5E-6/yr, or low to moderate safety significance. The SRA determined that Exelon uses a Large Early Release Frequency (LERF) factor value of 8E-2. This value takes into consideration operator action for those relevant high pressure vessel breach scenarios (fuel-coolant interaction, liner-melt-through, and direct containment heating). This also credits procedure strategies where other mitigating actions are taken such as flooding the drywell. The SRA review of the dominant sequences and time to core damage affirmed that LERF did not increase the risk over that determined from the increase in CDF.Basis for Discretion: The inspectors determined that the ring lug failure was not within Exelons ability to foresee and prevent. As a result, no performance deficiency was identified. The inspectors assessment considered:1. Exelons review of emergency diesel maintenance performed in 2015 checked allconnections of the current transformer for tightness. The inspectors did not identify any gaps or deficiencies in the 2015 inspections. Inspectors also reviewed completed biennial inspections of the connection dating back to 1991 and did not identify any gaps.2. At the time of the failure, the current transformer connections did not have a time directed replacement frequency recommended by the Emergency Diesel Generator Owners Group. The inspectors did not identify any additional vendor or industry recommendations specific to the failed component or considerations specific to the failed component that existed prior to the failure.3. Industry operating experience information available to Exelon did not identify the potential for the fatigue cracking of the bent wire ring lug that was experienced.4. The bent ring lug failure was not the result of a failure on the part of Exelon staff; no standards existed on bending of the lug during installation and is considered skill of the craft.The NRC determined that it was not reasonable for Exelon to have been able to foresee and prevent this violation of NRC requirements, and as such, no performance deficiency existed. Therefore, the NRC has decided to exercise enforcement discretion in accordance with Sections 2.2.4 and 3.10 of the NRC Enforcement Policy and refrain from issuing enforcement action for the violation of technical specifications (EA-18-007). Further, because Exelons actions did not contribute to this violation, it will not be considered in the assessment process or the NRC Action Matrix. Exelons equipment corrective action program evaluation report (ECAPE) determined that the ring lug failed on the No. 2 emergency diesel generator as a result of fatigue cracking, which was initiated due to excessive stress caused by bending and twisting of the ring lug beyond limits specified in industry guidelines. The inspectors noted that the ECAPE did not provide supporting information regarding how the ring lug was bent and twisted beyond industry guidelines. Specifically, industry guidance states that ring lugs can be bent up to 90 degrees. The broken ring lug found in the No. 2 emergency diesel generator was bent at approximately 45-55 degrees per the ECAPE, which was within industry guidelines. Additionally, the ECAPE did not include specific guidance on twisting allowances for ring lugs. Exelon documented the inspectors observation in Issue Report 4089829. As a result of the inspectors observation, Exelon revised the ECAPE to say the ring lug failed on the No. 2 emergency diesel generator as a result of fatigue cracking, which was initiated due to excessive stress caused by bending and twisting of the ring lug.
05000272/FIN-2018001-012018Q1SalemImplementing Procedures for Beyond Design Basis FLEX Mitigating Strategies Not FollowedA Green finding was identified by the inspectors for multiple examples of PSEG not following the station specific procedures that implement the Salem and Hope Creek Generating Station (HCGS) Final Integrated Plans for Beyond Design Basis FLEX Mitigating Strategies, EM-SA-100-1000 and EM-HC-100-1000, respectively. Specifically, since compliance with the FLEX order was met on November 10, 2016, PSEG did not follow the common PSEG fleet Preventive Maintenance (PM) Process and diesel fuel oil testing program procedures, MA-AA-716-210, CY-AB-140-410, and SC.OP-LB.DF-0001 for the annual fuel oil sampling of FLEX equipment. In addition to this, between December 6, 2017, and March 8, 2018, PSEG did not follow site specific procedures for FLEX equipment unavailability and mitigation capability protection in accordance with the Salem and HCGS procedures, OP-HC-108-115-1001 and OP-SA-108-115-1001, Operability Assessment and Equipment Control Program.
05000334/FIN-2018001-012018Q1Beaver ValleyInadequate Procedure AdherenceA self-revealed Green finding was identified when the licensee failed to adequately implement procedure NOP-WM-1001, Order Planning Process. Specifically, FENOC personnel that made a change to work order testing requirements did not receive concurrence from a Unit 1 Senior Reactor Operator nor did they ensure that the original scope and/or intent of the test was met.
05000219/FIN-2018001-012018Q1Oyster CreekUntimely Licensee Event Report for Reportable Conditions Associated with the No. 2 Emergency Diesel GeneratorThe inspectors identified a non-cited, Severity IV violation of 10 CFR 50.73(a)(1) for a failure to submit a licensee event report (LER) within 60 days after the discovery of an event requiring a report. Specifically, on October 9, 2017, Exelon determined that the No. 2 emergency diesel generator was inoperable for longer than the allowed outage time, which is reportable as a condition prohibited by technical specifications. Exelon did not submit an LER for this event until January 3, 2018
05000272/FIN-2017007-032017Q3SalemInadequate Corrective Action Regarding Missed Periodic Inspection of 2C EDG AVR CardThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because between April 2008 and July 2017, PSEG failed to promptly identify and correct a condition adverse to quality associated with an automatic voltage regulator (AVR) card installed in the 2C EDG. Specifically, PSEG corrective actions in response to a 2007 MPR Associates Part 21 report did not ensure that the 2C EDG was not susceptible to undesired voltage fluctuations associated with an aged-related defect in the installed AVR card. PSEGs immediate corrective actions included initiating a corrective action NOTF to evaluate operability and prioritize scheduling AVR card replacement. The issue is more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, without further inspection of the 2C EDG AVR card solder joints, cracks could form in the solder joint connections resulting in undesired voltage fluctuations and potentially preclude the 2C EDG from performing its safety function. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was Green because it was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs Maintenance Rule program for greater than 24 hours. The team determined the finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Self-Assessment, because PSEG did not conduct self-critical and objective assessments of its programs and practices. Specifically, PSEGs pre-inspection self-assessment in May 2017 reviewed PSEGs corrective actions for the MPR Associates Part 21 Report, but did not identify the missed periodic refueling cycle inspections of the 2C EDG AVR card.
05000272/FIN-2017007-022017Q3SalemInadequate PM for the EDG Room Ventilation SystemThe team identified a Green non-cited violation of Technical Specification (TS) 6.8.1, Procedures and Programs, because since January 2007, PSEG did not establish an appropriate preventive maintenance (PM) schedule for the emergency diesel generator (EDG) ventilation dampers. Specifically, PSEG cancelled a pre-existing 36-month lubrication/clean/inspect PM in 2007 but failed to add the lubrication task to an existing 6-year damper PM as intended. As a result, since January 2007, the intended lubrication PM was cancelled for the inlet, recirculation, and exhaust ventilation dampers on all six Unit 1 and Unit 2 EDG ventilation systems. PSEGs immediate corrective actions included initiating a corrective action NOTF to address the PM inadequacy and extent-of-condition. The issue is more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, the removal of the EDG ventilation damper lubrication PM had the potential to adversely impact EDG reliability. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was Green because it was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety-significant in PSEGs Maintenance Rule program for greater than 24 hours. The team determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000272/FIN-2017007-012017Q3SalemInadequate Design Verification that Inter-Cabinet Bolts were Installed between SEC and Bailey CabinetsThe team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because between May 1995 to July 2017, PSEG did not verify that bolts, or other suitable connections, were installed to connect the safeguard equipment control (SEC) cabinets to the Bailey termination cabinets to satisfy the Seismic Qualification Utilities Group (SQUG) recommended method to resolve effects of potential cabinet interaction during a seismic event. PSEGs immediate corrective actions included initiating several corrective action notifications (NOTFs) to evaluate operability, extent-of-condition, and long-term resolution. This issue is more than minor because it is associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, PSEG performed a SQUG evaluation in response to unresolved safety issue (USI) A-46, Verification of Seismic Adequacy of Mechanical and Electrical Equipment in Operating Reactors, and submitted the results to the NRC detailing a potential for SEC cabinet seismic interaction with the adjacent Bailey termination cabinet. The evaluation results recommended bolting the SEC cabinet to the Bailey cabinet to eliminate the interaction. However, PSEG did not ensure and verify that the SQUG recommended bolts were installed, which resulted in a reasonable doubt on the operability of the SEC to reliably perform its intended function during and following a design basis seismic event. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, the team determined that this finding was Green because it was a design deficiency that potentially affected the design or qualification of a mitigating system, however, the mitigating system maintained its operability. The team determined there was no cross-cutting aspect associated with this finding since it was not representative of current PSEG performance.
