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	Quarter	Site	Title	Description
05000317/FIN-2015003-03	2015Q3	Calvert Cliffs	Licensee-Identified Violation	TS 5.4.1.a states, in part, that written procedures shall be established and maintained covering the applicable procedures recommended in RG 1.33, Revision 2, Appendix A, February 1978, of which Section 9 specifies procedures for performing maintenance. The vendor technical manual specifies the need to conduct routine lube oil sample analysis and Exelon procedure MA-AA-716-006, Control of Lubricants Program, Revision 11, directs the performance of sampling in accordance with specific site approved procedures. Contrary to the above, following the June 17, 2015, failure of the 1A EDG surveillance test, Exelon identified that appropriate procedural guidance did not exist for the processing of 1A EDG engine lube oil samples. On June 17, 2015, during surveillance testing of the 1A EDG, Exelon secured the engine due to high lube oil filter differential pressure. The engine lube oil filters were determined to be clogged due to engine coolant contamination of the engine lube oil system caused by leakage past O-rings on one engine cylinder piston. Investigation determined that monthly engine lube oil samples were not provided to the vendor for analysis from February May 2015 due to the extended absence of the regular lubrication specialist and lack of procedural guidance for processing of lube oil samples once they were obtained. Subsequent analysis of these samples revealed that the engine lube oil had elevated potassium levels which is indicative of lube oil contamination by engine coolant. The inspectors evaluated the issue using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings AtPower, which determined that the finding was of very low safety significance (Green) because the safety function was not lost and the 1A EDG was not considered inoperable for greater than its TS limiting condition for operation allowed outage time. The inspectors determined that Exelon correctly evaluated the finding and developed appropriate corrective action as documented in Exelons CAP as IR02517365.
05000317/FIN-2015003-02	2015Q3	Calvert Cliffs	Licensee-Identified Violation	10 CFR 74.19 (c), Recordkeeping, states, in part that, each licensee who is authorized to possess special nuclear material (SNM), shall conduct a physical inventory of all SNM in its possession, under license, at intervals not to exceed 12 months. Contrary to this, on May 22, 2015, Exelon identified that the 2014 SNM inventory had not been completed by the end of August 2014, as was required since the 2013 SNM inventory was completed in August 2013. The 2014 SNM inventory was started on August 26, 2014, and was completed on October 6, 2014. Exelon subsequently self-identified that inventories of nine locations had exceeded 12 months although all SNM was accounted for by October 6, 2014. The inspectors determined that this finding was of very low safety significance (Green), because the finding did not represent an actual loss of SNM and the performance of an inventory in June 2015, as part of the corrective actions, was completed satisfactorily. The inspectors determined that Exelon correctly evaluated the finding and developed appropriate corrective action as documented in Exelons CAP as IR02504484.
05000317/FIN-2015003-01	2015Q3	Calvert Cliffs	Failure to Establish and Maintain Procedures for the Operation of the Diesel Fuel Oil System	The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1.a for Exelons failure to adequately establish and maintain procedures as required by Regulatory Guide (RG) 1.33, Appendix A, Section 3, Procedures for Startup, Operation, and Shutdown of Safety-Related PWR Systems. The inspectors determined that Exelons failure to adequately establish and maintain a procedure for the operation of the diesel fuel oil (DFO) supply system was a performance deficiency. Exelon entered this issue into their corrective action program (CAP) as issue report (IR) 02541107. Exelons immediate corrective actions included halting of opening of 0-DFO-108, 21 Fuel Oil Storage Tank (FOST) to Auxiliary Boilers Isolation, and initiating an evaluation to determine the seismic adequacy of the piping downstream of 0-DFO-108. The inspectors reviewed IMC 0612, Appendix B, Issue Screening, and determined the issue is more than minor because it adversely affected the protection against external factors 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. Specifically, the failure to adequately establish and maintain procedure Operating Instruction (OI)-21D, Fuel Oil Storage and Supply, Revision 10, for the operation of the DFO supply system resulted in the alignment of the safety-related 21 FOST to nonsafety-related/non-seismically qualified piping thus rendering the 21 FOST inoperable. In accordance with IMC 0609, Attachment 4, Initial Characterization of Findings, issued on June 19, 2012, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, and Exhibit 4, External Events Screening Questions, issued on June 19, 2012, the inspectors determined that a detailed risk evaluation was necessary to disposition the significance of this finding because the loss of the 21 FOST would degrade two or more trains of a multi-train system or function. A regional Senior Reactor Analyst (SRA) performed a detailed risk evaluation and determined the finding to be of very low safety significance (Green). The inspectors determined that the finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Operating Experience, because Exelon failed to adequately evaluate relevant external operating experience. Specifically, Exelon failed to evaluate for systems where non-seismically qualified piping could be connected to safety-related tanks as was described in Information Notice (IN) 2012-01, Seismic Considerations Principally Issues Involving Tanks. (P.5).
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.
05000293/FIN-2015002-01	2015Q2	Pilgrim	Ineffective Corrective Actions leads to Loss of Decay Heat Removal	Green. A self-revealing Green finding was identified when residual heat removal (RHR) pump B experienced cavitation during refueling and maintenance outage (RFO) 20 that was a result of inadequate corrective actions associated with equipment used to determine flow rate. Specifically, prior to placing augmented fuel pool cooling (AFPC) mode in service on April 26, 2015, Entergy did not ensure that the temporary flow transmitter was properly setup and calibrated because corrective actions from 2011 were not adequate to ensure proper setup in the future. As a result, when operators went to raise flow in accordance with their procedural requirement, RHR pump B experienced cavitation and operators secured the pump because the flow transmitter was inaccurately reading low. Entergys immediate corrective actions included entering the issue into the corrective action program (CAP) as condition report (CR)-2015-3724, re-calibrating and setting up the ultrasonic flow meter, and establishing a second ultrasonic flow meter to ensure proper flow. Inspectors performed a walkdown to ensure proper operation of the ultrasonic flow meters, and confirmed similar readings between the two flow meters on April 27, 2015. The finding is more than minor because it is associated with the equipment 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, the B RHR pump was secured from AFPC mode 2 on April 26, 2015 when the installed ultrasonic flow meter did not read properly, leading to operation of the B RHR pump outside of flow limits specified in procedure 2.2.85.2 and cavitation of the pump. This finding was evaluated in accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2, Section C.6 of IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process Phase 1 Initial Screening and Characterization of Findings, the inspectors determined that this finding is of very low safety significance (Green) because while the performance deficiency resulted in the B RHR pump being secured due to cavitation, it did occur when the refuel canal/cavity was flooded and did not increase the likelihood of a fire or internal/external flood that could cause an shutdown initiating event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because Entergy staff did not thoroughly evaluate the issues associated with the ultrasonic flow meter in 2011 and 2013 to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, Entergys corrective action process did not thoroughly evaluate and develop appropriate corrective actions for CR-2011-1847 and CR-2013-2857 to ensure the cause was addressed to prevent challenges using ultrasonic flow meters during AFPC for both mode one and mode two.
05000293/FIN-2015002-02	2015Q2	Pilgrim	Inadequate Operability Determination for the B EDG Results in TS Violation	The inspectors identified a Green NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when Entergy staff performed an inadequate operability determination that assessed the X-107B emergency diesel generator (EDG) following cylinder head leakage indications during pre-start checks for a planned monthly operability run. Specifically, after engine coolant had been observed spraying from one of the open cylinder test cocks during X-107B EDG pre-start checks, operators determined that the EDG remained operable because the volume of leakage that had been observed would not have precluded a successful start of the engine. Operators did not consider that potential sources of leakage, such as a crack in the cylinder or cylinder head, could reasonably worsen during operation, such that the engine would not be able to complete its 30-day mission time, and therefore should be declared inoperable. Entergys immediate corrective actions included replacement of the X-107B EDG 9L cylinder head and sending out the damaged cylinder head for analysis by a vendor. The completion of the analysis by the vendor is being tracked by CR-2015-2109. The finding was more than minor because it was 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. Specifically, Entergy staff inadequately determined that the X-107B EDG was operable, which resulted in the operability of the X-107A EDG not being verified, either through determination that it was not inoperable due to a common cause failure or performing TS SR 4.5.F.1 in its entirety. This finding was evaluated 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 determined that this finding was of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of Human Performance, Conservative Bias, because Entergy staff did not use decision making practices that emphasized prudent choices over those that are simply allowed. Specifically, Entergy staffs operability determination for the X-107B EDG was based on the conclusion that the as found condition would not have caused the engine to be inoperable because it would not have created a hydraulic lock; they did not consider that the condition would likely worsen during EDG operation, nor did their operability determination consider EDG mission time
05000293/FIN-2015002-03	2015Q2	Pilgrim	Failure to Conduct Operations to Minimize the Introduction of Residual Radioactivity to the Site	The inspectors identified a Green NCV of 10 CFR 20.1406(c) in that Entergy did not conduct operations to minimize the introduction of residual radioactivity on site. Specifically, Entergy did not take action to reduce residual radioactive waste from the site in a timely manner over 14 years for areas in the Radwaste building. Entergy entered this issue into the CAP as CR-2015-5745 with actions to characterize and evaluate the adverse conditions identified by the inspector. The finding was more than minor because it is associated with the program and process attribute of the Public Radiation Safety cornerstone and affected the cornerstone objective to ensure the licensees ability to prevent inadvertent release and/or loss of control of licensed material to an unrestricted area. In accordance with IMC 0609, Appendix D, Public Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance (Green) because Entergy had an issue involving radioactive material control, but did not involve: (1) transportation; or (2) public exposure in excess of 0.005 Rem. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, in that Entergy did not adequately address the radioactive waste in a 14 year time period.
