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	Quarter	Site	Title	Description
05000289/FIN-2018012-01	2018Q2	Three Mile Island	Failure to Establish Appropriate Corrective ActionsAssociated with a Degraded Non-Safety Related Piping System.	The NRC identified a Green finding when Exelon failed to establish appropriate corrective actions for a non-safety related system in the vicinity of safety-related equipment from 2010 to 2018. Specifically, failure to fix non-safety related piping resulted in its failure and water intrusion into the ESAS cabinets. This resulted in an event that required extensive clean up and detailed inspection of several Emergency Safeguards Actuation System (ESAS) cabinets due to water intrusion from the non-safety related system.
05000286/FIN-2018001-02	2018Q1	Indian Point	Inadequate Procedure for Placing Chemical and Volume Control System Demineralizer In Service	A self-revealing Green NCV of Technical Specification 5.4.1, Procedures, was identified because Entergy failed to provide adequate guidance in 3-SOP-CVCS-004, Placing the CVCS Demineralizers In or Out of Service. Specifically, Entergy did not provide adequate procedural direction to prevent exceeding the reactor coolant filter differential pressure while placing the demineralizers in service. As a result, the pressurizer water level technical specification limit was exceeded and the CVCS piping upstream of the filter was over-pressurized resulting in diaphram ruptures on valves CH-305 and CH-352 thereby spreading contamination throughout the Primary Auxiliary Building.
05000247/FIN-2018001-01	2018Q1	Indian Point	Failure to Incorporate Adequate Test Controls for Quarterly Stroke Close Testing of the Steam Supply Valves to Turbine-Driven Auxiliary Feedwater Pump	The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, when Entergy did not assure that surveillance tests required to demonstrate that structures, systems, and components will perform satisfactorily in service are identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Specifically, during quarterly stroke testing of the steam isolation valves to the 22 turbine-driven auxiliary feedwater pump, PCV-1310A and PCV-1310B, Entergy did not ensure that these valves traveled to the closed position as required to verify that the safety function was met.
05000354/FIN-2016003-04	2016Q3	Hope Creek	Inadequate Corrective Actions for Main Control Room Chiller Positioner Failure	A self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for PSEGs inadequate corrective actions to address a condition adverse to quality (CAQ). Specifically, PSEGs corrective actions to address a December 2013 failure of the A main control room (MCR) chiller pressure control valve (PCV) positioner were inadequate and did not ensure that the component was appropriately managed in their shelf life program. As a result, PSEG restored the A MCR chiller with a PCV positioner that exceeded its specified shelf life by 10 years, and ultimately failed due to its age. PSEGs corrective actions included conducting an extensive extent of condition (EOC) of similar positioners installed at the site (both Salem and Hope Creek), reviewing the shelf life program, and documenting an operability evaluation (70189201) for the currently installed positioners until they can be replaced. This finding 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 (i.e., core damage). The degraded positioners being installed in both MCR chillers affected the reliability and availability of the A and B MCR chillers, which provide cooling for the MCR, emergency switchgear rooms, and the safety auxiliaries cooling system pump rooms. Using Exhibit 2 of IMC 0609, Appendix A, the inspectors determined that this finding is of very low safety significance (Green) because, although the performance deficiency (PD) affected the design/qualification of the A MCR chiller operability, it did not result in an actual loss of safety system function because the B chiller was still available, and it did not represent a loss of function of one or more than one train for more than its TS allowed outage time or greater than 24 hrs. The B MCR chiller remained available and the A MCR chiller was restored to an operable status within 6 hours of failing. This finding had a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because PSEG did not follow the process and procedure that ensures the shelf life program for safety-related components is properly maintained. Specifically, PSEG did not ensure that the shelf life of the MCR chiller PCV positioners were adequately managed in the shelf life program by verifying the correct shelf life of 14 years was correctly assigned.