05000247/FIN-2017003-012017Q3Indian PointComponent Misalignments for Nuclear Instrumentation P6 Permissive and AFW Flow Transmitter FI-1201 Following Scheduled MaintenanceA self-revealing Green NCV of Technical Specification (TS) 5.4.1, Procedures, with two examples was identified when Entergy failed to implement procedures to ensure correct system alignment for the nuclear instrumentation permissive interlock, P6, and auxiliary feedwater (AFW) flow transmitter, FI-1201. Entergy promptly corrected the alignment issues and entered them into their corrective action program (CAP) as condition report (CR)-IP2-2017-02193 for the P6 permissive interlock and CR-IP2-2017-02150 for the AFW flow transmitter. This performance deficiency is more than minor because it affects the configuration control attribute of the Mitigating System cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, in both cases, the instrumentation was left disabled following maintenance such that they could not perform their safety functions required by TSs. Additionally, the first example was similar to IMC 0612, Appendix E, example 2.g, because Entergy changed plant modes from Mode 5 to Mode 2 without ensuring P6 was operable. The second example was similar to IMC 0612, Appendix E, examples 5.a and 5.b, because Entergy failed to return the AFW flow transmitter to service after the refueling outage. The inspectors assigned a cross-cutting aspect in the area of Human Performance, Work Management, because both examples demonstrated a failure in the planning, control, and execution of work, and a lack of coordination between work groups to ensure quality.(H.5)
05000219/FIN-2017003-012017Q3Oyster CreekInadequate Augmented Offgas System Procedure Resulted in a Manual ScramA self -revealing NCV of Technical Specification 6.8.1, Procedures and Programs, was identified because Exelon did not adequately establish and maintain the augmented offgas (AOG) system operation procedure as required by NRC Regulatory Guide 1.33, Quality Assurance Requirements (Operation), Appendix A, Section 7, Procedures for Control of Radioactivity. Specifically, Exelon procedure 350.1, Augmented Offgas System Operation, did not include adequate guidance for placing the AOG system into a recycle or shutdown configuration following a system trip. Without this guidance, Operations personnel failed to ensure the correct configuration of the AOG system following a partial trip of the system which resulted in degraded main condenser vacuum and a subsequent manual reactor scram on July 3, 2017. This issue was entered into the corrective action program as issue report 4028402. The corrective actions included placing the AOG system in the correct configuration and revising the AOG system operation procedure to provide guidance for verifying proper alignment of the AOG system when the system is in recycle or shutdown. The inspectors determined the performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of Procedure Quality and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to establish an adequate procedure for verifying proper alignment of the AOG system following a full or partial trip of the system resulted in the AOG inlet valve being left in the open position, which allowed demineralized water to be siphoned from the flame arrestor tank and slowly fill the offgas hold- up pipe. This caused a degradation of main condenser vacuum and resulted in operators inserting a manual reactor scram on July 3, 2017. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, Exhibit 1, Initiating Event Screening Questions. The inspectors determined the finding was a transient initiator that did not contribute to both the likelihood of 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, and therefore was of very low safety significance (Green). The finding had a cross- cutting aspect in the area of Human Performance, Avoid Complacency , because Exelon failed to recognize and plan for the possibility of mistakes or latent errors and implement appropriate error reduction tools by verifying the AOG system was properly aligned following a system trip ; instead , Operations personnel relied upon using a procedure that did not contain adequate guidance to place the AOG system in the correct configuration following a system trip (H. 12)
05000293/FIN-2017002-062017Q2PilgrimSecondary Containment Testing not performed per Technical SpecificationsAn NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, and TS 4.7.C, Containment Systems Secondary Containment, was identified when Entergy performed a surveillance test requiring a refueling outage while online. Specifically, Entergy performed Procedure 8.7.3, Secondary Containment Leak Rate Test, TS Surveillance Requirement (SR) 4.7.C from February 27, 1997, to April 5, 2017. As corrective actions, Entergy re-performed the test during the April 2017 refueling outage prior to refueling. This issue was entered into the CAP as CR 2017-2900. The performance deficiency is more than minor because it is associated with the configuration control attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protects the public from radionuclide releases caused by accidents or events. Specifically, Entergy intentionally removed the safety function of standby gas and secondary containment for operational convenience and did not comply with the requirements of TS SR 4.7.C which requires the test to be performed during a refueling outage before refueling. In accordance with IMC 0609.04, Initial Characterization of Findings, issued October 7, 2016, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green), because the finding only represented a degradation of the radiological barrier function provided for the SBGTS. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance - Conservative Bias, in that Entergy personnel did not use decision making-practices that emphasize prudent choices over those that are simply allowable. Specifically, operators did not refer to the TSs to understand the required conditions for a secondary containment surveillance test. Operators followed an inadequate site procedure for the plant conditions at the time and did not question why removal of a safety function for operational convenience was acceptable. (H.14)
05000293/FIN-2017002-072017Q2PilgrimUntimely 10 CFR 50.72 Notification of a Secondary Containment System Functional FailureAn NRC-identified SL IV NCV of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, was identified because both trains of the SBGTS were made inoperable during surveillance testing, and the condition was not reported to the NRC within eight hours of the occurrence, as required by 10 CFR 50.72(b)(3)(v), Event or Condition that Could Have Prevented Fulfillment of a Safety Function. Specifically, on April 5, 2017, while performing TS SR 4.7.C, trains A and B of the SBGTS were made inoperable leading to the inoperability of the Secondary Containment System (SCS). As a corrective action, Entergy personnel performed a causal evaluation. This issue was entered into the CAP as CR 2017-7446. The inspectors evaluated this performance deficiency in accordance with the traditional enforcement process because the issue impacted the regulatory process, in that a condition that could have prevented a safety function was not reported to the NRC within the required timeframe, thereby delaying the NRCs opportunity to review the matter. Using Example 6.9.d.9 from the NRC Enforcement Policy (the failure of a licensee to make a report as required by 10 CFR 50.72 or 10 CFR 50.73), the inspectors determined that the violation was a SL IV violation. Because this violation involves the traditional enforcement process and does not have an underlying technical violation, inspectors did not assign a cross-cutting aspect, in accordance with IMC 0612, Appendix B.