05000293/FIN-2015002-04	2015Q2	Pilgrim	Failure to Properly Ship Category 2 Radioactive Material Quantity of Concern	The inspectors identified a Green NCV of 10 CFR 71.5, Transportation of Licensed Material, and 49 CFR 172, Subpart I, Safety and Security Plans. Specifically, Entergy shipped a Category 2 Radioactive Material in Quantities of Concern (RAM-QC) on public highways to a waste processor without adhering to a transportation security plan. Prior to shipment, Entergys staff failed to recognize that the quantity of radioactive material met the definition RAM-QC. Entergy entered the issue into their CAP as CR-2015-05746 to address changes in Department of Transportation requirements. The finding was more than minor because it is associated with the program and process attribute of the Public Radiation Safety cornerstone and affected the cornerstone objective to ensure the safe transport of radioactive material on public highways in accordance with regulations. The finding was determined to be of very low safety significance (Green) because Entergy 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 nonconformance; or (5) a failure to make notifications or provide emergency information. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification, in that the licensee did not have a low threshold for identifying issues. Specifically, the security transportation plan requirements became effective in March 2003, had not been effectively identified by Entergy.
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.
05000293/FIN-2015002-05	2015Q2	Pilgrim	Failure to Submit an LER	The inspectors identified a Severity Level IV NCV because Entergy personnel did not provide a written report to the NRC within 60 days after discovery of the event as required by 10 CFR 50.73(a)(2)(i)(B) for a condition which was prohibited by TS 3.5.E, Automatic Depressurization System (ADS). Specifically, on January 27, 2015, Pilgrim experienced a loss of offsite power and reactor scram during a winter storm. While operators performed a reactor cooldown with manual operation of safety relief valves (SRVs), the 3C SRV twice failed to open upon demand by the operations crew. Entergy staff initiated CR-PNP-2015-0561 to document SRV 3Cs failure to open, and the valve was immediately declared inoperable. The inspectors determined that the improper operation of SRV 3C was reportable in accordance with 10 CFR 50.73(a)(2)(i)(B). Entergy has captured this issue in CR-2015-6191. The inspectors determined that Entergys failure to submit an event notification in accordance with 10 CFR 50.73 within the required time was a performance deficiency that was reasonably within Entergys ability to forsee and correct, and should have been prevented. Because the issue had the potential to affect the NRCs ability to perform its regulatory function, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the Enforcement Policy, the inspectors determined that the violation was a Severity Level IV (a failure of a licensee to make a report required by 10 CFR 50.72 or 10 CFR 50.73) 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 to this violation in accordance with IMC 0612, Appendix B.
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.
05000247/FIN-2015001-01	2015Q1	Indian Point	Failure to Control Transient Combustibles in Accordance with the Approved Fire Protection Program	The inspectors identified an NCV of the license condition 2.K. when Entergy failed to properly control transient combustibles within the Unit 2 control room envelope in accordance with the approved fire protection program (FPP). The inspectors identified transient combustible material in excess of the specified limits that were unattended and without a transient combustible evaluation (TCE). The inspectors notified Entergy personnel of the deficiency, the transient combustibles were promptly removed, and the issue was entered into the corrective action program (CAP) as condition report (CR)-IP2-2015-1058. The inspectors determined that the failure to properly control transient combustible material in accordance with the approved FPP was a performance deficiency. This finding was determined to be more than minor because it is associated with the protection against external factors attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. In accordance with IMC 0609.04, Phase 1 Initial Characterization of Findings, the inspectors determined that the finding affected the administrative controls for transient combustible materials. The inspectors conducted a Phase 1 SDP screening using IMC 0609, Appendix F, Fire Protection Significance Determination Process, and assigned the finding to the Fire Prevention and Administrative Controls category; in that, it affected Entergys combustible materials control. The finding was determined to be Green, or very low safety significance, after IMC 0609, Appendix F. question 1.3.1, Is the reactor able to reach and maintain safe shutdown (hot or cold) condition, was answered yes. The inspectors assumed that any fire in the area associated with the combustibles observed would be promptly extinguished using readily available extinguishing equipment and that no safety-related equipment would be disabled. The inspectors determined that this finding had a Human Performance, Procedure Adherence, cross-cutting aspect because Entergy failed to properly control transient combustible material in accordance with the approved FPP when the allowed limits were exceeded without an evaluation (H.8).
05000247/FIN-2015001-02	2015Q1	Indian Point	Untimely Corrective Actions for Degraded Fire Protection Piping Results in Piping Break	The inspectors identified a self-revealing NCV of license condition 2.K. because Entergy did not take adequate corrective actions for degraded fire protection piping in the Unit 1 turbine building. This issue contributed to excessive leakage and failure of a 10-inch high-pressure fire protection spool piece. Depressurization and isolation of this leak resulted in loss of high-pressure fire water to Unit 2 until compensatory measures could be established after about two hours. Entergy entered this issue into their CAP as CR-IP2-2014-6668, repaired the piping section, and is prioritizing repairs to other sections of degraded piping. This finding is greater than minor because it adversely affected the Mitigating Systems cornerstone objective to ensure the availability and reliability of systems (fire protection system) that provide protection against external events (fire) when all the fire protection pumps were secured to isolate the failed piping. This finding was evaluated using IMC 0609, Appendix F, Fire Protection Significance Determination Process, question 1.4.7, Fire Water Supply. It was found to be of very low safety significance because at least 50 percent of the fire water capacity (5500 gpm) remained available when the leak occurred. The inspectors determined that this finding had a cross-cutting aspect in Problem Identification and Resolution, Resolution, because Entergy did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance, resulting in the piping break (P.3).
05000286/FIN-2015001-03	2015Q1	Indian Point	Licensee-Identified Violation	TS LCO 3.4.13, RCS Operation Leakage, states, in part, that RCS operational leakage shall be limited to no pressure boundary leakage. Contrary to the above, on March 14, 2013, during a scheduled RFO boric acid program walk down inspection, Entergy identified a through-wall defect and therefore a RCPB leak on a fillet weld which attaches the E-11 in-core guide tube to the seal table path. Corrective actions included a VT-2 visual examination of the remaining seal table penetrations to verify that no additional through wall leaks were present. Additionally, the leaking guide tube was removed from service by cutting the tube below the leaking area and installing a welded plug to form a new RCPB. No performance deficiency was identified because it was not reasonable for Entergy to foresee and prevent the pressure boundary leak. Since this violation has no performance deficiency, traditional enforcement applies. The inspectors evaluated the significance of the issue using traditional enforcement and determined it was a SL IV NCV of TS 3.4.13 in accordance with the NRC Enforcement Policy, Section 6.1.d. This issue was entered into Entergys CAP as CR-IP3-2013-01556 and a report was made to the NRC in LER 05000286/2013-004-00.
05000333/FIN-2014004-02	2014Q3	FitzPatrick	Licensee-Identified Violation	TS 3.3.5.2, Reactor Core Isolation Cooling System Instrumentation, requires that the RCIC system instrumentation for all four channels of low CST water level be operable while in Modes 1, 2, or 3 with reactor steam dome pressure greater than 150 psig. With one level switch inoperable, Condition D requires that the channel be placed in trip. When this condition is not met, Condition E requires that RCIC be declared inoperable. TS 3.5.3, RCIC System, further requires that RCIC be restored to operable status within 14 days or be in Mode 3. Contrary to TS 3.3.5.2, with one RCIC CST level switch, 13LS-76B, inoperable from September 17, 2013 until November 4, 2013, Entergy did not place the channel in trip or declare RCIC inoperable, or place the reactor in Mode 3 per TS 3.5.3. The cause of the inoperability was the failure to align the microswitch in accordance with vendor manual instructions when the switch was replaced in September. Entergy entered this issue into the CAP as CR-JAF-2013-5576. The inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, because the finding was not a design or qualification deficiency, did not involve the 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 screen to potentially risk significant due to a seismic, flooding, or severe weather initiating event.