05000354/FIN-2016003-02	2016Q3	Hope Creek	Untimely Submittal of an LER for a Condition that Could Have Prevented Fulfillment of a Safety Function	The Inspectors identified a Severity Level IV (SLIV) NCV of 10 CFR 50.73(a)(2)(v) for because PSEG did not submit a Licensee Event Report (LER) within 60 days of an event or condition that could have prevented the fulfillment of a safety function at any time within 3 years of the date of discovery. Specifically, while performing an in-service retest of the HPCI system, the turbine tripped on overspeed shortly after startup due to low spring force on the overspeed assembly reset spring. This condition allowed the overspeed tappet to trip the turbine without an actual overspeed condition present, rendering the system inoperable and unable to automatically initiate and inject at rated flow within 35 seconds as required per TSs and the design basis, thus preventing the fulfillment of a safety function. PSEGs corrective actions included documenting the missed LER in the corrective action program (CAP) in notification (NOTF) 20741046, and submitted LER 05000354/2016001-00 under 10 CFR 50.73(a)(2)(v)(D) on October 04, 2016. The inspectors evaluated this issue using the traditional enforcement process because the performance deficiency had the potential to impede or impact the NRCs regulatory process. Specifically, the failure to submit an LER under 10 CFR 50.73(a)(2)(v)(D) within 60 days of an event or condition that could have prevented the fulfillment of a safety function at any time within 3 years of the date of discovery could impact the NRCs regulatory process. The inspectors reviewed this issue in accordance with IMC 0612 and the Enforcement Manual; violations of 10 CFR 50.73 are dispositioned using the traditional enforcement process. The inspectors reviewed Section 6.9.d.9 of the NRC Enforcement Policy and determined this violation was a Severity Level IV violation because PSEG did not submit the LER as required by 10 CFR 50.73 did not cause the NRC to reconsider a regulatory position or undertake substantial further inquiry. The performance deficiency was screened against the Reactor Oversight Process (ROP) per the guidance of IMC 0612, Appendix B, Issue Screening, and no associated ROP finding was identified. In accordance with IMC 0612, Appendix B, this traditional enforcement issue is not assigned a cross-cutting aspect.
05000354/FIN-2016003-01	2016Q3	Hope Creek	Inadequate Implementation of Adverse Condition Monitoring Actions for the High Pressure Coolant Injection System	A self-revealing preliminary White finding and apparent violation (AV) of Title 10 of the Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and Technical Specification (TS) 3.5.1.c, Emergency Core Cooling Systems - High Pressure Coolant Injection (HPCI), was identified because PSEG did not detect and act upon an adverse trend of water intrusion into the HPCI oil system. Specifically, PSEG did not adequately implement procedure OP-AA-108-111, Adverse Condition Monitoring (ACM) and Contingency Planning, and the ACM HC 15-008 action to perform monthly HPCI turbine oil analysis for water contamination with known steam leakage by the Steam Admission Valve (FD-F001). Because these monthly oil samples were collected but were not analyzed for water content, PSEG did not identify significant moisture contamination in the HPCI oil system and thus take the necessary response actions. As a result, on August 6, 2016, the HPCI governor control valve (FV-4879) failed to stroke open as required due to moisture-induced corrosion that degraded its hydraulic actuator (EG-R). Consequently, PSEG violated TS 3.5.1.c because, based on failure of the FV-4879 and the EG-R to actuate on August 6, 2016, the NRC determined that the HPCI system was inoperable for a period greater than its technical specification (TS) allowed outage time of 14 days. PSEGs immediate corrective actions included entering the issue into their Corrective Action Program (CAP) (NOTFs 20737383, 20738402 and 20738403); repairing the HPCI turbine insulation; replacing the HPCI EG-R; flushing the HPCI turbine oil system; and replenishing the system with new oil. This finding is more than minor because it adversely affected the equipment performance attribute of the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, a loss of safety function occurred when elevated water concentration in the HPCI oil system corroded the EG-R, preventing the FV-4879 valve from opening and the HPCI system from starting/running. This resulted in HPCI system inoperability for greater than the 14 days allowed by TS. 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, the inspectors screened the finding for safety significance and determined that a detailed risk evaluation (DRE) was required based on the HPCI system being inoperable for greater than the TS allowed outage time of 14 days. The DRE was performed by a Region I senior reactor analyst (SRA) and concluded that the condition resulted in an increase in core damage frequency (CDF) of low E-6/yr., or of low-to-moderate safety significance (White). The SRA determined the increase in Large Early Release Frequency (LERF) was low E-7/yr., consistent with the significance determined for the internal and external event CDF. This finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because PSEG did not use decision-making practices that emphasize prudent choices over those that are simply allowable. In addition, PSEG did not take timely action to address degraded conditions commensurate with their safety significance.