05000293/FIN-2017002-012017Q2PilgrimFailure to Follow Procedure Requirements for the Control of a Flood Protection BarrierAn NRC-identified Green finding was identified because Entergy personnel did not follow Procedure 1.3.135, Control of Doors, to adequately control a condenser bay flood protection door. Specifically, on May 22, 2017, Entergy personnel failed to control door 25A, which is designed to mitigate condenser bay flooding to preclude adversely impacting the important to safety instrument air system. Entergys short-term corrective actions included closing the door and providing additional operator training. This issue was entered into the CAP as CR 2017-5746. The performance deficiency is more than minor because it is associated with the configuration 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. The finding was evaluated using IMC 0609, Appendix A, Exhibit 4, External Events Screening Questions, issued June 19, 2012, with respect to the degraded safety function of the flood barrier door. The finding was determined to be of very low safety significance (Green) because the failure of the flood door was determined to not degrade the instrument air system ability to support the feedwater injection function or the alternate injection through the control rod drive system. This is because the backup diesel driven compressor was available to be started locally and supply the instrument air headers. The finding also did not involve the total loss of any safety function. The finding has a cross-cutting aspect in the area of Human Performance - Procedure Adherence, because Entergy personnel did not follow processes, procedures, and work instructions. Specifically, Entergy personnel did not follow procedural requirements to adequately control flood protection door 25A. (H.8)
05000293/FIN-2017002-032017Q2PilgrimInaccurate Suppression Pool Water Level Instrument not Identified during Post-event Prompt InvestigationAn NRC-identified Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, was identified because Entergy staff did not identify and correct a condition adverse to quality related to suppression pool water level indication when the A suppression pool wide range instrument provided inaccurate level indication during the inadvertent suppression pool water level increase event on March 31, 2017. As corrective actions, Entergy entered Technical Specification (TS) 3.2.F, Protective Instrumentation - Surveillance Information Readouts, and repaired the instrument. This issue was entered into Entergys corrective action program (CAP) as condition report (CR) 2017-2965. The performance deficiency is more than minor because if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern. Specifically, inaccurate level indication during off-normal changing level conditions in the suppression pool could result in operator actions not warranted by plant conditions. The finding is also associated with the Initiating Events cornerstone. Using IMC 0609, Appendix A, Exhibit 1, issued June 19, 2012, The Significance Determination Process for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not cause a reactor trip and a loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution - Identification, because the Entergy organization did not demonstrate an appropriately low threshold for entering problems into their CAP. Specifically, Entergys prompt investigation of the inadvertent suppression pool level increase event did not identify that the A suppression pool wide range level instrument was not indicating properly and required corrective maintenance. (P.1)
05000293/FIN-2017002-042017Q2PilgrimImproper System Restoration Results in Suppression Pool InoperabilityA self-revealing Green NCV of TS 5.4.1.a, Procedures, was identified on March 31, 2017, when operators did not follow procedures and caused an inadvertent increase in the suppression pool water level. The inspectors determined that the operators did not restore the core spray system valve line-up as prescribed in Attachment 11 of Entergy Procedure 2.2.20, Core Spray, and the maintenance safety tag clearance sheet. Operator implementation of these documents is directed by Entergy Procedure EN-OP-102, Protective Caution Tagging, section 5.19(4)(b). As corrective actions, Entergy performed additional management oversight of control room operations and performed a root cause evaluation (RCE). This issue was entered into the CAP as CR-2017-2785. The performance deficiency is more than minor because it is associated with the equipment reliability attribute of the Mitigating Systems cornerstone objective 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 out of specification conditions on March 31, 2017, impacted suppression pool reliability because the suppression pool was not maintained within parameters required to ensure operability. Additionally, significant analysis was necessary to show the suppression pool and associated supports remained functional when TS requirements were not met. Using IMC 0609, Appendix A, Exhibit 2, issued June 19, 2012, The Significance Determination Process for Findings At-Power, the inspectors determined the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a mitigating structure, system, or component (SSC), the finding did not represent a loss of system and/or function, the finding did not represent an actual loss of a function of a single train for greater than the TS allowed outage time (AOT), and the finding did not represent an actual loss of a function of one or more non-TS trains of equipment. Specifically, the suppression pool, including downcomers and supports, remained functional following the influx of water. The finding has a cross-cutting aspect in the area of Human Performance - Procedure Adherence, because Entergy personnel did not follow processes, procedures, and work instructions. Specifically, Entergy personnel did not follow procedures and work instructions during the restoration of the core spray system. (H.8)
05000293/FIN-2017002-052017Q2PilgrimDamper Failure Causes Loss of Secondary ContainmentA self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and TS 3.7.C.2, Containment Systems Secondary Containment, was identified because Entergy did not establish an appropriate interval to overhaul the secondary containment isolation dampers. As a result, the refueling floor supply isolation dampers were operated beyond the recommended overhaul interval and subsequently failed. Entergys corrective actions included cleaning, lubricating, and post-work testing the failed refueling floor supply isolation dampers. This issue was entered into the CAP as CR 2017-0494. The performance deficiency is more than minor because it is associated with the SSC and barrier performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, Entergys preventative maintenance (PM) for the refueling floor supply isolation dampers was inadequate to ensure the availability and reliability of SSCs required to maintain secondary containment operable. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of 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 only represented a degradation of the radiological barrier function provided by the reactor building and standby gas treatment system (SBGTS). The finding has a cross-cutting aspect in the area of Problem Identification and Resolution - Resolution, in that Entergy personnel did not take effective corrective actions to address issues in a timely manner. Specifically, in 2016, Entergy personnel identified there were deficiencies in the PM program with technical justifications for deferring PMs. Entergy reasonably had the opportunity to identify which PMs were not performed within recommended guidelines and make appropriate changes as needed. (P.3)
05000293/FIN-2017002-082017Q2PilgrimLicensee-Identified Violation10 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 procedures. Entergy Procedure EN-OP-104, Operability Determination Process, requires that operators have a reasonable expectation of operability when determining the operability of a component. On April 15, 2017, operators did not have a reasonable expectation of operability, as required by EN-OP-104, and incorrectly declared the B SRM operable without reasonable assurance. This resulted in a violation of TS 3.10.B, Core Alterations, which requires, during core alterations, when fuel is in the vessel, at least 2 SRMs shall be operable, one in the quadrant where fuel or control rods are being moved and one in an adjacent quadrant. Entergy entered this issue into the CAP as CRs 2017-3541, 2017-3952, 2017-5294, and 2017-6724. Entergy repaired the B SRM, and performed a causal evaluation on the equipment failure that includes the late inoperability determination by the operators. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix G, Attachment 1, Exhibit 3, Mitigating Systems Screening Questions. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not affect the design or qualification of a system, and did not represent a loss of safety function of a train or system, and did not degrade a functional auto-isolation of RHR on low reactor vessel level.
05000293/FIN-2017002-022017Q2PilgrimReporting of Unplanned Scrams with Complications Performance Indicator for Feedwater Regulating Valve ScramThe inspectors identified an unresolved item (URI) associated with Entergys reporting of Unplanned Scrams with Complications PI data for the third quarter of 2016. Description. On September 6, 2016, PNPS operators initiated a manual reactor scram based on oscillating feed flow as a result of a malfunction with feedwater regulating valve (FRV) A. As a result of high reactor vessel water level, all of the reactor feed pumps tripped, the HPCI and RCIC systems isolated, and a Group 1 isolation signal was present, initiating closure of the MSIVs. In order to maintain pressure control of the reactor, SRV 3B was manually cycled. This event was reported under Licensee Event Report (LER) 05000293/2016-007-00. During the scram response, PNPS operators were required to use an SRV to maintain reactor pressure control, but Entergys submittal of PI data for the third quarter of 2016 does not count the scram as an Unplanned Scram with Complications, which is required by EN-LI-114, Regulatory Performance Indicator Process. This URI is being opened to determine if a performance deficiency exists pending resolution of the differing interpretation of guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guidance, Revision 7, at the next scheduled Reactor Oversight Process Working Group Meeting. (URI 05000293/2017002-02, Reporting of Unplanned Scrams with Complications Performance Indicator for Feedwater Regulating Valve Scram)
05000220/FIN-2017001-022017Q1Nine Mile PointFailure to Identify and Correct a Non- Conforming Condition in Safety-Related UPSsGreen. The inspectors documented a self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, for the failure to identify and correct a non-conformance (an inadequate capacitor) in safety-related uninterruptable power supplies (UPSs) 162 and 172. Between 2008 and 2017, this non-conformance led to multiple component failures, loss of vital power supplies, plant transients, and in one case, loss of the emergency condenser safety function. Specifically, in 2003, during a preventative maintenance activity, NMPNS installed a commercially dedicated capacitor (part number C-805) that was not rated for the normal service temperature for the application. This resulted in chronic overheating, reduction of service life, and in seven cases failures (internal shorts of C-805) which resulted in the loss of the associated safety-related UPS. Upon identification, Exelon entered each failure into the CAP conducted an apparent cause evaluation (ACE) following the 2016 and 2017 failures, and developed corrective actions to replace the underrated capacitors. The performance deficiency was determined to be more than minor because it affected the equipment performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge the critical safety functions during shutdown as well as power operations. Specifically, the underrated capacitors failure resulted in the loss of a vital alternating current (AC) bus, a support system and in one case the unplanned loss of a safety function required to bring and maintain the plant in safe shutdown. In accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, a detailed risk assessment was required. Using the NMPNS Unit 1 Standardized Plant Analysis Risk (SPAR) Model Version: 8.21, model date January 28, 2010, a Region I senior reactor analyst ran a zero maintenance condition assessment with basic events for emergency condenser (EC) motor operated valve (MOV) 39-09R and EC MOV 39-10R, normally closed condensate return isolation valves, failed for a duration of one hour. The results were a CDP of 1.37E-08. The dominant risk sequences involved loss of feedwater and loss of offsite power. As a result, the finding is of very low safety significance (Green). The performance deficiency for this finding occurred in 2008. Because the performance deficiency occurred greater than 3 years ago and is not indicative of current performance based upon the corrective actions taken following the 2016 failure, there is no cross-cutting aspect assigned to this finding.