05000289/FIN-2014004-01	2014Q3	Three Mile Island	Inadequate Evacuation Time Estimate Submittals	The inspectors identified an NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.54(q)(2), 10 CFR 50.47(b)(10), and 10 CFR 50, Appendix E, Section IV.4, for failing to maintain the effectiveness of the Three Mile Island Nuclear Station (TMI) emergency plan as a result of failing to provide the station evacuation time estimate (ETE) to the responsible offsite response organizations (OROs) by the required date. Upon identification, Exelon entered this issue into its corrective action program (CAP) as issue reports (IRs) 1525923 and 1578649. Exelon submitted a third ETE for TMI on April 4, 2014, and the NRCs review of that ETE is documented in section 1EP4 of this report. The finding is more than minor because it is associated with the Emergency Preparedness cornerstone attribute of procedure quality and adversely affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The ETE is an input into the development of protective action strategies prior to an accident and to the protective action recommendation decision making process during an accident. Inadequate ETEs had the potential to reduce the effectiveness of public protective actions implemented by the OROs. The finding is determined to be of very low safety significance (Green) because it is a failure to comply with a non-risk significant portion of 10 CFR 50.47(b)(10). The cause of the finding is related to cross-cutting aspect of Human Performance, Documentation, because Exelon did not appropriately create and maintain complete, accurate and, up-to date documentation (H.7).
05000333/FIN-2014004-01	2014Q3	FitzPatrick	Failure to Notify NRC Within 30 Days of Medical Changes for Licensed Operators	The inspectors identified a Severity Level (SL) IV NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.74, Notification of Change in Operator or Senior Operator Status. Specifically, on three occasions, Entergy staff did not notify the NRC of a change in the medical status of a licensed operator within 30 days of learning of the diagnosis. These issues were entered into the corrective action program (CAP) as condition report (CR)-JAF-2014-02227 and CR-JAF-2014-02304. The inspectors determined that Entergys failure to notify the NRC of licensed operator medical status changes as described above within 30 days was a performance deficiency that was within Entergys ability to foresee and correct and should have been prevented. Because the issue had the potential to affect the NRCs ability to perform its regulatory function, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.4.d.1(b) from the NRC Enforcement Policy, the inspectors determined that the violation was a Severity Level IV (more than minor concern that resulted in no or relatively inappreciable potential safety or security consequence) violation because Entergy staff did not communicate licensed operator permanent medical status changes within the 30 day reporting requirement for three licensed operators. In accordance with IMC 0612, Power Reactor Inspection Reports, traditional enforcement issues are not assigned cross-cutting aspects.
05000387/FIN-2014003-03	2014Q2	Susquehanna	Implementation of Enforcement Guidance Memorandum (EGM) 11-003, Revision 2	From April 16 through May 23, PPL performed OPDRVs without establishing secondary containment integrity. An OPDRV is an activity that could result in the draining or siphoning of the RPV water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable and is applicable during OPDRVs. The required action for this specification if secondary containment is inoperable in this condition of applicability is to initiate actions to suspend OPDRVs immediately. Therefore, failing to maintain secondary containment operability during 31 Enclosure OPDRVs without initiating actions to suspend the operation was considered a condition prohibited by TSs as defined by 10 CFR Part 50.73(a)(2)(i)(B). TS 3.6.4.1 is applicable during OPDRVs and requires that secondary containment be operable. TS 3.6.4.1, action C.3, requires operators to initiate actions to suspend OPDRVs immediately upon discovery that secondary containment is inoperable. Contrary to the above, from April 16, 2014 through May 23, 2014, PPL did not maintain secondary containment operable while performing OPDRVs. Because the violation was identified during the discretion period described in EGM 11-003, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation. In accordance with EGM 11-003, each licensee that receives discretion must submit a license amendment request within 12 months of the NRC staffs publication in the Federal Register of the notice of availability for a generic change to the Standard TSs to provide more clarity to the term OPDRV. The inspectors observed that PPL is tracking the need to submit a license amendment request in its CAP as CR 1707662. This LER is closed.
05000387/FIN-2014003-02	2014Q2	Susquehanna	Licensee-Identified Violation	10 CFR Part 20.1701 requires, in part, that the licensee use, to the extent practicable, process or engineering controls to control the concentration of radioactive materials in air. Contrary to this requirement, PPL did not use, to the extent practicable, process or engineering controls during pipe weld preparation on the RWCU piping on April 27, 2014, due to miscommunication between the workers and radiation protection. A radiation protection technician monitoring a continuous air monitor noticed increasing airborne radioactivity and subsequently stopped the work. This failure to use, to the extent practicable, process or engineering controls led to a worker receiving an unplanned, unintended uptake of approximately 11 millilrem. This violation has been entered into PPLs CAP as CR-2014-16603. The inspectors determined the finding was of very low safety significance (Green) because it did not involve: (1) ALARA occupational collective exposure planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose.
05000286/FIN-2014007-01	2014Q2	Indian Point	Deficient Design Control Results in Non-Qualified Component Installed in Harsh Environment for Unit 3, BFD-FCV-406B Actuator	The team identified a Green non-cited violation of Title 10 Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, because Entergy did not ensure the control air pressure regulator (IA-PCV-1548) for Unit 3 auxiliary boiler feedwater (ABFW) flow control valve BFD-FCV-406B was suited and designed to perform its safety-related function. Specifically, IA-PCV-1548 was not designed or qualified for use in the harsh environment area where it was located. Immediate corrective actions included evaluation of IA-PCV-1582 and BFD-FCV-406B to verify component operability. The issue was entered into the corrective action program as condition report IP3-2014-1364, to further evaluate both the extent-ofcondition and the stations processes for maintaining configuration control over mechanical components installed in harsh environment areas. The finding was more than minor because the finding was associated with the Design Control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of assuring the reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Additionally, the issue was similar to example 3.j in Appendix E of Inspection Manual Chapter 0612, in that the design control issue resulted in a reasonable doubt of operability. The team determined the finding was of very low safety significance (Green) because it was a design or qualification deficiency confirmed not to result in a loss of operability. The finding had a cross-cutting aspect in the area of Human Performance, Design Margin (H.6), because Entergy did not maintain the operational temperature design margin for the control air pressure regulator to the ABFW flow control valve. The margin between the ABFW pump room peak environmental temperature and the design/qualified temperature of IA-PCV-1582 was not carefully guarded and changed only through a systematic and rigorous process.
05000244/FIN-2014003-02	2014Q2	Ginna	Licensee-Identified Violation	TS 3.8.3, Diesel Fuel Oil, requires that EDGs and required support systems to be operable. TS 3.8.3 LCO condition B, one or more required EDGs with stored fuel oil total particulates not within limit, requires that the fuel oil total particulates be returned within limit within 7 days. TS 5.5.12, Diesel Fuel Oil Testing Program, established acceptance criteria for meeting the requirements of LCO 3.8.3 condition B. Contrary to the above, from January 7 until January 23, 2014, diesel fuel oil sample results were above the limit for particulates established by TS 5.5.12 thus rendering the B EDG inoperable for greater than its allowed outage time. Exelon entered the issue into their CAP as CR-2014-000303, conducted an apparent cause evaluation, and properly reported the issue to the NRC as LER 05000244/2014-001- 00, Total Particulate Concentration in B Emergency Diesel Generator Fuel Oil Storage Tank Exceeded Acceptance Criteria Cause Attributed to Contamination from Using a Temporary Fuel Oil Storage Tank. The inspectors determined the finding was of very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating System Screening Questions, issued June 19, 2012, since the finding did not represent a loss of system and/or function.
05000387/FIN-2014003-01	2014Q2	Susquehanna	Failure to Identify Conditions Adverse to Quality due to Untimely Actions to Address Extent of Condition	An 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 for PPL's failure to identify conditions adverse to quality by not implementing timely actions to address the extent of a previously identified inoperable condition. Specifically, when a reactor core isolation cooling (RCIC) turbine exhaust line vacuum breaker failed its inservice test, PPL did not take timely actions in accordance with NDAP-QA-0702, Action Request and Condition Report Process, to test other valves that could be susceptible to the failure mechanism and, therefore, did not identify conditions adverse to quality in similar valves in a timely manner. PPL entered the issue into the corrective action program (CAP) as condition report (CR) 2014-17151 and tested all other susceptible valves. Additionally, degraded conditions that were identified were corrected prior to restoring the systems to service. The finding was determined to be more than minor because it was associated with the structures, systems, and component (SSC) and barrier performance attribute of the Barrier Integrity cornerstone and affected its objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Inspectors determined the risk significance was bounded by the failure of the high pressure coolant injection (HPCI) turbine exhaust line vacuum breaker, which was stuck in a partially opened state. With the valve stuck in this state, failure of the redundant valve would have resulted in HPCI exhaust steam relieving directly to the suppression chamber air space affecting containment performance. The inspectors assessed the finding in accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, and determined the finding to be of very low safety significance (Green) because it did not represent a degradation of the barrier function of the control room, did not represent an actual open pathway in the physical integrity of reactor containment, and did not involve the actual reduction in function of hydrogen igniters in containment. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because PPL did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, despite properly identifying appropriate corrective actions while evaluating the extent of a condition adverse to quality, PPL failed to implement those actions in a timely manner resulting in the failure to identify and correct conditions adverse to quality in three similar valves.