05000354/FIN-2016003-03	2016Q3	Hope Creek	Inadequate Procedure Adherence Resulted in a Loss of Shutdown Cooling	A self-revealing non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, occurred when PSEG did not follow procedure during the transition from Cold Shutdown to refueling operations while filling up the reactor pressure vessel (RPV) to support RPV head cooling in preparation for reactor disassembly. This resulted in an automatic isolation of the operating residual heat removal (RHR) pump while it was providing decay heat removal in shutdown cooling. PSEG has entered this issue into their corrective action program (CAP) in notification (NOTF) 20684861, and corrective actions included performing a root cause evaluation for the event, revising the operating procedures to provide clarity, and conducting training with all operators on the lessons learned from the event. This issue was evaluated in accordance with IMC 0612, Appendix B, and determined to be more than minor since it was associated with the human performance attribute of the Initiating Events cornerstone and adversely 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. The finding was evaluated using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process (SDP), and per Attachment 1, Exhibit 2, required a Phase 2 risk evaluation which determined the safety significance of this performance deficiency to be in the mid E-8 range, or of very low safety significance (Green). The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Conservative Bias, in that the operator did not use decision-making practices that emphasized prudent choices over those that are simply allowable, and the operators proposed action was not determined to be safe prior to proceeding with the action. Specifically, the operator did not ensure his actions were safe prior to aligning and operating the feedwater system to fill the RPV during plant cooldown using an uncommon method.
05000311/FIN-2016002-02	2016Q2	Salem	Withdrawn - Failure to Follow Operability Determination Procedure for Unit 2 Baffle-Former Bolts	The 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.
05000272/FIN-2016002-01	2016Q2	Salem	Baffle-Former Bolts with Identified Anomalies	The 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-2016002-03	2016Q2	Salem	Inadequate Work Order Planning Results in Main Generator AVR STV Relay Trip	A 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.
05000311/FIN-2016002-04	2016Q2	Salem	Licensee-Identified Violation	TS 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.
05000354/FIN-2015004-02	2015Q4	Hope Creek	Licensee-Identified Violation	From 2010 to 2014, Hope Creek made a total of 12 shipments of radioactive waste for disposal, four of which contained a category 1 quantity of radioactive material, and eight which contained a category 2 quantity of radioactive material of concern. PSEG did not implement a transportation security plan for these shipments in violation of the requirements of 10 CFR 71.5, Transportation of Licensed Material, and 49 CFR 172, Subpart I, Safety and Security Plans. This performance deficiency adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive material. The finding was determined to be of very low safety significance (Green) because Hope Creek had an issue involving transportation of radioactive material, but it did not involve: (1) a radiation limit that was exceeded; (2) a breach of package during transport; (3) a certificate of compliance issue; (4) a low level burial ground non-conformance; or (5) a failure to make notifications or provide emergency information. This issue was documented in the PSEGs CAP as NOTF 20674767. Corrective actions included issuance of new procedure RP-AA-600-1009, revision of procedure LS-AA-1020, Implementation of Significant Rules and Orders, Revision 1, and contracting with a vendor to receive regular, prompt notifications of potentially applicable rule changes in the Federal Register.
05000354/FIN-2015004-01	2015Q4	Hope Creek	Failure to Follow CAP Procedures to Ensure Functionality of the Main Control Room during a Station Blackout	The inspectors identified a Green finding because PSEG did not follow procedures to ensure that an identified condition adverse to quality (CAQ) was adequately evaluated, documented, and corrected. Specifically, PSEG identified a CAQ associated with a station blackout (SBO) design calculation used to justify the main control room (MCR) heat load during a loss of ventilation, but failed to adequately evaluate, document and correct the CAQ. This CAQ challenged the reasonable assurance of functionality of the MCR during an SBO event and required PSEG to complete a detailed technical evaluation (TE) to prove functionality was maintained. PSEGs corrective actions included performing a detailed TE to ensure MCR temperatures during an SBO would not have exceeded a functionality limit, and initiating actions to ensure issues identifying a potential CAQ receive the appropriate screening by operators, engineering and management staff. PSEG also revised SBO procedures to ensure the proper electrical loads were included when required to be shed in the event of an SBO event. PSEG documented the issue in the corrective action program (CAP) as Notification (NOTF) 20704285. This finding was more than minor because it was associated with the human performance attribute of the Mitigating Systems cornerstone and adversely affected its objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the potential existed for the analyzed MCR heat load to be exceeded, affecting the ability of the MCR to remain functional during an SBO event. Additionally, the finding was similar to IMC 0612, Appendix E, examples j and k, in that, a design engineering calculation error resulted in a condition where there was a reasonable doubt of operability of a structure, system, or component (SSC). The finding was screened for significance in accordance with IMC 0609, Appendix A, Significance Determination Process (SDP) for Findings-at-Power, issued June 2, 2012. The finding screened as very low safety significance (Green) using Exhibit 2 for Mitigating Systems Screening Questions, because the finding is a deficiency affecting the design or qualification of a mitigating SSC, but the affected SSC maintains its operability and/or functionality. Specifically, the design calculation error was a CAQ that challenged the reasonable assurance of functionality of the MCR during an SBO event and required a TE to prove functionality of the MCR during an SBO event was maintained. The inspectors determined this finding has a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R), Evaluation, in that PSEG did not thoroughly evaluate the issue to ensure that resolutions address causes and extent of conditions, commensurate with its safety significance. Specifically, issues of concern need to be properly classified, prioritized, and evaluated according to their safety significance, and operability and reportability determinations are developed, when appropriate. In this case, PSEG did not properly classify or evaluate an identified CAQ per their procedures.