05000220/FIN-2017001-012017Q1Nine Mile PointDeficient Design Control of Outboard MSIV Pilot Valve Instrument Air SupplyGreen. The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, for Exelons failure to correctly translate the design basis into the NMPNS Unit 1 instrument air system to ensure the Unit 1 outboard main steam isolation valves (MSIVs) were capable of performing their design function. Specifically, the NMPNS Unit 1 Updated Final Safety Analysis Report (UFSAR) states, Reliable operation of instrument air end users and in-line components is dependent on the filtration and removal of particulates greater than 40 microns. Additional filtration for various components exists where the 40 micron limit is not satisfactory. The MSIV pilot valves at Unit 1 have a tighter clearance than the 40 micron limit. However, contrary to the UFSAR, NMPNS did not install additional filtration upstream of the pilot valves. As a result, during a surveillance test conducted on December 10, 2016, foreign material in the instrument air system potentially contributed to the failure of an outboard MSIV. Exelons immediate corrective actions included entering this issue into its corrective action program (CAP) as issue report (IR) 03959732, performing an air purge of the instrument air system to remove foreign material from the system, and replacing the current style pilot valves with new style valves with larger clearances during the spring 2017 refueling outage. The performance deficiency was determined to be more than minor because it was associated with the design control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents for events. Specifically, Exelon failed to install additional filtration in the instrument air system upstream of the outboard MSIV pilot valve in accordance with the Unit 1 UFSAR even though the internal clearance of the pilot valve was significantly less than the 40 micron particulate limit. Additionally, example 3.j from IMC 0612, Appendix E, Examples of Minor Issues, provides a similar scenario to this issue. Example 3.j details that a performance deficiency is more than minor if the error results in a condition where there is a reasonable doubt of the operability of a system or component. This performance deficiency is more than minor because without the additional filtration defined in the UFSAR there 4 existed a reasonable doubt of operability for the Unit 1 outboard MSIVs. The finding was evaluated in accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, and determined to be of very low safety significance (Green). The finding has a cross-cutting aspect in the area of Human Performance, Documentation, because Exelon failed to create and maintain complete, accurate, and up-to-date documentation pertaining to instrument air sampling for high particulate. Specifically, Exelon failed to develop and implement a surveillance testing program for the instrument air system that would alert personnel that particulate greater than 5 microns could jeopardize the operability of the outboard MSIVs. (H.7)
05000352/FIN-2017001-022017Q1LimerickFailure to Implement Human Performance Tools Results in Draining of Emergency Diesel Generator Jacket Water SystemGreen. The inspectors identified a Green self-revealing finding for the failure of Exelon personnel to follow procedures related to human performance tools which resulted in the inadvertent opening of a valve on the D13 emergency diesel generator (EDG). Specifically, Exelon personnel did not correctly identify and maintain a distance barrier from the diesel generator jacket water drain valve during a maintenance activity which resulted in the draining of the jacket water system and unplanned inoperability and unavailability of the D13 EDG. Exelon refilled the jacket water system, restored D13 EDG to an operable condition, and entered the issue into the corrective action program as IR 3986305. This finding is more than minor because it adversely affected the configuration control attribute of the mitigating systems cornerstone to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the valve mispositioning caused the D13 EDG to be inoperable and unavailable. Using IMC 0609, Appendix A, Exhibit 2, the inspectors determined that this finding was of very low safety significance (Green). Specifically, the finding did not represent a loss of system or function and did not represent the loss of a single train for greater than technical specification allowed outage times or greater than 24 hours. The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Exelon personnel did not properly implement error reduction tools. (H.12)
05000353/FIN-2017001-012017Q1LimerickInadequate Work Instructions for Staging of Equipment and Routing of Temporary Power CablesGreen. The inspectors identified a Green NCV of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for Exelons failure to establish instructions appropriate to the circumstances to properly stage equipment and route temporary power cables. Specifically, during cell replacement of the Class 1E 2A2 125/250 volts direct current (Vdc) safeguards battery, a portable battery charger was staged adjacent to operable 2A1 battery cells and not restrained to prevent potential tipping and shorting of exposed battery cell terminals and a non-safety related extension cord was routed in near contact with exposed safety related cables in an open cable tray. Exelon moved the portable battery charger, removed and rerouted extension cords, and entered the issues into the corrective action program as issue report (IR) 3980217; IR 3980203; and IR 3983203. This finding is more than minor because it adversely affected the configuration control attribute of the mitigating systems cornerstone to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the portable battery charger was adjacent to the 2A1 battery rack and oriented such that it was susceptible to tipping over and causing electrical shorting, and a non-safety related temporary power cable connected to a non-safety related power source was routed in near contact with safety related cables in an open cable tray which introduced a potential to damage and disable safety related equipment. Using IMC 0609, Appendix A, Exhibit 2, the inspectors determined that this finding was of very low safety significance (Green). Specifically, the finding did not represent a loss of system or function and did not represent the loss of a single train for greater than technical specification allowed outage times or greater than 24 hours. The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Training, because Exelon did not provide sufficient training to maintain a knowledgeable workforce and instill nuclear safety values associated with the staging of material and equipment. (H.9)
05000272/FIN-2016004-012016Q4SalemInadequate 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)
05000311/FIN-2016004-022016Q4SalemInadequate Surveillance Test Procedure Results in Water Hammer and Reactor TripGreen. The inspectors determined there was a self-revealing Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1.c, Surveillance and test activities of safety-related equipment, when PSEG did not establish adequate procedures for restoring service water (SW) to a drained section of discharge piping from the containment fan coil unit (CFCU) following surveillance test activities. Consequently, during restoration of SW to 22 CFCU following testing on August 31, 2016, refilling the voided SW piping created a pressure pulse sufficient to extrude the motor cooler cover plate spacer gasket inside primary containment, resulting in leakage that caused a 21 reactor coolant pump (RCP) cable fault and subsequent reactor trip. PSEG entered the issue in the corrective action program (CAP), performed a root cause evaluation (RCE), and revised applicable procedures for filling and venting SW to the CFCUs on September 19, 2016. This issue was more than minor since it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied upon to transition the plant to stable shutdown remained available. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because PSEG did not thoroughly evaluate previous CFCU motor cooler gasket leaks such that the resolution addressed the cause. (P.2)
05000272/FIN-2016004-032016Q4SalemLicensee-Identified ViolationThe following PSEG-identified violation of NRC requirements was determined to be of very low safety significance (Green) and meet the NRC Enforcement Policy criteria for being dispositioned as an NCV. As a result of a Salem Post-Fire Safe Shutdown Analysis update, PSEG submitted LER 272/1999-009-00 when they identified that cables for pressurizer PORVs and associated block valves were routed in the same containment cable trays, a fire-induced spurious operation concern, that could result in a pathway for a loss of reactor coolant inventory and pressure control. A similar condition was also identified for a fire in the control or relay rooms that could affect alternate shutdown capability. The NRC dispositioned this issue in IR 05000272;311/1999-010. On August 26, 2015, PSEG identified that they had not adequately completed corrective actions associated with the relay rooms. Specifically, a fire scenario involving cables within cabinets existed that could result in spurious PORV operation while preventing the ability to manually close block valves. At the time of this discovery, the safe shutdown analysis did not include the evaluations required to credit closure of both PORVs and block valves in the main control room prior to evacuation. Local, manual closure of the block valves had been incorporated into procedures but could be delayed up to 40 minutes in the scenario while EDGs were restored. The loss of reactor coolant inventory and pressure control had not been accounted for during this timeframe. The issue was determined to be more than minor since it was associated with the protection against external factors (Fire) attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was evaluated in accordance with IMC 0609, Appendix A, Attachment 4, and Appendix F. The IMC 0609, Appendix F, Attachment 1, Step 1.6, permits screening of the issue with PSEG fire PRA results provided there is an approved fire PRA for the plant. PSEG provided a fire PRA evaluation for the degraded condition but since the PRA results were not from a finalized, approved fire PRA, additional evaluation was required. The Senior Reactor Analyst (SRA) conducted a detailed assessment of the issue using the External Initiator Risk Informed Inspection Notebook for Salem Generating Station (Revision 1). Fires of concern were determined to be those confined to the Unit 1 and Unit 2 Relay Rooms. This is modeled in table 3.3.13 of the notebook as Fire Group M. For evaluation, it was assumed that Spurious PORV Due to Hot Short had a probability of 1.0. For this model, this would indicate a condition in which a PORV and its associated block valve were open. Given the exposure period of greater than 30 days, this would result in a change in core damage frequency of approximately 1E-8, Green, for Unit 1 and Unit 2. The notebook was conservative since the evaluation assumed the failure of the PORV to close as opposed to the more realistic probability that fire would cause a spurious failure of a PORV and hot short resulting in failure of the block valve. The dominant sequences included: 1) Fire in the relay room with a failure of the PORV to close and a failure of high pressure injection and 2) Fire in the relay room with a failure of the PORV to close and a failure of high pressure recirculation. PSEGs results were consistent with the SRAs analysis. Title 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that conditions adverse to quality are promptly identified and corrected. Salem Unit 1 and 2 license conditions 2.(C).5 and 2.(C).10 respectively require, in part, that PSEG shall implement and maintain all provisions of the fire protection program. PSEGs Quality Assurance Topical Report states that the Quality Assurance Program is applied to the Fire Protection Program consistent with Branch Technical Position APCSB 9.5-1 Appendix A, Section C requirements that include, under Corrective Action, that conditions adverse to fire protection are promptly identified, reported, and corrected. Contrary to this, from about 1999 to August 2015, actions from a previous, related fire-induced circuit failure scenario did not completely correct the condition resulting in the inability to credit manual closure of PORV and PORV block valves in an associated fire scenario. PSEG entered this in their CAP as NOTFs 20700943 and 20750010.