05000244/FIN-2014003-01	2014Q2	Ginna	Inadequate Procedure Implementation Results in	A self-revealing Green NCV of Technical Specification (TS) 5.4.1, Procedures, was identified for failure to perform maintenance as required by Exelon Generation (Exelon) procedure STP-I-9.1.16, Undervoltage Protection 480 Volt Safeguard Bus 16, Revision 01001. Specifically, while performing step 6.4.2.1 to place the BX1/16 relay toggle switch in the trip position, an incorrect switch manipulation by an instrumentation and control (I&C) technician resulted in an engineered safety feature (ESF) actuation, which included the automatic start of the B emergency diesel generator (EDG) and the de-energization of a safety-related bus. Immediate corrective actions included restoring Bus 16 to its normal power supply and entering this issue into the corrective action program (CAP) as condition report (CR)-2014-002741. The finding was more than minor, because it is 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, due to a personnel error, an incorrect switch was manipulated during Bus 16 undervoltage testing. This resulted in the automatic start of the B EDG, the de-energization of Bus 16, and the transition of the outage defensein- depth from a Green to a Yellow risk condition. The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Initial Characterization of Findings. This attachment directed the inspectors to evaluate the finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process. However, IMC 0609, Appendix G, directed the inspectors to contact the senior risk analyst for assistance as it does not apply when there are no fuel assemblies in the reactor vessel. The senior risk analyst directed the inspectors to evaluate the finding using Appendix M, Significance Determination Process Using Qualitative Criteria, which directed the inspectors to consider a bounding case. For this instance, if the bus had not been recovered with the fuel in the spent fuel pool (SFP), the only significant system lost would have been the redundant SFP cooling system. Therefore, the inspectors determined the finding to be of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Avoid Complacency, because Exelon personnel did not recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Specifically, Exelon personnel did not implement appropriate error reduction tools or consider the potential undesired consequence of an ESF actuation before performing work.
05000318/FIN-2014002-02	2014Q1	Calvert Cliffs	Inadequate Compensatory Actions for Out of Service Letdown Radiation Monitor	The inspectors identified an NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.54, Conditions of Licenses, paragraph (q)(2), because CENG did not maintain the Emergency Plan to adequately meet the standards in 50.47(b)(4). Specifically, following the removal of the Unit 2 letdown radiation monitor for maintenance on October 28, 2013, CENG did not establish adequate compensatory measures to ensure that a fuel clad degradation emergency action level (EAL) could be assessed in a timely manner as discussed in the Emergency Plan. This could have resulted in an unnecessary delay in the recognition of a Notice of an Unusual Event (NOUE) EAL declaration for elevated coolant reactivity. Immediate corrective actions included restoring the proper valve lineup, entering this issue into their CAP, and implementing compensatory actions, which included the use of a portable radiation monitor with appropriate alarm setpoints to initiate action to sample the RCS to determine if the specified reactor coolant activity limits are exceeded. Planned corrective actions include restoration of the Unit 2 letdown radiation monitor. This finding is more than minor because it was associated with the emergency response organization performance attribute of the Emergency Preparedness (EP) cornerstone and affected the cornerstones objective to ensure that CENG is capable of implementing adequate measures to protect public health and safety in the event of a radiological emergency. Specifically, the failure to establish compensatory actions beyond the normal RCS sampling frequency could have resulted in exceeding an NOUE EAL threshold for a degraded fuel clad and the condition not becoming known until the next normal RCS sample or upon further fuel clad degradation requiring escalation under other EALs. In accordance with IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012, and IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, issued February 24, 2012, the inspectors determined the finding is of very low safety significance (Green). Utilizing IMC 0609, Appendix B, the inspectors determined that the finding is associated with an aspect of the Emergency Plan related to the EAL Classification Scheme 10 CFR 50.47(b)(4). The inspectors determined that the EAL was ineffective because it, in and of itself, no longer resulted in a timely and accurate declaration for the initiating condition. Utilizing Figure 5.4.1, the impact of the ineffective EAL is that a NOUE would be declared in a timely manner, which screens as a Green finding. In addition, the finding is similar to a Green finding in Table 5.4.1, Significance Examples 50.47(b)(4), in that the EAL classification process is not capable of classifying an Alert or NOUE in a timely and accurate manner. This finding has a cross-cutting aspect in the area of Human Performance, Work Management, because CENG personnel adequately implement a work process that included the identification and management of risk commensurate to the work and the need for coordination with different groups or job activities. Specifically, Operations and Chemistry personnel did not ensure that the assigned tasks were adequate to compensate for the increased in nuclear risk associated with having the letdown radiation monitor out of service (H.5).
05000317/FIN-2014002-03	2014Q1	Calvert Cliffs	Inadvertent Loss of RCS Inventory During Lowered Inventory Conditions	The inspectors identified a self-revealing NCV of Technical Specification (TS) 5.4.1, Procedures, for the failure of Constellation Energy Nuclear Group, LLC (CENG) personnel to adequately implement procedures associated with a local leak rate test (LLRT). Specifically, CENG personnel did not isolate the letdown line in accordance with surveillance test procedure (STP)-O-108D-1, Containment Penetration Local Leak Rate Tests, prior to draining the piping in preparation for an LLRT on chemical and volume control system (CVCS) containment isolation valves. This resulted in inadvertently draining 150 gallons from the reactor coolant system (RCS) while the reactor vessel was in a lowered inventory condition. Immediate corrective actions included entering this issue into their corrective action program (CAP), performing a prompt investigation, and conducting a safety stand-down. In addition, an apparent cause evaluation will be performed to determine any additional corrective actions. The finding is more than minor because it is associated with the configuration control attribute of the Initiating Events cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to isolate the letdown line prior to draining resulted in he loss of 150 gallons of RCS inventory and challenged the critical safety function of inventory control while in a lowered inventory condition. Operator actions were required to identify and isolate the leak to prevent further inventory loss. The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012, and IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, issued February 28, 2005, and determined that the issue screened to Green (very low safety significance). Specifically, the inspectors determined that adequate mitigating capability remained available and the finding did not represent a loss of control of RCS level due to less than 2 feet of inventory loss when not in midloop. As a result, a Phase 2 quantitative assessment was not required and the issue screened to Green. The inspectors determined that the finding has a cross-cutting aspect in the area of Human Performance, Teamwork, because CENG individuals and work groups did not adequately communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety was maintained. Specifically, a detailed shift turnover between dayshift and nightshift LLRT operators was not completed to ensure that the oncoming operators were aware of the letdown system configuration (H.4).
05000317/FIN-2014002-01	2014Q1	Calvert Cliffs	11 and 12 AFW Pumps Inoperable due to Valves Misposition	The inspectors identified a self-revealing problem consisting of NCVs of TS 3.7.3, Auxiliary Feedwater System, and TS 5.4.1, Procedures, because CENG Operations personnel did not adhere to procedures which resulted in a valve mispositioning event that inadvertently rendered the 11 and 12 turbine driven auxiliary feedwater (AFW) pumps inoperable for approximately 12 hours, a condition prohibited by TSs. Specifically, on February 7, 2014, operators did not perform draining of 11 turbine driven AFW pump steam supply drain line as stated in Operating Instruction (OI)-32A, Auxiliary Feedwater System, resulting in two main steam (MS) drain valves being left opened. With the drain valves open, an actual auxiliary feedwater actuation system (AFAS) signal would have resulted in steam blowing down into the room via the sump and causing room temperatures to exceed 130F, the maximum temperature allowed in the room to protect the pump air cooled bearings. Immediate corrective actions included restoring the proper AFW system valve lineup, entering this issue into their CAP, returning the valves to their normal position on Unit 1, and ensuring that similar valves were in the correct position on Unit 2. Planned corrective actions include conducting an apparent cause evaluation to understand the apparent and contributing causes of this event and determine additional corrective actions. The problem 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 (i.e., core damage). Specifically, Operations personnel lost configuration control of valves MS-225 and MS-228 resulting in the inoperability of the 11 and 12 AFW pumps for approximately 12 hours. The inspectors evaluated the problem using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions, issued June 19, 2012, and determined that the problem represented an actual loss of function of at least a single train for greater than its TS allowed outage time which required a detailed risk evaluation. The senior reactor analyst performed a detailed risk assessment utilizing the CCNPP Unit 1 simplified plant analysis risk model version 8.2.1 and determined that the problem is of very low safety significance (Green). Specifically, given a 12 hour exposure period with both turbine driven AFW pumps assumed to fail-to-run, the change in the internal events core damage frequency (CDF) was calculated to be in the high 10-8 range (Green). This problem has a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because CENG personnel did not follow processes, procedures, and work instructions. Specifically, after draining the 11 AFW pump mud leg, CENG plant operators did not restore MS-225 and MS-228 to their required position as stated in procedure OI-32A (H.8).