05000354/FIN-2015002-02	2015Q2	Hope Creek	Failure to Request a Generic Fundamentals Examination Waiver for a Senior Operator License Applicant	During a review of recently issued operator licenses, the NRC identified an NCV of 10 CFR 50.9 associated with the licensees failure to request a Generic Fundamentals Examination (GFE) waiver for a Senior Operator License applicant. Compliance was restored on May 4, 2015, when the licensee submitted a letter to the NRC which provided additional information concerning the issue. The Senior Reactor Operator (SRO) applicant had completed classroom instruction and successfully passed a licensee administered GFE on August 16, 2013, and had passed an NRC prepared GFE when previously licensed as a reactor operator at another utility. The applicant met the requirements to request a waiver to sit for the exam and would have been granted a waiver if it had been requested. The inspectors determined that traditional enforcement applied to this performance deficiency (PD), as the issue impacted the NRCs ability to perform its regulatory function. Specifically, the NRC relies upon the licensee to ensure all license applicants have completed the preparation requirements of NUREG-1021. The PD was determined to be Severity Level IV because it fits the SL-IV example of Enforcement Policy Section 6.4.d.1.a, Violation Examples: Licensed Reactor Operators. This section states, Severity Level IV violations involve for example ...cases of inaccurate or incomplete information inadvertently provided to the NRC that does not contribute to the NRC making an incorrect regulatory decision as a result of the originally submitted information. Because the applicant met the requirements for a waiver and the waiver would have been granted if it had been requested, the performance deficiency did not cause the NRC to make an incorrect regulatory decision. The performance deficiency was screened against the Reactor Oversight Process (ROP) per the guidance of IMC 0612, Appendix B, Issue Screening. No associated ROP finding was identified and no cross-cutting aspect was assigned.
05000354/FIN-2015002-03	2015Q2	Hope Creek	Conditions Prohibited by Technical Specifications Due to Core Spray Inoperabilities	On March 31, 2015, at 1:42 p.m., the breaker for 'A' Core Spray (CS) pump failed to close during normal surveillance testing. Technical Specification (TS) 3.5.1.a was entered for one inoperable CS subsystem. The breaker was replaced and the surveillance was satisfactorily performed, and the 'A' CS subsystem was declared operable on March 31, 2015, at 8:00 p.m. PSEG performed troubleshooting which indicated that the failure in the breaker control device most likely existed since the last breaker operation on January 8, 2015, at 10:00 a.m., and vendor failure analysis concluded that the spring in the breaker control device failed due to cyclic fatigue, preventing the breaker from closing. Accordingly, PSEG determined that the A CS subsystem was inoperable for longer than the TS allowed outage time (7 days). Therefore, the condition was determined to be reportable per 10 CFR 50.73(a)(2)(i)(B) as any operation or condition prohibited by TS. During the review of this event, PSEG also determined that 'B' CS subsystem was inoperable from February 9, 2015, at 3:00 a.m., until February 10, 2015, at 3:32 p.m. (36 hours and 32 minutes) when planned maintenance was performed on the 'B' EDG. This condition was determined to be reportable per 10 CFR 50.73(a)(2)(v) as an event or condition that could have prevented the fulfillment of a safety function. The inspectors reviewed the LER and LER supplement, the associated causal analysis (ACE 70175101) and corrective actions, the completed vendor failure analysis on the breaker control device, interviewed PSEG staff, related corrective action program (CAP) notifications and walked down associated components. The inspectors found that the vendor failure analysis indicated: 1. Fatigue where the spring bends, or kinks, to form the hook that attaches the spring to the contact carrier inside the control device; and, 2. Permanent deformation, or a visible gap, in the spring coil turns. In discussing the failure analysis with PSEG, the inspectors determined that the bend, or kink, in the spring for the hook is a known high stress location and the kink introduces an additional stress riser that promotes fatigue crack initiation, which occurred over several stress cycles, suggesting that the spring failed due to an accumulation of operations of the breaker control device. PSEG engineering also indicated that the permanent deformation, or visible gap, in the spring coil turns were most likely caused during manufacturing, prior to the breaker control device assembly. Based on a review of PSEGs preventative maintenance strategy, CAP documents, ABB safety and non-safety related breaker failure history, no previous operating experience, and