05000277/FIN-2016004-012016Q4Peach BottomFailure to Identify and Remove FM in CAD System PipingGreen. The inspectors identified a finding of very low safety significance (Green) involving a non-cited violation (NCV) of 10 CFR 50 Appendix B Criterion XVI, Corrective Action, because Exelon did not adequately identify and correct a condition adverse to quality associated with the containment atmospheric dilution (CAD) piping system. Specifically, in 2012, Exelon did not adequately identify the source of foreign material (FM) and implement corrective actions to remove the FM from the CAD piping which resulted in the failure of the CHK-2-07C-40145 containment isolation valve to close in 2016. Exelon documented the issue in issue report (IR) 2735344 and promptly replaced the valve and restored the valve to operable. As an interim corrective action, Exelon plans to increase the local leak-rate test (LLRT) frequency and replacement of the check valve to maintain reasonable assurance of operability. Exelon is implementing a detailed troubleshooting plan to identify the source of FM and perform corrective actions to address the condition adverse to quality. The performance deficiency (PD) is more than minor because it was associated with the containment barrier performance attribute of the barrier integrity cornerstone and it adversely impacted the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings at-Power, Exhibit 3, and the inspectors determined this finding to be of very low safety significance (Green) because the degraded condition did not represent an actual open pathway in the physical integrity of containment, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors determined that a cross cutting aspect does not apply because the performance deficiency occurred greater than three years ago and is not indicative of current plant performance.
05000336/FIN-2016003-012016Q3MillstoneFailure to Review Standing OrdersThe inspectors identified a Green NCV of Technical Specification (TS) 6.8.1.a, for Dominions failure to implement procedures as required by Regulatory Guide 1.33, Revision 2, Appendix A.1, Administrative Procedures, during the performance of watch turnover. This resulted in multiple operators across multiple crews in both Unit 2 and 3 standing watch without performing a review of the applicable standing orders for up to 4 months from March to July 2016. Dominion entered the condition in their corrective action program (CAP) as condition report (CR)1042287. The inspectors determined that the finding was more than minor because if left uncorrected the performance deficiency could lead to a more significant event. Specifically, the operators did not review TS amendments, emergency action level classifications, emergency operating procedures, and plant computer issues impacting the plant prior to taking watch. Without reviewing the standing orders to understand the information contained within, operators could potentially take improper actions to control the plant during evolutions and abnormal conditions. The finding was determined to be of very low safety significance (Green) because it did not affect design or qualification of a mitigating structure, system, and component (SSC), did not represent a loss of system function, and did not involve external event mitigation systems. The inspectors determined that the finding has a cross-cutting aspect in the Human Performance cross-cutting area associated with Field Presence, where leaders are commonly seen in the work areas of the plant observing, coaching, and reinforcing standards and expectations. Specifically, Dominion leadership observations in the control room or management review of monthly standing order audits could have discovered the deviation from standards and expectations. (H.2)
05000423/FIN-2016003-022016Q3MillstoneFailure to Scope Safety Related Acoustic Valve Monitoring System into the Maintenance RuleThe inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b)(1), for Dominions failure to include the safety-related Unit 2 Pressurizer Safety Valve, Acoustic Valve Monitoring System (AVMS) SSC within the scope of the maintenance rule program. Specifically, Dominion removed the Millstone Unit 2 AVMS, which is required to remain functional during and following a design bases event to provide indication to operators in the control room of significant abnormal degradation of the reactor coolant pressure boundary and monitor for loss of coolant due to an open safety relief valve, from the scope of the maintenance rule monitoring program. Dominion has documented this condition in their CAP as CR1049493. The inspectors determined that the finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events 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. Specifically, Dominions removal of AVMS from maintenance rule performance and condition monitoring and the failures observed have resulted in the complete loss of availability and reliability of each channel of AVMS such that they cannot perform their intended function. The finding was determined to be of very low safety significance (Green) because the conditions associated with the most applicable design basis event are bound by the small break loss of coolant accident (LOCA) analysis and did not affect other systems used to mitigate a LOCA. This finding has a crosscutting aspect in the Human Performance cross-cutting area associated with Procedure Adherence, in that Millstone Maintenance Rule Expert Panel (MREP) members did not follow the Dominion maintenance rule program implementing procedure, ER-AA-MRL-100, which provides guidance for scoping systems into the maintenance rule. (H.8)
05000311/FIN-2016002-042016Q2SalemLicensee-Identified ViolationTS LCO 3.3.2.1 requires the ESFAS instrumentation channels and interlocks shown in Table 3.3-3 shall be operable. Table 3.3-3, Function 8, requires two channels of AFW automatic actuation logic to be operable in Modes 1, 2, and 3. With the number of operable channels one less than the required number of channels, TS LCO 3.3.2.1 requires the inoperable channel to be restored to operable status within 6 hours or, be in at least Hot Standby within the next 6 hours and in at least Hot Shutdown within the following 6 hours. Contrary to TS LCO 3.3.2.1, one less than the required number of channels of AFW automatic actuation logic were operable from April 20, 2015, until Unit 2 entered Mode 4 for a scheduled refueling outage on October 23, 2015. This was due to the 21 AFW pump loop time response being greater than the allowed TS value because the isolation valve for the pressure override defeat pressure transmitter was in the closed position. PSEG entered this issue into the CAP as NOTFs 20709417, 20716352, 20710947, and 20711796. This performance deficiency was more than minor because it was associated with the human performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated this finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2. The inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time.
05000277/FIN-2016002-022016Q2Peach BottomUntimely Corrective Actions to Address Condition Adverse to the Fire Protection Program Alternative Shutdown CapabilityThe inspectors identified an NCV of very low safety significance (Green) of PB Unit 2 and Unit 3 Facility Operating License condition 2.C.(4) for failure to implement and maintain in effect all provisions of the approved fire protection program. Exelon did not correct a condition adverse to the fire protection program alternative shutdown capability in a timely manner. Specifically, Exelon did not establish testing requirements for transfer/isolation switches since the identification of the issue on February 6, 2014, and the due date to complete this action was extended to February 24, 2018. As a result, Exelon has delayed assurance that the components credited for alternative shutdown capability would perform their fire protection design basis function. Exelon entered this issue into their CAP as IR 02669323. This performance deficiency (PD) was more than minor because it was associated with the protection against external factors (fire) attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, by failing to correct the condition, Exelon has not ensured that the control circuit for the safe shutdown components would be isolated from the effects of fire damage. The inspectors determined that the finding was of very low safety significance (Green) based on IMC 0609, Appendix F, Fire Protection SDP, task number 1.3.1, because Exelon had demonstrated reasonable expectation of functionality for these switches by having comparable switches in the test program and periodically testing those switches. The test results did not indicate any kind of significant failures of these switches. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Resources, in that, Exelon extended the due date to complete the corrective action to support the completion of higher priority items, indicating lack of resources.
05000311/FIN-2016002-032016Q2SalemInadequate Work Order Planning Results in Main Generator AVR STV Relay TripA Green, self-revealing finding (FIN) was identified against MA-AA-716-010, Maintenance Planning Process, Revision 18, when PSEG work orders (WOs) did not specify the appropriate procedure to perform satisfactory modification testing of the main generator automatic voltage regulator (AVR) protective relay (model STV1). Consequently, the relay actuated below its design setpoint on February 4, 2016, resulting in an automatic trip of the Unit 2 main turbine and reactor. PSEG entered the issue in their Corrective Action Program (CAP) and performed a root cause evaluation (RCE), replaced the failed STV1 relay with a properly tested relay, verified other STV relays were appropriately tested as an extent of condition, and initiated an action to revise Laboratory Testing Services (LTS) department relay test procedures to ensure all applicable acceptance criteria will be incorporated. The inspectors determined that a performance deficiency existed because PSEG WOs did not specify the appropriate procedure to perform satisfactory modification testing of the main generator AVR protection relay. This issue was more than minor since it was associated with the procedure quality attribute of the Initiating Events cornerstone and adversely impacted its objective to limit the likelihood of events that upset plant stability (turbine and reactor trip) and challenge critical safety functions. Using IMC 0609, Attachment 4 and Appendix A, Exhibit 1, the inspectors determined that this finding was of very low safety significance, or Green, since mitigating equipment relied up to transition the plant to stable shutdown remained available. The finding had a cross-cutting aspect in the area of Human Performance, Work Management, in that the PSEG did not adequately implement the work process to coordinate with engineering and maintenance departments as needed to appropriately plan the STV1 relay modification test WO.