05000443/FIN-2014002-01	2014Q1	Seabrook	Scaffolding Installed with Insufficient Separation to Safety Related Equipment	The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion V, Procedures, because NextEra did not ensure adequate separation was maintained between temporary scaffolding and safety-related equipment. Specifically, six instances of scaffolding installed in the plant were identified with less than the minimum standoff distance to safety-related equipment specified in NextEra procedures and no corresponding engineering evaluation to support these deviations. NextEra entered this NCV into their CAP as AR 01933827 and assessed the six deviations for any impact on the associated safety-related systems. This performance deficiency was considered more than minor because it affected the protection against external factors attribute of the Mitigating Systems cornerstone and its objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, NextEra did not evaluate scaffolding installations when insufficient separation to safety-related equipment existed after procedural requirements were revised to a more restrictive value. Additionally, it was similar to example 4.a in IMC 0612, Appendix E, Examples of Minor Issues, which states that the issue of failing to appropriately evaluate scaffold installation as required by procedures is more than minor if the licensee routinely failed to perform engineering evaluations. The issue was evaluated in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power and determined to be of very low safety significance (Green), because it did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic event. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation, because NextEra personnel did not perform an adequate extent of condition review after revision of their erection of scaffold procedure. This performance deficiency directly contributed to multiple instances of scaffold members erected within two inches of safety-related equipment without an engineering evaluation (P.2).
05000354/FIN-2013005-06	2013Q4	Hope Creek	Operations with a Potential to Drain the Reactor Vessel (OPDRV) Without Secondary Containment	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 1700 on October 15, 2013, and 1143 on October 30, 2013, 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 1, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation.
05000352/FIN-2013005-01	2013Q4	Limerick	Failure to Properly Plan Work for Failed Airlock Door Magnetic Switch	The inspectors identified a self-revealing finding (FIN) of very low safety significance (Green) for Exelons failure to appropriately prioritize work activities associated with a degraded Unit 2 magnetic switch for a secondary containment airlock door in accordance with Exelon procedure WC-AA-106, Work Screening and Processing. This resulted in both airlock doors being opened simultaneously due to equipment degradation and resulted in a momentary loss of reactor enclosure secondary containment integrity. The failure of the station to properly prioritize the work order for the defective magnetic switch for the Unit 2 313 elevation reactor building-to-reactor building air supply room access airlock doors was a performance deficiency that was reasonably within Exelons ability to foresee and correct and could have been prevented. This was caused by not performing a site impact review of reportability clarifications made by NUREG 1022, Event Report Guidelines 10 CFR 50.72 and 50.73, Revision 3. The performance deficiency was also contrary to Exelons procedure for work screening and processing. The finding was determined to be more than minor because it was associated with the Barrier Integrity cornerstone attribute of structures, systems, and components (SSC) and Barrier Performance (doors and instrumentation) and affected the cornerstone objective of providing reasonable assurance that physical design barriers (secondary containment) protect the public from radionuclide releases caused by accidents or events. Specifically, opening two reactor building airlock doors at the same time did not maintain reasonable assurance that the secondary containment would be capable of performing its safety function in the event of a reactor accident. The finding was determined to be self-revealing because it was revealed through the receipt of an alarm in the main control room which required no active and deliberate observation by Exelon personnel. The finding was determined to be of very low safety significance (Green) in accordance with Appendix A of IMC 0609, Significance Determination Process for Findings At-Power. Specifically, the finding only represents a degradation of the radiological barrier function provided by the secondary containment airlock doors. Exelon entered the issue into the corrective action program (CAP) as Issue Report (IR) 1553563. Corrective actions performed or planned included repairing the magnetic switch, verifying that the corrective maintenance backlog did not contain any other issues involving the airlock door indicating lights, developing a periodic routine test of the airlock door indicating circuits, and performing a site impact review of the changes in NUREG 1022, Revision 3. This finding had a cross-cutting aspect in the area of Human Performance, Resources, because Exelon did not ensure that resources were available to minimize preventative maintenance deferrals and ensure maintenance and engineering backlogs were low enough to ensure that safety is maintained (H.2(a)). Specifically, Exelon deferred implementation of the work order several times over a three year period which resulted in secondary containment becoming inoperable on September 3, 2013.
05000354/FIN-2013005-01	2013Q4	Hope Creek	NCV Failure to Follow Procedure for Configuration Control Activity Adversely Affected Unidentified Leakage in the Drywell	A Green self-revealing NCV of TS 6.8.1, Procedures and Programs, was identified regarding PSEGs conduct of maintenance and component configuration control during system restoration from an operation with a potential for draining the reactor vessel (OPDRV) activity. Specifically, PSEG did not close a reactor water cleanup (RWCU) valve in accordance with the maintenance procedure during the refueling outage. This resulted in increased RCS UIL in the reactor drywell area following startup. PSEG restored the mispositioned valves, conducted an extent of condition on other valves in the drywell, completed a prompt investigation concerning the valve mispositioning, and is in the process of conducting an Apparent Cause Evaluation (ACE) on the configuration control event under Order 70161461. PSEG has also placed this issue into CAP as notification 20632003. The performance deficiency was more than minor because it was associated with the configuration control attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, which required an analysis using Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. The finding was determined to be of very low safety significance (Green) because the finding could not result in exceeding the RCS leak rate for a small loss of coolant accident (LOCA) or have likely affected other systems used to mitigate a LOCA resulting in a total loss of their function. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because PSEGs communication of human error prevention techniques did not support human performance and proper personnel work practices. Specifically, PSEG did not use adequate human performance tools and valve position verification techniques when controlling valve position for components associated with an OPDRV activity
05000354/FIN-2013005-02	2013Q4	Hope Creek	Failure to Follow the Primary Containment Closeout Procedure when Declaring the Drywell Ready for Power Operation	The inspectors identified a finding of very low safety significance (Green) and associated NCV of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for PSEGs failure to conduct primary containment (drywell) close-out activities in accordance with site procedures. Specifically, during the NRCs drywell closeout inspection, the inspectors identified several outage-related items that were not removed from the various elevations of the drywell. As a result, PSEG did not properly inspect the drywell in preparation for power operation. PSEG corrective actions included removing the items identified during the NRC drywell closeout inspection and placing the issue in the corrective action program (CAP). The performance deficiency was determined to be more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using NRC IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, dated February 28, 2005, the finding was determined to be of very low safety significance (Green) because the inspectors qualitatively determined that the finding involved adequate mitigation capability and was not an event that could be characterized as a loss of control. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because PSEG did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures. Specifically, PSEG personnel did not ensure that the drywell was ready for power operations as required by site procedures.
05000354/FIN-2013005-03	2013Q4	Hope Creek	Inadequate Evaluation of Containment Vent Functionality	The inspectors identified a finding of very low safety significance (Green) for PSEGs failure to ensure evaluations addressed identified issues in accordance with PSEG procedure LS-AA-125, Corrective Action Program. Specifically, PSEG failed to adequately assess the functionality of the containment vent following NRC identification of inadequate maintenance practices for an instrument air check valve (1KBV-300) and that design calculation H-1-KB-MDC-1007, Backup Pneumatic Supply for 1GSHV-4964 and 1GSHV-11541 Valves, did not account for leakage through the valve. PSEGs corrective actions included installation of a design change to modify instrument air piping to support leak rate testing of 1KBV-300 and addition of 1KBV-300 to its check valve monitoring and preventive maintenance program. PSEG also completed a revision to design calculation H- 1-KB-MDC-1007 to credit up to 500 standard cubic centimeter per minute (sccm) of leakage through 1KBV-300. This issue was more than minor because it was associated with the design control attribute of the mitigating systems cornerstone, and affected the cornerstones objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined the finding to be of very low safety significance (Green) in accordance with Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because: it was not a deficiency affecting the design or qualification of the containment vent; it did not represent a loss of system or function; it did not represent the loss of function for any technical specification (TS) system, train, or component beyond the allowed TS outage time; and it did not represent an actual loss of function of any non TS trains of equipment designated as highly safety-significant in accordance with PSEGs maintenance rule program. The inspectors determined that the finding had a cross cutting aspect in the Human Performance area associated with Resources, because PSEG did not ensure that personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety, specifically, those necessary for maintaining long term plant safety by maintenance of design margins. Specifically, PSEG did not ensure maintenance of design margin for the containment vent system when concerns were identified regarding its functionality. This included PSEG relying upon operation of the containment vents with hydraulic jacks that have not been operated since 1992 following their installation.