the fact that the cause of the inoperability, a failed spring inside the sealed breaker control device that was still within the manufacturers recommended life span, was due to a manufacturing defect that could not have been identified during inspection and testing or avoided through management controls, the inspectors determined that this type of failure was not within PSEGs ability to foresee and correct. Therefore, the inspectors determined there was no licensee performance deficiency associated with the violation of the TS 3.5.a.1 limiting conditions for operation. NRC Inspection Manual Chapter 0612, Appendix B, Issue Screening, directs disposition of 31 such issues using traditional enforcement in accordance with the Enforcement Policy. The inspectors used Enforcement Policy, Section 6.1.d.1, Reactor Operations, to evaluate the significance of this violation, and concluded that the violation was more than minor and best characterized as a Severity Level IV violation in that the issue was associated with a failure to comply with a technical specification action requirement. In reaching this conclusion, the inspectors considered that the underlying technical finding would have been evaluated as having very low safety significance (i.e. Green) under the Reactor Oversight Process using NRC IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012 because, although the issue involved the potential loss of system and/or function and therefore required a detailed risk evaluation, the calculated delta core damage frequency (CDF) was mid E-8. Because this change in CDF was less than 1E-7, no further evaluation of external events or large early release frequency was required. Because it was not reasonable for PSEG to have been able to foresee and prevent the violation, the NRC determined no performance deficiency existed. Thus, the NRC has decided to exercise enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and refrain from issuing enforcement action for the violation (EA-15-147). Further, because PSEGs action and/or inaction did not contribute to this violation, it will not be considered in the assessment process or the NRCs action matrix. This LER is closed.
05000354/FIN-2015002-04	2015Q2	Hope Creek	Operations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary Containment	On April 14, 15, 17, 20, 27 and 29, 2015, during a planned refueling outage and the reactor cavity flooded up in Mode 5, Hope Creek conducted multiple OPDRVs without an operable secondary containment. The conduct of an OPDRV without establishing secondary containment integrity is a condition prohibited by TS as defined by 10 CFR 50.73(a)(2)(i)(B). Secondary containment is required by TS 3/4.6.5.1 in Operational Condition , which is a condition during an OPDRV. The required action for this specification is to suspend OPDRV operations. In this case, the specific OPDRVs were the removal of the scram air header from service (2:00 to 5:15 p.m. on April 14, 2015), B RRP seal replacement (4:36 a.m. on April 15, 2015, through 2:55 a.m. on April 24, 2015), control rod drive replacements (2:17 p.m. on April 17, 2015, through 1:02 p.m. on April 20, 2015), Local power range monitor replacements (3:13 a.m. on April 20, 2015, through 6:40 a.m. on April 23, 2015), scram discharge volume tagging (1:14 to 1:26 p.m. on April 27, 2015), and the fill and vent for the B RRP seal (8:41 p.m. on April 29, 2015, through 6:45 a.m. on April 30, 2015). The OPDRVs were completed in accordance with PSEG procedure OP-HC-108-102, "Management of Operations with the Potential to Drain the Reactor Vessel." These OPDRVs were completed and exited at 6:45 a.m. on April 30, 2015. The NRC issued EGM 11-003, Revision 2, Enforcement Guidance Memorandum On Dispositioning Boiling Water Reactor Licensee Noncompliance With Technical Specification Containment Requirements During Operations With A Potential For Draining The Reactor Vessel, on December 13, 2013, which provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has implemented specific interim actions during any OPDRV activity. The inspectors determined that PSEGs implementation of these specific interim actions during these OPDRV activities were adequate and met the intent of EGM 11-003, Revision 2. The inspectors assessments of PSEGs implementation of these criteria during each of the multiple OPDRV activities are described below: The inspectors observed that, as required by the EGM, the OPDRV activity was logged in the control room narrative logs and that the log entry appropriately recorded the safety-related pump (A RHR) that was the standby source of makeup designated for the evolution. The inspectors noted that the reactor vessel water level was maintained at least 22 feet and 2 inches over the top of the RPV flange in compliance with the minimum water level allowed by Hope Creek TS LCO 3.9.8 applicability. The inspectors also noted that at least