05000272/FIN-2016002-012016Q2SalemBaffle-Former Bolts with Identified AnomaliesThe inspectors determined the level of degradation of Unit 1 baffle bolts reported to the NRC as a condition not previously analyzed is an issue of concern that warrants additional inspection to determine whether a performance deficiency exists. As a result, the NRC opened a unresolved item (URI). Additional inspection is warranted to determine whether a performance deficiency exists related to Event Notification 51902, dated May 3, 2016, in which PSEG reported to the NRC that the level of degradation of baffle bolts was a condition not previously analyzed. The baffle bolts secure plates in the reactor core barrel to form a shroud around the fuel core to direct reactor coolant flow upward through the fuel assemblies. In order to determine if a performance deficiency exists, the inspectors will review the results of PSEGs RCE which will be completed at a later date.
05000311/FIN-2016002-022016Q2SalemWithdrawn - Failure to Follow Operability Determination Procedure for Unit 2 Baffle-Former BoltsThe inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," because, from June 15, 2016 until July 26, 2016, PSEG did not accomplish actions necessary to provide adequate confidence that a structure, system, and component (SSC) would perform satisfactorily in service (an activity affecting quality) as prescribed by a documented procedure. Specifically, although PSEG had concluded Salem Unit 2 is susceptible to baffle bolt failure due to its design and operating life (but less susceptible than Salem Unit 1), PSEG inadequately implemented Procedure OP-AA-108-115, "Operability Determinations & Functionality Assessments," Sections 4.7.14 followed by Sections 4.7.18-4.7.20 to perform an operability evaluation (OpEval) to justify continued operation of the unit until the next refueling outage. PSEGs immediate corrective actions included entering the issue into its corrective action program (NOTF 20736630) and documenting an operability evaluation to support the basis for functionality of the baffle structure and the operability of the emergency core cooling system (ECCS) and reactivity control systems. This finding is more than minor because it is associated with the equipment performance 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, in that degradation of a significant number of baffle bolts could result in baffle plates dislodging following an accident. This issue was dispositioned as more than minor because it was also similar to example 3.j of IMC 0612, Appendix E, Examples of Minor Issues, in that the condition resulted in reasonable doubt of operability of the ECCS and additional analysis was necessary to verify operability. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors screened the finding for safety significance and determined it to be of very low safety significance (Green), since the finding did not represent an actual loss of system or function. After inspector questioning, PSEG performed OpEval 2016-015, which provided sufficient bases to conclude the Unit 2 baffle assembly would support ECCS and control rod system operability until the next refueling outage. This finding is related to the cross-cutting aspect of Operating Experience because PSEG did not effectively evaluate relevant internal and external operating experience. Specifically, PSEG did not adequately evaluate the impact of degraded baffle bolts in Unit 2 when directly relevant operating experience was identified at Unit 1.
05000277/FIN-2016002-012016Q2Peach BottomImproperly Stored Material in Reactor BuildingThe NRC identified a very low safety significance (Green) NCV of Technical Specification (TS) 5.4.1 for Exelons failure to adequately implement procedure requirements governing the storage of material in a safety-related structure. Specifically, on April 26, 2016, Exelon technicians stored ladders vertically without them being adequately tied off to prevent the ladders from falling over in accordance with MA-AA-716-026, Station Housekeeping / Material Condition Program. The inspectors identified that the ladders were stored in the PB Unit 2 reactor building (RB), such that they could fall over and impact safety-related equipment. The inspectors promptly notified Exelon, the ladders were immediately removed, and the condition was documented under IR 2661309. This finding was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings At-Power, Exhibit 2. The inspectors determined this finding to be of very low safety significance (Green) because the degraded condition was not a design deficiency that affected system operability; did not represent an actual loss of function of a system; did not represent an actual loss of function of a single train or two separate trains for greater than its TS allowed outage time; and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant. The finding was determined to have a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Exelon technicians did not store ladders in safety-related buildings in accordance with station procedures, such that they could not fall over and damage safety-related equipment.
05000277/FIN-2016002-032016Q2Peach BottomHuman Performance Event Results in Emergent DownpowerA self-revealing finding of very low safety significance (Green) was identified for the failure of Exelon operators to use human performance error reduction tools during equipment manipulation in accordance with HU-AA-101, Human Performance Tools and Verification Practices. Specifically, on March 28, 2016, an equipment operator failed to use self-check (STAR) while removing a circuit breaker from service and incorrectly tripped the E-124 480 volt supply breaker which required a rapid manual power reduction to 80 percent rated thermal power (RTP) due to lowering main condenser vacuum and a partial loss of feedwater heating. Exelon entered the issue into their corrective action program (CAP) under issue report (IR) 2646772 and performed a root cause which identified corrective actions to address the adverse human performance behaviors at the station. The finding was more than minor because it was associated with the human performance 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, an equipment operator failed to adequately use human performance error reduction tools and opened an incorrect breaker which required a rapid downpower. The inspectors evaluated the finding in accordance with Exhibit 1 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance (Green) because it did not result in a reactor trip and the loss of mitigation equipment relied upon for transition to a stable shutdown condition. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Field Presence, because Exelon did not ensure that deviations from standards and expectations, which were identified by leaders, were corrected promptly. Specifically, Exelon identified that adverse human performance behaviors existed with certain equipment operators, however, those observations were not appropriately input into their performance management system, such that the behaviors could be addressed. Thus, these adverse behaviors were a primary contributor to this human performance error.
05000354/FIN-2015007-022015Q4Hope CreekInadequate work order instructions and drawings resulting in improper installation of a safety-related SW valve.Green. The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not provide adequate work order instructions for the reinstallation of service water (SW) pump discharge isolation valve EAHV-2198C following planned valve maintenance in October 2013. Specifically, the inadequate work order instructions contributed directly to maintenance technicians installing the valve in the opposite orientation compared to the intended orientation. PSEG entered this issue into their corrective action program. In addition, PSEGs corrective actions included completing several associated technical evaluations, calculations, operability determinations, and motor-operated valve performance tests. The team determined that the failure to provide adequate work order instructions for the installation of safety-related SW valve 2198C was a performance deficiency. The team determined that this performance deficiency was more than minor in accordance with IMC 0612, Power Reactor Inspection Report, Appendix B, because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems (SW) that respond to initiating events to prevent undesirable consequences. Additionally, the team determined that it was more than minor in accordance with IMC 0612, Appendix E, Example 3j, because PSEGs associated operability and technical evaluations did not adequately consider the worst case conditions, resulting in a potential underestimation of the maximum required opening torque and in a condition where there was a reasonable doubt on the operability of the C SW train. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 - Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a deficiency that affected the design and qualification of safety-related SW valve 2198C but did not result in the loss of operability or functionality. The team determined that this finding has a cross- cutting aspect in Human Performance, Documentation, in that PSEG failed to ensure that design documentation and work packages were complete, thorough, accurate, and current.
05000289/FIN-2015004-012015Q4Three Mile IslandFailure to Trend Vibration Data for Safety Related River Water PumpThe inspectors identified a finding of very low safety significance involving an NCV of 10 Code of Federal Regulations (CFR) 50, Appendix B Criterion XVI, Corrective Action Program, because Exelon did not identify and correct a condition adverse to quality on the B nuclear river water pump (NR-P-1B). Specifically, Exelon did not properly evaluate an adverse vibration trend on NR-P-1B, which resulted in exceeding its in-service test (IST) required action level and declared inoperable on October 10, 2015. Exelon entered the condition into their corrective action program (CAP) as issue report 2568763 and emergently replaced the pump, engaged the vendor for short and long term design and material changes to correct the vibration, and created process and peer check corrective actions to ensure all vibration data is reviewed timely and trends are addressed commensurate with their safety significance. The performance deficiency is 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 elevated vibrations reduced the reliability and capability of NR-P-1B to perform its safety function. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, and determined this finding to be of very low safety significance (Green) because the degraded condition was not a design deficiency that affected system operability; did not represent an actual loss of function of a system; did not represent an actual loss of function of a single train or two separate trains for greater than its technical specification (TS) allowed outage time and did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety significant. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because the station did not thoroughly evaluate the elevated vibration data such that the issue was addressed before NR-P-1B became inoperable (P.2).