05000354/FIN-2013005-04	2013Q4	Hope Creek	Failure to Identify Adverse Trend Regarding Bailey Module and Auxiliary Card Failures	A Green self-revealing finding was identified for PSEGs failure to identify and correct an adverse trend regarding 48 Bailey module failures across multiple systems since 2005, including six Bailey module failures in the circulating water (CW) system. As a result of continued problems associated with this previously unidentified adverse trend, on June 12, 2013, the B CW pump tripped resulting in a manual scram of the reactor due to degrading condenser vacuum. PSEG corrective actions include addressing the programmatic weakness identified regarding the performance monitoring and trending program for circuit card failures by amending the Bailey Module Reliability Program to include fuse module and auxiliary card failures. The finding was more than minor because it was associated with the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, PSEGs failure to identify and correct the adverse trend regarding Bailey module failures resulted in a manual scram from 100 percent power due to the trip of the B CW pump concurrent with the B CW discharge valve being gagged in the open position. The finding was determined to be of very low safety significance (Green) in accordance with Appendix A of IMC 0609, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding did not contribute to both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because PSEG did not trend and assess information from the CAP and other assessments in the aggregate to identify programmatic and common cause problems. Specifically, PSEG failed to trend or perform an aggregate assessment of Bailey module and auxiliary card failures.
05000354/FIN-2013005-05	2013Q4	Hope Creek	Licensee-Identified Violation	Technical Specification 3.6.5.1, Secondary Containment Integrity requires, in part, that secondary containment be operable during OPDRV activities in OPCON. The action statement with secondary containment inoperable in OPCON is to suspend operations with a potential to drain the reactor vessel. Contrary to the above, from 9:30 a.m. until 5:31 p.m. on October 31, 2013, Hope Creek did not comply with this TS action statement or the EGM 11-003 Revision 1 guidance, and secondary containment should have been operable. The failure to comply with this guidance resulted in a condition prohibited by TSs until the condition was corrected by restoring the automatic isolation function of the drain-down path, complying with both the EGM guidance and TSs at 5:31 p.m. on October 31, 2013. PSEG entered this issue into the CAP as notification 20631218. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, because the finding did not represent a finding that required quantitative assessment.
05000271/FIN-2013004-01	2013Q3	Vermont Yankee	Failure to Monitor the Unavailability of the B Control Rod Drive Equipment Train	The inspectors identified a NCV of Title 10 Code of Federal Regulations (10 CFR) 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, because Entergy did not monitor the performance of the B control rod drive (CRD) equipment train. Specifically, Entergy did not include seven days of unavailability for the B CRD flow control valve in the tracking database, and therefore did not initiate corrective actions when the train exceeded its unavailability criterion. Entergy initiated a condition report to document exceeding the performance criterion, entered the unavailability into the tracking database, and initiated a condition report to document the oversight in unavailability tracking. This finding is more than minor because it is associated with the human performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, since Entergy personnel did not recognize that this unavailability put the plant into a higher integrated risk category and did not recognize the plant risk impact of the flow control valves extended unavailability, no corrective actions were taken to address the maintenance practices which caused the unavailability performance criterion to be exceeded unnecessarily. 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 determined that this finding is of very low safety significance (Green) because the performance deficiency did not represent a loss of system safety function or a loss of safety function of a single train for greater than its Technical Specification allowed outage time. In addition, the failure to recognize and manage the plant risk associated with the 169 hours of unavailability of the B CRD flow control valve resulted in an incremental core damage probability of approximately 2E-10, which is less than 1E-6, and therefore also of very low safety significance. The inspectors determined that this finding has a cross-cutting aspect in the Human Performance area, Work Practices component, because Entergy personnel did not follow the maintenance rule program procedures. Specifically, operations did not log the unavailability in the maintenance rule out-of-service log and the system engineer did not review the scoping document to verify which components counted toward the train unavailability.
05000293/FIN-2013004-01	2013Q3	Pilgrim	Failure to Complete a Design Control Review for the SBO Fuel Oil Transfer System in a Timely Manner	The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Entergy did not complete a design control review for the station blackout (SBO) fuel oil transfer system in a timely manner. Entergy extended the corrective action due date out to greater than a year from the discovery of the original condition. Entergy has increased the priority of this design review and captured this issue in condition report CR-PNP-2013-6906. The performance deficiency was determined to be more than minor because it is associated with the design control attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences. The failure to complete a timely design review of a credited support system for the onsite power safety function further extends the vulnerability of the safety function if the design review determines the system is inadequate. The inspectors used IMC 0609.04, Phase 1 Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening. The finding was determined to be of very low safety significance (Green) because the finding was a design deficiency that did not result in the loss of system safety function or a loss of safety function of a single train for greater than its Technical Specification allowed outage time. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because Entergy did not take appropriate corrective actions to address a safety issue in a timely manner, commensurate with its safety significance.
05000333/FIN-2013004-01	2013Q3	FitzPatrick	Inadequate Reactor Water Recirculation Digital Flow Control Modification Post Maintenance Test Procedure Results in Unexpected Power Increase	The inspectors identified a Green self-revealing NCV of Technical Specification (TS) 5.4, Procedures, because Entergy staff did not adequately preplan the implementation of a plant modification to install a digital reactor water recirculation (RWR) flow control system during the 2012 refueling outage. Specifically, post-maintenance testing (PMT) failed to identify that a portion of the runback logic was incorrectly programmed. As a result, the RWR system was restored to operation without identifying the error. On November 8, 2012, during power ascension activities following a subsequent forced outage, the A RWR pump demand signal increased from minimum flow (approximately 30 percent) to approximately 44 percent with no operator action when feedwater flow increased above 20 percent. This resulted in an unexpected power increase of approximately 1.4 percent (37 megawatts thermal (MWth)). As immediate corrective action, control room operators reduced flow in the A RWR loop to restore it to pre-transient conditions, locked the scoop tubes for both RWR motor-generators, and placed the power ascension on hold pending further evaluation of the event. The issue was entered into the corrective action program (CAP) as condition report (CR)-JAF-2012-08042. The issue of inadequate PMT was subsequently entered into the CAP as CR-JAF-2013-05326. The finding was more than minor because it was similar to Example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, in that it resulted in a plant transient. In addition, the finding adversely affected the Initiating Events 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. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined this finding was of very low significance (Green) because the performance deficiency did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding had a cross-cutting aspect in the area of Human Performance, Resources, because FitzPatrick did not ensure that the PMT acceptance criteria specified in the engineering change (EC) package were clearly translated into PMT testing work packages to verify successful implementation of the digital RWR flow control modification.
05000271/FIN-2013004-02	2013Q3	Vermont Yankee	Failure to Maintain Radiation Exposure ALARA During Refueling Activities	A self-revealing finding was identified because Entergy inadequately planned and controlled work while performing reactor reassembly and reactor cavity decontamination activities during refueling outage (RFO) 30 resulting in excessive unintended occupational collective exposure that exceeded the planned dose exposure established by Radiation Work Permit (RWP) 2013-702. Inadequate work planning and control resulted in unplanned, unintended collective exposure due to conditions that were reasonably within Entergys ability to control. The work activity performance deficiencies resulted in the collective exposure for these activities increasing from the original estimate of 9.950 person-rem to an actual dose of 18.940 person-rem. Entergy entered the issues into their corrective action program. This finding is more than minor because it is associated with the program and process attribute of the Occupational Radiation Safety cornerstone and affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Additionally, the performance deficiency was determined to be more than minor based on a similar example (6.i) in Appendix E of IMC 0612, in that the actual collective dose exceeded 5 person-rem and exceeded the planned, intended dose by more than 50 percent. In accordance with IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspectors determined that this finding is of very low safety significance (Green) because the plant\'s current three year rolling average collective dose (142.6 person-rem/reactor years for 2010 through 2012) is less than the criteria of 240 person-rem per boiling water reactor unit. The inspectors determined that this finding has a cross-cutting aspect in the Human Performance area, Work Control component, because Entergy did not implement the planned work as intended, which involved job site activities, and impacted radiological safety.