one safety-related pump was the standby source of makeup designated in the control room narrative logs for the evolution with the capability to inject water equal to, or greater than, the maximum potential leakage rate from the RPV for a minimum time period of 4 hours. PSEG reported that the worst case estimated time to drain the reactor cavity to the RPV flange was 26 hours, which met the EGM criteria of greater than 24 hours. The inspectors verified that the OPDRV was not conducted in Mode 4 and that PSEG did not move recently irradiated fuel during the OPDRV. The inspectors noted that PSEG had in place a contingency plan for isolating the potential leakage path. The inspectors verified that two independent means of measuring RPV water level (one alarming) were available for identifying the onset of loss of inventory events with sufficient time to close secondary containment before reactor water level reached the top of the RPV flange. TS 3.6.5.1 is applicable in Operational Conditions 1, 2, 3 and requires that secondary containment integrity shall be maintained. Operational Condition * is defined, in part, as being during OPDRV. TS 3.6.5.1, action b, states, in part, in operational condition, * suspend operations with a potential for draining the reactor vessel. Contrary to the above, between 2:00 p.m. on April 14, 2015, and 6:45 a.m. on April 30, 2015, Hope Creek Generating Station did not maintain secondary containment integrity while conducting OPDRV activities. Because the violation was identified during the discretion period described in EGM 11-003 Revision 2, the NRC is exercising enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.5, Violations Involving Special Circumstances, and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003 Revision 2, each licensee that receives discretion must submit a license amendment request within 4 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the STS to provide more clarity to the term OPDRV. The inspectors observed that PSEG is tracking the need to submit a license amendment request in its corrective action program as notification 20559547. This LER is closed.
05000272/FIN-2015008-01	2015Q2	Salem	Inadequate Maintenance Rule System Performance Criteria Selection	The 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.
05000354/FIN-2015002-01	2015Q2	Hope Creek	Failure to Identify and Correct a Condition Adverse to Quality Associated with Safety Relief Valve Inlet Piping	A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified involving PSEGs failure to promptly identify and correct a condition adverse to quality. Specifically, PSEG did not identify and initiate a Corrective Action Process Notification Report for numerous tooling marks on the Reactor Coolant System (RCS) inlet piping connecting the Safety Relief Valves (SRVs) to the primary system following periodic removal and replacement. PSEG determined that the tooling marks could have resulted in stress risers on the RCS piping, making the pipe prone to cracking, and reduced the margin to the piping minimum wall thickness. PSEGs corrective actions included blending the tooling marks on all 14 SRV inlet pipes, verifying thickness above the minimum wall value, completing ultrasonic thickness measurements and magnetic particle surface examinations of the piping, and completing an RCS operational pressure test to verify the operability and functionality of the SRV inlet piping. This finding was more than minor because it was associated with the human performance 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) protect the public from radionuclide releases caused by accidents or events. The inspectors used IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, which states in the Barrier Integrity section that for all non-pressurized thermal shock issues, the inspectors should evaluate the issue under the initiating events cornerstone (Exhibit 1). Using Exhibit 1 for Transient Initiators, the inspectors determined that the finding was of very low safety significance (Green), because after a reasonable assessment of the degradation; the condition did not adversely impact RCS leakage or functionality of available Loss of Coolant Accident (LOCA) mitigation capabilities. Specifically, the SRV inlet piping safety-related function, relied upon for accident mitigation and pressure relief, remained operable. The inspectors determined this finding has a cross-cutting aspect in Human Performance, Work Management, because the organization did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority. The work process did not include the identification of risk (risk of the torque tool damaging the SRV pipe, and the failure to identify damage during inspections when performing maintenance on the SRVs) commensurate to the work and the need for coordination with different groups or job activities.

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