05000317/FIN-2015007-022015Q4Calvert CliffsFailure to Verify AC Equipment Operability at Design Loading and Voltage LevelsThe team identified a finding of very low safety significance (Green) involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, because Exelon failed to verify, in design basis calculations, that all required Class 1E alternating current (AC) components would perform their safety functions during design basis events. Specifically, the team found multiple examples where Exelon failed to ensure AC equipment operability and functionality at maximum postulated loading levels and minimum allowable voltage levels. Specifically, the team found that during design basis events several transformers exceeded their manufacturers rating and Exelon had not performed an analysis that demonstrated voltage trip setpoints of the degraded voltage relays would ensure adequate voltage was available to supplied equipment. Exelon entered this issue into the corrective action program and performed preliminary analysis to show that there was reasonable assurance that equipment remained operable. The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone design control attribute and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and was similar to Example 3j in Appendix E of the NRC IMC 0612. Using the NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. The team did not identify a cross-cutting aspect with this finding because it did not represent current performance.
05000317/FIN-2015007-012015Q4Calvert CliffsInadequate Verification of Offsite Power Operability LimitThe team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, "Design Control," because Exelon did not ensure the operability of offsite power in design calculations. The team determined that non-conservative assumptions caused the results of the voltage calculation to predict higher 4160 Volts, Alternating Current (VAC) switchgear post-trip voltage levels than those which could occur with existing controls. Specifically, the team found that Exelons calculation assumed a 3.2 percent switchyard voltage drop upon main generator trip, which did not bound the 5 percent alarm setting provided by the Transmission System Operator Security Analysis application. The team also determined that Exelon used a non-quantitative evaluation, which could not be verified, to adjust design basis calculation results in order to show that during a design basis event the 4160 VAC bus voltage would recover in time to reset the degraded voltage relay prior to the transient degraded voltage relay (TUR) tripping (causing a loss of offsite power). The team could not determine if offsite power would be lost during the event because these assumptions could not be validated. Exelon entered the issue into the corrective action program and performed preliminary computer modeling of the current plant configuration that showed offsite power was operable. The finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone design control attribute and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and was similar to Example 3j in Appendix E of the NRC IMC 0612. Using the NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety significance (Green) because it was a design deficiency confirmed not to result in the loss of operability or functionality. This finding was not assigned a cross-cutting aspect because it was a historical design issue not indicative of current performance.
05000354/FIN-2015007-012015Q4Hope CreekFailure to establish appropriate acceptance criteria for RHR and core spray pump start times during simulated LOCA/LOP testing.The team identified a finding of very low safety significance involving a non-cited violation of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because PSEG did not establish appropriate acceptance criteria for the time allowed for starting the residual heat removal (RHR) and core spray pumps during simulated loss-of-coolant accident/loss-of-offsite power (LOCA/LOP) conditions in the 18-month integrated emergency diesel generator (EDG) surveillance test (ST) for the vital 4KV buses. Specifically, the ST acceptance criteria failed to confirm that the pumps started in accordance with the design basis loading sequence described in the design analyses and Updated Final Safety Analysis Report Table 8.3-1. PSEGs short-term corrective actions included reviewing LOCA/LOP test results and plant historical data to confirm current operability of the RHR and core spray pumps, and initiating corrective action notifications to determine the appropriate ST acceptance criteria and to trend pump start times. The team determined that the failure to specify adequate acceptance limits for the design basis assigned start times for the RHR and core spray pumps during LOCA/LOP conditions in the 18-month integrated EDG ST procedure was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2 Mitigating Systems Screening Questions, and determined that the finding was of very low safety significance (Green) because the finding was a design deficiency that did not result in the loss of operability or functionality. The team determined that this finding has a cross-cutting aspect in Human Performance, Documentation, in that PSEG failed to maintain accurate test acceptance documentation to aid plant staff in the identification of equipment performance that was outside the acceptable limits of design.
05000387/FIN-2015002-032015Q2SusquehannaIncorrect Implementation of the Ventilation Filter Testing ProgramThe inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, because Susquehanna did not ensure representative samples were obtained from Engineered Safety Feature (ESF) filter ventilation systems and did not establish written test procedures. Specifically, subsequent to refilling charcoal test canisters for the activated charcoal absorber of both trains of the SBGT System, new charcoal was added to the activated charcoal absorber which was not exposed to the same service conditions as the bulk of the absorber section as required by TS 5.5.7, Ventilation Filter Testing Program, and written test procedures were not established for this activity. As corrective action for the identified issue, Susquehanna replaced the charcoal in the A and B trains of SBGT and the A and B trains of CREOASS activated charcoal absorber beds and test canisters between January and February 2015 and initiated condition reports CR-2014-39116 and CR-2015-01443. The inspectors determined that the finding was more than minor because it was associated with the Procedure Quality Attribute of the Barrier Integrity Cornerstone and it adversely affected the cornerstone objective to provide reasonable assurance that physical barriers protect the public from radionuclide releases caused by accidents or events. Specifically, since 2001, work instructions did not prevent the contamination of test canisters with charcoal that was not representative of the in-service conditions of the adsorber bed and the introduction of new charcoal into the test canisters likely provided better results during periodic surveillance testing which were not representative of actual conditions. In accordance with IMC 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Exhibit 3 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that the finding was of very low safety significance (Green) because it only represented a degradation of the radiological barrier function provided for the control room and SBGT system. This finding has a cross-cutting aspect in the area of Human Performance, Documentation, because the activities for sampling the activated charcoal beds were not governed by comprehensive, high-quality programs, processes, and procedures nor were the design documentation, procedures, and work packages complete, thorough and accurate.
05000387/FIN-2015002-042015Q2SusquehannaMultiple Violations of Work Hour Limitations by Licensed OperatorsThe inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 26.205, Work Hours, because Susquehanna did not ensure that the working hours of licensed operators were maintained within regulatory limits. Specifically, numerous instances of violations were identified in the operations department in which individuals exceeded the required work hour limits while performing duties subject to work hour controls. In review of the issue, the inspectors identified that Susquehanna inappropriately excluded some works hours performing non-covered work from the total accumulated work hours, which allowed individuals to perform covered work while in excess of the work hour limits without meeting the requirements for applying a waiver. Susquehanna entered the issue into the CAP as CR-2015-15708 and initiated action to evaluate the extent of the matter and communicate the issue with the operations department, reinforce the standards for work hour tracking with station personnel, and ensure work hours are appropriately tracked. The inspectors determined that the finding was more than minor because Susquehanna inadequately implemented the requirements of 10 CFR 26.205 and NDAP-QA-0025 routinely. Therefore, if the performance deficiency were left uncorrected, the continued process of not including all hours accumulated toward work hour limits and allowing workers to exceed work hour limits, had the potential to lead to a more significant safety concern. The finding was also similar to IMC 0612, Appendix E, "Examples of Minor Issues," Example 9.a. In accordance with IMC 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Exhibits 1 and 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because no transients, loss of function of a mitigating system, or mismanagement of reactivity occurred as a result of licensed operators performing covered work while not in compliance with the work hour limits specified in 10 CFR 26.205. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, because Susquehanna did not identify the issues completely, accurately, and in a timely manner. Specifically, Susquehanna identified violations of work hour limits on multiple occasions but the CRs were not in sufficient detail to ensure they were appropriately prioritized and assigned for resolution. Individuals did not recognize that work performed doing non-covered work was to be counted as hours accumulated towards the work hour limitations and thus discounted the violations as erroneous.
05000388/FIN-2015002-052015Q2SusquehannaLoss of Main Condenser Vacuum When Transitioning Steam Seals to Auxiliary SteamA self-revealing finding of very low safety significance (Green) and associated NCV of SSES Unit 2 TS 5.4.1, Procedures, was identified because Susquehanna incorrectly implemented procedures for operation of the auxiliary steam and main turbine steam sealing systems. Specifically, on April 10, 2015, while Unit 2 was being shut down for a RFO, operators secured main turbine steam seals resulting in degraded main condenser vacuum. The degraded main condenser vacuum resulted in a main turbine trip, which caused an automatic reactor scram from approximately 37% power. Susquehanna restored main condenser vacuum by reestablishing steam seals, performed off-normal and emergency operating procedures to stabilize the plant post-scram and entered the issue into the corrective action program (CAP) as CR-2015-09890. The finding was more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not understanding the impact of securing auxiliary steam to the main turbine steam seals resulted in the degradation of main condenser vacuum, automatic trip of the main turbine and associated reactor scram. The inspectors evaluated the finding in accordance with IMC 0609, Appendix A "The SDP for Findings At-Power," Exhibit 1, for the Initiating Events cornerstone, dated June 19, 2012. The inspectors determined the finding was of very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment. Specifically, though a reactor scram occurred, operators were able to restore main condenser vacuum prior to MSIV closure and the main condenser and reactor feed pumps remained functional during the event. This finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Susquehanna did not implement appropriate error reduction tools. Specifically, operators did not effectively implement human error prevention tools (e.g. pre-job briefing, stop-think-act-review) in accordance with station processes.