05000271/FIN-2013004-03	2013Q3	Vermont Yankee	Operator Error Results in Diesel Generator Overload	A self-revealing NCV of Technical Specification 6.4, Procedures, was identified because Entergy overloaded the B emergency diesel generator to 130 percent of its sustained load rating. Specifically, an auxiliary operator (AO) took the speed droop switch to zero before the output breaker was opened, contrary to procedure, which resulted in the overload condition. Entergys immediate corrective actions included initiating a condition report, conducting a root cause evaluation, and performing management assessment of control room communications. This finding is more than minor because it is associated with the Human Performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the B emergency diesel generator was unavailable for an additional 24 hours in order to perform required inspections and testing to verify it was not damaged by the overload condition. 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 determined that this finding is of very low safety significance (Green) because the performance deficiency did not represent a loss of system safety function or a loss of safety function of a single train for greater than its Technical Specification allowed outage time. The inspectors determined that this finding has a cross-cutting aspect in the Human Performance area, Work Practices component, because Entergy personnel did not use human performance error prevention techniques commensurate with the risk of the assigned task such that work activities were performed safely. Specifically, self-checking, peer checking, and three-part communications were not used effectively to prevent performing procedure steps out of order.
05000352/FIN-2013003-01	2013Q2	Limerick	Failure to Identify and Correct a Condition Adverse to Quality Associated with Emergency Diesel Generator D24	The inspectors identified a Green NCV of 10 Code of Federal Regulation (CFR) 50, Appendix B, Criterion XVI, Corrective Action , because Exelon personnel did not identify and correct a condition adverse to quality associated with emergency diesel generator (EDG) D24 lubricating oil pipe fitting supports. This resulted in EDG D24 being in a degraded condition from November 2012 until the condition was corrected in May 2013. Exelon personnel entered this issue into the corrective action program (CAP) as issue reports (IRs) 1507365, 1509125, 1511869, 1512745, 1526780, and 1528088. The failure of Exelon personnel to identify and correct the degraded instrument line pipe fitting support and insert on EDG D24s lubricating oil supply pressure sensing line following the failure of a pipe fitting on November 13, 2012 is a performance deficiency that was reasonably within Exelons ability to foresee and correct. The IR written to document the issue (IR 1439284) was inappropriately classified as not a critical component failure. This resulted in the issue receiving a lower level of investigation (work group evaluation versus an apparent cause or root cause evaluation). This NRC-identified finding was more than minor because it is associated with equipment performance and affected the Mitigating System cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating event to prevent undesirable consequences. The inspectors evaluated the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power, to IMC 0609, Significance Determination Process. Exelon personnel conducted vibration testing which determined that the pipe fitting crack initiation and propagation occurred during engine slow start speed acceleration. This was based vibration data which showed two vibration peaks at speeds during the acceleration. Also, the crack did not propagate during normal speed operation based on the fact that the leak size did not increase during monthly testing on April 27, 2013. The inspectors determined this finding did not represent an actual loss of function of a single train for greater than it Technical Specification Allowed Outage Time. Therefore, the inspectors determined the finding to be of very low safety significance.
05000352/FIN-2013003-02	2013Q2	Limerick	Failure to adhere to radiation protection procedures for evacuation of the Unit 2 upper drywell in preparation for irradiated component moves	The inspectors identified a self-revealing finding of very low safety significance associated with failure to comply with TS 6.8, Procedures and Programs. Specifically, the inspectors identified Exelon personnel failed to implement radiation protection procedure requirements associated with clearance of personnel from the upper levels of the Unit 2 reactor drywell in preparation for removal and movement of irradiated core component from the Unit 2 reactor vessel. Exelon personnel entered this issue into their CAP as IR 1495585. The failure to adhere to TS required radiation protection procedures for personnel exposure control related to irradiated core component movement is a performance deficiency. The performance deficiency was determined to be more than minor because it was related to the Programs and Process attribute of the Occupational Radiation Safety Cornerstone, and adversely affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation from radioactive material during routine reactor operation. Further, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern if personnel were locked in the area and irradiated hardware dropped above their work location. The finding was not subject to traditional enforcement because it was not associated with a violation that impacted the regulatory process and did not contribute to actual safety consequences. The finding was assessed using IMC 0609, Appendix C, 2 Enclosure Occupational Radiation Safety SDP, dated August 19, 2008, and was determined to be of very low safety significance (Green) because it was not related to As-Low-As-Is-Reasonably-Achievable (ALARA), did not result in an overexposure or a substantial potential for overexposure, and did not compromise the licensee\'s ability to assess dose. This finding was associated with the Work Control aspect of the Human Performance cross-cutting component. Specifically, Exelon staff did not effectively coordinate this work activity by incorporating actions to address the impact of the work on different job activities, and the need for work groups to maintain interfaces and communicate, coordinate, and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance.
05000317/FIN-2013002-01	2013Q1	Calvert Cliffs	Failure to Establish Adequate Design Control Measures for Diesel Fuel Oil Cloud Point	The inspectors identified an NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, because Constellation failed to provide design control measures to assure appropriate specifications were translated into procedures for diesel fuel oil (DFO) in the No.11 fuel oil storage tank (FOST). Specifically, Constellations cloud point maximum specification for DFO is above historical minimum temperatures recorded in the vicinity of CCNPP. The inspectors determined that Constellation did not have adequate measures in place such as a calculation, temperature monitoring, and/or procedures to assess the operability of the DFO transfer system from the No. 11 FOST for sustained outdoor temperatures below the cloud point specification temperature but above the minimum expected temperature the site may experience. Constellation entered this issue in their corrective action program (CAP). Immediate corrective actions included adding a note in Operations turnover sheet to determine No.11 FOST DFO operability if ambient temperatures dropped below 10F at the site. Planned corrective actions include performing a calculation to determine cold weather effects on the No.11 FOST. This finding is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone and affects 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). Specifically, a reasonable doubt of operability existed because the minimum temperature limits and duration of low temperature had not been established for diesel generator operability and historical low temperatures have been below the cloud point of the DFO. If left uncorrected, the performance deficiency has the potential to lead to a more significant safety concern because an inadequate cloud point specification could impact emergency diesel generator (EDG) and/or station blackout (SBO) diesel operation during an actual event during extreme low temperature conditions. The inspectors evaluated the significance of this finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding is a deficiency affecting the design or qualification of a mitigating structure, system, and component (SSC); however, the SSC maintained its operability or functionality. This finding did not have a cross-cutting aspect because the most significant contributor of the performance deficiency was not reflective of current licensee performance. Specifically, the most reasonable opportunity to identify this issue was in 1994 when Constellation reviewed this issue in response to Information Notice (IN) 94-19, Emergency Diesel Generator Vulnerability to Failure from Cold Fuel Oil.
05000317/FIN-2013002-02	2013Q1	Calvert Cliffs	Inadequate Technical Specification Surveillance Testing of the Diesel Fuel Oil Transfer System	The inspectors identified an NCV of Technical Specification (TS) surveillance requirement (SR) 3.8.1.7 because Constellation failed to adequately perform SR associated with the DFO transfer system. Specifically, since approximately 1996, Constellation did not test the 2A EDG fuel oil transfer system aligned to the No. 21 FOST. The No. 21 FOST is the credited tank in the plants licensing bases. Immediate corrective actions included entering this issue into the CAP and entering TS SR 3.0.3 for a missed surveillance which required performing a probabilistic risk assessment and performing the missed surveillance within 31 days. Corrective actions planned includes revising the quarterly EDG surveillance procedure to test the 2A EDG while aligned to the No. 21 FOST and develop and implement a testing program to periodically test each EDG aligned to the normal and alternate FOSTs. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating System cornerstone and affects 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). Specifically, Constellations testing program did not provide assurance that no obstruction exists in the DFO transfer system. If left uncorrected, this issue potentially would result in a greater safety concern in that an obstruction could exist would not be identified until an actual event requiring the 2A EDG to be aligned to the No. 21 FOST as described in the safety analysis. In accordance with IMC 0609.04, Initial Characterization of Findings and Exhibit 2 of IMC 0609, Appendix A, Significance Determination Process For Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency; did not represent a loss of system and/or function; did not represent an actual loss of function of at least 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 significance. The inspectors determined that the finding has a cross-cutting aspect in the area of Problem Identification and Resolution, CAP, because Constellation did not ensure that issues potentially impacting nuclear safety are promptly identified, fully evaluated, and that actions are taken to address safety issues in a timely manner, commensurate with their significance. Specifically, Constellation did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner associated with previously identified inadequate testing programs of risk significant equipment.
05000277/FIN-2012005-03	2012Q4	Peach Bottom	Licensee-Identified Violation	10 CFR 50.54(q) requires, in part, that a power reactor licensee follow an Emergency Plan that meets the requirements of 10 CFR 50.47(b). 10 CFR 50.47(b) requires, in part, that a standard emergency classification and action level scheme, the bases of which includes facility system and effluent parameters, is in use by Exelon. Contrary to the above, between December 2008 and November 2012, the standard emergency classification and action level scheme associated with radiological effluents at PBAPS was not updated to reflect the changes in X/Q dispersion factor that occurred during the December 2008 ODCM revision. Consequently, the effluent monitor emergency classification and action level thresholds for the reactor building exhaust vent stack were non-conservative until this condition was identified and promptly corrected by PBAPS in November 2012. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, Table 5.4-1, because the emergency action level (EAL) classification process would not be capable of classifying an Unusual Event (UE) within 15 minutes, but would still be capable of declaring all other EALs within 15 minutes. Because this finding is of very low safety significance, and has been entered into Exelon\'s CAP under IR 1439489, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000277/FIN-2012005-02	2012Q4	Peach Bottom	Licensee-Identified Violation	TS LCO 3.3.1.1, Condition B, requires that with one RPS instrument function with one or more required channels inoperable, action shall be taken within six hours to place a channel or trip system in a trippedcondition within six hours. Additionally, TS LCO 3.3.4.2, Condition A, requires that with one or more required end of cycle (EOC) recirculation pump trip (RPT) instrument channels inoperable, action be taken to place the channel in a tripped condition within 72 hours if the channel is not restored to operable status. Contrary to the above, PBAPS determined that the A and B channels of the Unit 2 turbine control valve (TCV) fast closure pressure sensing instruments were inoperable for a period of time greater than allowed by TS. Specifically, the as-found trip setpoints of the A and B sensing instruments were identified to be below the allowable trip setting during surveillance testing on October 1, 2012. PBAPS Unit 2 was defueled to support the 19th RFO during performance of the ST. Both instruments were replaced and calibrated to within acceptable limits prior to reactor startup. The inspectors determined that the finding was of very low safety significance (Green) in accordance with Section C of Exhibit 2 in Appendix A of IMC 0609, The Significance Determination Process for Findings at Power, because RPS system trip capability was maintained with the C and D instrument channels. Because this finding is of very low safety significance and has been entered into Exelon\'s CAP under IR 1421069, this violation is being treated as a Green NCV consistent with the NRC Enforcement Policy.
05000277/FIN-2012005-01	2012Q4	Peach Bottom	Licensee-Identified Violation	TS 3.4.3 Limiting Condition for Operation (LCO) requires that 11 of 13 SRVs\\SVs shall be operable in reactor operating modes 1, 2, and 3. TS 3.4.3.1 surveillance requirement states that the SRVs\\SVs opening lift setpoints are maintained within + 1% tolerance of the design opening pressure. Contrary to the above, information received by site engineering from a laboratory performing SRV\\SV as-found testing, determined that on September 25, 2012, the valve setpoint deficiencies existed with six SRVs and one SV that were in place during the Unit 2 19 operating cycle. The SRVs /SV were determined to have their as-found setpoints outside of the TS allowable + 1% tolerance. The six SRVs outside of their TS allowable setpoint range were within the ASME Code allowable + 3% tolerance. The one SV outside of its TS allowable setpoint range also slightly exceeded the ASME Code allowable + 3% tolerance at a value of + 3.4%. The cause of the SRVs /SV being outside of their allowable as-found setpoints was due to setpoint drift. The SRVs /SV were replaced with refurbished SRVs/SV for the 20th Unit 2 operating cycle. The amount of setpoint drift was within the as found Target Rock SRV values when compared to industry data. The SRVs/SV were replaced with refurbished valves that were tested and opened within the allowable + 1% tolerance. The inspectors determined that the finding was of very low safety significance (Green) in accordance with Section A of Exhibit 2 in Appendix A of IMC 0609, The Significance Determination Process for Findings at Power, because the SRVs safety function was not affected. Although outside the lift setpoint tolerance, the as found SRV/SV lift pressure values would not have challenged the reactor vessel design maximum pressure rating during the most limiting postulated accident event. The inspectors reviewed PBAPSs planned corrective actions to address the SRV setpoint drift issue and considered a planned industry standard TS setpoint change submittal to a + 3% tolerance appropriate. Because this finding is of very low safety significance, the as-found out of tolerance SRVs were replaced with SRVs that had the proper lift setpoint prior to the Unit 2 reactor plant startup, and the issue was entered into Exelon\'s CAP under IR 1418320 and apparent cause evaluation 1120516, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000271/FIN-2012004-02	2012Q3	Vermont Yankee	Dedicated Operators Required for Operability Under Applied Administrative Controls Left Immediate Vicinity of Open Valves	The inspectors identified an NCV of technical specification (TS) 6.4, Procedures, for Entergys failure to implement a surveillance activity in accordance with the written procedure. Specifically, the inspectors identified that during a surveillance test, dedicated operators required to maintain operability of primary containment left the immediate vicinity of open manual containment isolation valves. Entergys corrective actions included restoring the administrative controls required to maintain primary containment operability during the subject surveillance test, initiating condition report CR-VTY-2012-03561, sending a memorandum to and discussing the issue with all operating crew shift managers explaining the error and the requirements of a dedicated operator, and issuing a temporary night order further explaining these requirements. Additional corrective actions included implementing and tracking training for all operators on these requirements, and revising licensed operator training on primary containment to specifically describe these requirements. The inspectors determined that the issue was more than minor because it is associated with the Human Performance attribute of the Barrier Integrity cornerstone and 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. Specifically, the dedicated operators were required to be stationed in the immediate vicinity of the valve controls to rapidly close the valves when primary containment isolation is required during accident conditions, but the operators were significantly beyond the required immediate vicinity when they left the reactor building. The inspectors determined the significance of the finding using IMC 0609, Appendix H, Containment Integrity Significance Determination Process. The finding was determined to be of very low safety significance (Green) using Appendix H, Table 6.2, Phase 2 Risk Significance Type B Findings at Full Power, because primary containment was inoperable for 37 minutes, i.e. less than 3 days. The inspectors determined that this finding had a cross-cutting aspect in the Human Performance cross-cutting area, Resources component, because the training of personnel did not describe specific requirements of dedicated operators, including the definition of immediate vicinity.
05000271/FIN-2012004-01	2012Q3	Vermont Yankee	Incorrect Assessment of Equipment Condition Resulted in Single Recirculating LOOP Operation	A self-revealing, Green finding (FIN) was identified because Entergy failed to implement a preventive maintenance procedure. Specifically, Entergy personnel classified the discovery status code for the minor motor inspection on the A recirculation pump motor generator set drive motor incorrectly, as B satisfactory or normal wear, instead of D abnormal wear, which resulted in a missed opportunity to replace degraded components that caused the A recirculation pump to trip and an unplanned entry into single recirculation loop operation. Entergys corrective actions included cleaning the motor and the junction box, replacing components that had been damaged by an arc flash, and testing the circuit to verify no other components were degraded prior to restarting the motor. In addition, Entergy initiated condition report CR-VTY-2012-02811 and issued a corrective action to reinforce the requirements of Entergy Procedure EN-DC-324 among maintenance staff. Entergy also plans to add all large motor and generator junction boxes to the predictive maintenance program and to perform thermography on a six month frequency. The inspectors determined that the issue was more than minor because it resulted in a transient, i.e. an event that upset plant stability (an unplanned entry into single recirculation loop operation). In particular, the issue is associated with the Equipment Performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability during power operations. The inspectors determined the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The finding was determined to be of very low safety significance (Green) because the finding was a transient initiator that did not cause a reactor trip. The inspectors determined that the finding had a cross-cutting aspect in the Human Performance cross-cutting area, Work Practices component, because Entergy did not sufficiently define and effectively communicate expectations regarding procedural compliance for the selecting of the discovery status code and personnel did not follow procedures.
05000443/FIN-2012004-04	2012Q3	Seabrook	Licensee-Identified Violation	Seabrook TS SR 4.3.2.2, Engineered Safety Features Actuation System Instrumentation, requires that the engineered safety features response time for each ESFAS function listed in Table 3.3-3 be verified to be within its limit at least once per 18 months. On July 19, 2012, NextEra identified that the full scope of response time testing for the emergency feedwater function had not been completed since initial licensing because the implementing procedure did not verify the response time for starting and loading the motor-driven emergency feedwater pump on a steam generator low-low water level. The issue was determined to be a violation of Seabrook TS 6.7, Procedures and Programs, which requires that written procedures be established, implemented and maintained as recommended in RG 1.33, Revision 2, Appendix A, February 1978. RG 1.33, Appendix A, requires implementing procedures for each SR listed in TSs. Contrary to this requirement, since initial licensing, NextEras procedure for implementing TS SR 4.3.2.2 did not test the response time for the emergency feedwater function at least once per 18 months, which resulted in a violation of TS 3.3.2, Engineered Safety Features Actuation System Instrumentation, as described in LER 05000443/2012-001-00. The finding was associated with the Mitigating Systems cornerstone and was evaluated for significance using Exhibit 2 of IMC 0609, Appendix A. Since the finding was not a design or qualification deficiency, did not result in a loss of system safety function, did not result in loss of a single train for greater than its allowed outage time, and was not potentially risk significant due to external events, the finding was determined to be of very low safety significance (Green). The issue was entered into NextEras CAP as CR 1785593.

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