05000387/FIN-2015002-022015Q2SusquehannaEntry into a High Radiation Area without Radiological BriefingA self-revealing finding of very low safety significance (Green) and associated NCV of SSES Unit 2 TS 5.7.1 was identified because Susquehanna did not comply with a radiological posting barrier and other protective measures for HRA entry. Specifically, on October 10, 2014, two workers entered the turbine building roof, a posted HRA, but the workers were not on the proper RWP and were not briefed on the radiological conditions prior to entry. Upon receiving a dose rate alarm, the workers exited the HRA and reported the issue to radiation protection personnel. Susquehanna entered the issue into the CAP as condition report CR-2014-31911. The inspectors determined that Susquehannas inadequate adherence to a high radiation area (HRA) posting, which requires a HRA RWP and a radiological briefing prior to entry, was a performance deficiency that was within Susquehannas ability to foresee and correct and should have been prevented. The inspectors determined that the finding was more than minor because it adversely affected the human performance attribute of the Occupational Radiation Safety cornerstone objective. Specifically, the individual violated the RWP and briefing requirements designed to protect the worker from unnecessary radiation exposure. The issue was also similar to example 6.h in IMC 0612, Appendix E. Using IMC 0609, Appendix C, Occupational Radiation Safety SDP, dated August 19, 2008, the finding was determined to be of very low safety significance (Green) because it did not involve: (1) as low as is reasonably achievable (ALARA) occupational collective exposure planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding has a cross-cutting aspect of Human Performance, Challenge the Unknown, because the workers did not stop when faced with uncertain conditions. Specifically, the workers did not use a questioning attitude during the pre-job brief or when they encountered the HRA posting on the access to the turbine building roof.
05000272/FIN-2015008-012015Q2SalemInadequate Maintenance Rule System Performance Criteria SelectionThe inspectors identified a URI associated with inadequate Maintenance Rule Performance Criteria selection. Specifically, the inspectors determined that PSEG did not follow station procedures to: 1) determine that the number of maintenance preventable functional failures (MPFF) allowed per 10 CFR 50.65(a)(3) evaluation period was consistent with the assumptions in the probabilistic risk assessment (PRA); and 2) review and approve reliability performance criteria (PC) that was higher than the number of PRA-supplied basic event failures. The inspectors determined that additional information was needed to determine if these performance deficiencies were more than minor. The inspectors performed a review of PSEGs Focused Area Self-Assessment (FASA) of the Maintenance Rule (MRule) Program, completed August 30, 2014, to determine if PSEG was appropriately assessing MRule program performance in accordance with LS-AA-126-1001, Self-Assessments. The purpose of PSEGs FASA was to ensure the MRule Program was implemented in accordance with 10 CFR 50.65, as well as PSEG program procedures. The inspectors noted that the MRule Program FASA met the requirements of LS-AA-126-1001, was sufficiently critical, identified several deficiencies that were entered into the CAP, and resulted in multiple recommendations. As a result of the FASA, PSEG determined that multiple structures, systems, and components (SSCs) in (a)(2) status had to be re-evaluated for (a)(1) status, due to those SSCs having had their Functional Failure Cause Determinations (FFCDE) and unavailability (UA) amounts incorrectly assessed in the past. The inspectors reviewed the list of systems re-evaluated for (a)(1) status due to the FASA, as well as a listing of systems that remained in (a)(2) status and actual SSC performance data against the PC established under ER-AA-310-1003, Maintenance Rule Performance Criteria Selection. During this review the inspectors noted approximately 25 high safety significant systems (HSS) with reliability PC greater than two maintenance preventable functional failures (MPFFs). According to ER-AA-310-1003, Attachment 3, flowchart Process for Selecting Reliability Performance Criteria, HSS SSCs, with reliability PC greater than or equal to two MPFFs require SSC past performance documentation. Additionally, Attachment 1, steps 2.B.3 and 2.B.4, state that for HSS SSCs with high risk achievement worth (RAW) values, a reliability PC greater than or equal to zero or one MPFF requires SSC past performance documentation. The inspectors requested that PSEG provide past performance documentation for the HSS SSCs with reliability PC greater than two MPFFs. PSEG provided documentation of HSS SSC PC approval from 1997, when the MRule Program was first implemented by PSEG. The inspectors determined this documentation did not support the assigned PC, because it did not consider the last 18 years of SSC past performance. The inspectors also reviewed ER-AA-310-1007, Maintenance Rule Periodic (a)(3) Assessment. Step 5.11.1.4 states Determine that the number of MPFFs allowed per evaluation period is consistent with the assumptions in the PRA. Contrary to ER-AA-310-1007, step 5.11.4, the last two periodic (a)(3) assessments performed by PSEG: April 1, 2011 through September 9, 2012; and October 1, 2012 through June 30, 2014; did not verify that the number of MPFFs allowed per evaluation period was consistent with the assumptions in the PRA. Additionally, ER-AA-310-1003, step 4.3.2, states, in part, that Unless justified and approved by the Maintenance Rule Expert Panel, the number of MPFFs selected, as a Reliability PC, may not be higher than the PRA-supplied number of Functional Failures (FFs). The inspectors then reviewed SC-MRULE-002, Maintenance Rule Performance Criteria Verification Following Salem SA112A PRA Update, subsequent to the most recent update performed in October 2014. The inspectors noted that to complete this verification, PSEG requantified the PRA model by changing the failure probabilities of the basic events to reflect the MRule PC. The result was a 98% increase in the Salem base core damage frequency (CDF) of 1.55E-05. The inspectors determined that this data was reflective of SSC reliability PC above the PRA-supplied number of basic event failures. As such, contrary to ER-AA-310-1003, step 4.3.2, the number of MPFFs selected as reliability PC was higher than the PRA-supplied number of FFs, and, based on the lack of documentation supplied by PSEG, the inspectors concluded this was not justified or approved by Maintenance Rule Expert Panel. The inspectors determined that the failure to meet ER-AA-310-1007, step 5.11.4, and ER-AA-310-1003, step 4.3.2, was a performance deficiency. However, at the time of inspection, the inspectors did not have the information needed to determine the consequence of the performance deficiency. Information was needed to determine whether the performance deficiency was more than minor. Specifically, PSEG did not provide SSC past performance documentation for HSS SSCs with reliability PC greater than the PRA-supplied number of basic event failures in accordance with ER-AA-310-1003 Attachment 1 and 3. The inspectors will use this information to determine whether the performance or condition of HSS SSCs was effectively controlled through the performance of appropriate preventive maintenance under 10 CFR 50.65(a)(2), and also to determine if those HSS SSCs being monitored under 10 CFR 50.65(a)(1) were assigned appropriate goals and monitoring when considered against the appropriate reliability PC threshold. This issue was determined to be a URI IAW Inspector Manual Chapter (IMC) 0612.
05000387/FIN-2015002-012015Q2SusquehannaFailure to Assess a Non-Conforming Condition for its Impact on Component OperabilityThe inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when Susquehanna staff did not assess component operability following identification of a potentially non-conforming condition. Specifically, Susquehanna did not assess for operability a potential non-conforming condition associated with inadequate testing of the primary containment airlock inboard equalizing valve which was identified during the review of industry operating experience. Susquehannas corrective actions to restore compliance included entering this issue in their CAP as CR-2015-15187, performing a prompt operability determination of the Unit 1 primary containment airlock inboard equalizing valve, including completion of the requirements in SR 3.0.3 for a missed surveillance, and performing testing on the Unit 2 valve which adequately demonstrated that the PCIV was operable prior to entering into a mode of TS applicability. The inspectors determined that the finding was more than minor because it was associated with the SSC and Barrier performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that the physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. Specifically, inadequate actions to evaluate the impact of the condition adverse to quality on the operability of the Unit 1 PCIV resulted in a reasonable doubt of operability of the barrier. In accordance with IMC 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Exhibit 2 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency did not represent an actual open pathway in the physical integrity of reactor containment and heat removal components or involve the actual reduction in function of hydrogen igniters in containment. This finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Susquehanna did not perform a thorough review of the work and planned activity but rather relied on past successes and assumed conditions. Specifically, the control room staff did not assess the condition for operability believing that it was similar to previous CRs documenting a review of operating experience.
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