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	Q	Significance	CCA	Identified by	Title	Description
05000277/FIN-2018410-01	2018Q3	Green	H.8	NRC identified	Security
05000277/FIN-2018003-03	2018Q3	White		NRC identified	Reactor Core Isolation Cooling System Pressure Switch Failure Results in Condition Prohibited by TS - EA-18-108	On April 22, 2018, during a routine surveillance test of the RCIC system, the RCIC turbine tripped approximately 28 seconds after startup, prior to the system reaching rated flow and pressure. Concurrent with the RCIC trip, an alarm was received for RCIC turbine high exhaust pressure; however, local indications did not indicate a true high pressure in the exhaust line. Therefore, the RCIC system was declared inoperable and TS 3.5.3, Condition A was entered, which requires the RCIC system to be restored to operable within 14 days. Troubleshooting determined that the B RCIC exhaust pressure switch (PS-3-13-72b) had prematurely tripped at normal operating pressure due to an age-related failure of the instrument diaphragm and O-ring. The RCIC system had been previously verified as operable during its last surveillance run on January 16, 2018. Corrective Actions: The failed pressure switch was replaced and the station performed an extent of condition review/inspection of similar pressure switch instruments. Following replacement of the switch, RCIC was retested and restored to operable on April 23, 2018. Furthermore, actions were established to modify the turbine trip logic to remove the single point trip vulnerability. Corrective Action Reference: IR 4129583 Enforcement:Violation: Peach Bottom Unit 3 TS 3.5.3 requires that the RCIC system shall be operable in Mode 1, and if RCIC becomes inoperable, it shall be returned to operable status within 14 days or the plant shall be placed in Mode 3 within the next 12 hours. Contrary to the above, based on relevant causal information, Unit 3 RCIC was likely inoperable prior to April 22, 2018, for a period greater than the TS allowed outage time of 14 days, and Unit 3 had not been placed in Mode 3. Specifically, on April 22, 2018, the Unit 3 RCIC turbine tripped during startup for a routine surveillance test due to a degraded turbine exhaust pressure switch which resulted in an inoperability time of greater than 14days. Internal inspection on the switch identified that it failed due to corrosion from water intrusion which had existed for an extended period of time. Severity/Significance: For violations warranting enforcement discretion, IMC 0612 does not require a detailed risk evaluation; however, safety significance characterization is appropriate. A Region I SRA performed a best estimate analysis of the safety significance using the Peach Bottom Unit 3 Standardized Plant Analysis Risk (SPAR) model, Version 8.51 and Systems Analysis Programs for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8.1.8. This model was used to evaluate the internal events increase in core damage frequency (CDF) per year. The SRA performed a site visit to review Exelons fire model output to estimate the external risk contributor of the issue. The final risk evaluation estimated the total (internal and external events risk) increase in CDF to be in the mid E-6/yr range, or of low to moderate safety significance. The SRA evaluated the internal and external events risk contribution due to the inoperability of the RCIC system for an assumed 47 day exposure time. 16 The analyst used the guidance in the Risk Assessment Standardization Project (RASP) Handbook, Volume I, Section 2.4, Revision 2.0, to estimate an exposure time using a time divided by two (t/2) approach. This would represent the time from the last successful surveillance test divided by two. The approach is appropriate for periodically operated components that fail due to a degradation mechanism that gradually could affect the component during the standby period. Given this approach, the internal event contribution was calculated to estimate the internal event risk increase due to the conditional failure of the RCIC pump to successfully start. The increase for internal events was estimated at 2.5E-6/yr increase in CDF. The dominant sequence involved a loss of condenser heat sink, with operator action failure to depressurize, and HPCI system failures. The SRA noted from discussions with Exelon staff that the RCIC system was assumed to be non-recoverable given the nature of the failure. To estimate the external risk contribution, the SRA had several discussions and a site visit to review Exelons preliminary fire model outputs for the conditional failure of the RCIC system for the 47 days. The 47 days included a conservative additional day for repair time. The SRA reviewed Exelons fire risk analysis and noted that one of the dominant risk increase contributors was fire within the 13kV switchgear room. Several other fire areas were reviewed and the SRA noted that the core damage sequences appeared technically reasonable given the plant areas and values assumed for mitigating equipment. Exelons preliminary results showed an increase in external event CDF/yr for the conditional failure of RCIC for 47 days to be approximately 4.5E-6/yr. The SRA determined the results to be reasonable. Exelons model for internal events resulted in an increase in CDF/yr of 1.05E-6/yr which was considered to compare well with the NRC SPAR model. Exelon performed a review of the large early release frequency (LERF) impact and determined an overall increase in LERF due to both external and internal events for the RCIC failure for 47 days to be a nominal 6E-8/yr. Therefore, the SRA review of the dominant sequences and Exelons LERF results affirmed that LERF did not increase the risk over that determined from the increase in CDF. Basis for Discretion: The inspectors determined that the maintenance strategy for these switches was consistent with requirements and standards that existed at the time and that there was no relevant operating experience that would have reasonably necessitated consideration of additional maintenance actions. As a result, no performance deficiency was identified. The inspectors assessment considered: The industry, regulatory, and Exelon service life standards were reviewed for static O-ring pressure switches. Exelons assessment of the pressure switch service condition (critical, mild conditions, low-duty cycle) required a preventive maintenance task to perform periodic calibration and to replace the switch as-required. There was no time-based replacement task prescribed by any standard for this switch. The inspectors determined that Exelons assessment was adequate and the corresponding preventive maintenance activities met applicable standards. The subject pressure switch was installed during original construction and the calibration results of the pressure switch had been satisfactory from 2003 until the 2018 failure. The inspectors reviewed the maintenance and calibration history on the pressure switch and did not identify any adverse trends or conditions adverse to 17 quality that would have required further evaluation or replacement of the pressure switch. Industry operating experience information available to Exelon did not identify the potential for the age-related failure mode of the pressure switch o-ring and diaphragm that occurred at Peach Bottom. The NRC determined that it was not reasonable for Exelon to have been able to foresee and prevent this violation of NRC requirements, and as such, no performance deficiency existed. Therefore, the NRC has decided to exercise enforcement discretion in accordance with Sections 2.2.4 and 3.10 of the NRC Enforcement Policy and refrain from issuing enforcement action for the violation of TSs (EA-18-108). Further, because Exelons actions did not contribute to this violation, it will not be considered in the assessment process or the NRC Action Matrix
05000277/FIN-2018003-02	2018Q3	White	H.11	NRC identified	Inadequate Corrective Actions Result in the Failure of the E-3 EDG	The inspectors identified a self-revealing preliminary White finding associated with an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not perform adequate corrective actions on the E-3 EDG scavenging air check valve assembly. Specifically, Exelon did not perform an adequate repair of an interference fit pin joint during maintenance activities in April 2017 and did not correct an oil leak on the check valve dashpot assembly identified in September 2017, which resulted in the E-3 EDG failure on June 13, 2018.
05000277/FIN-2018003-01	2018Q3	Green	P.2	NRC identified	HPCI System Exhaust Pressure Switches Exceeded Documented Qualified Life	The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because Exelon did not establish measures to ensure that environmental qualification requirements for qualified components were correctly translated into procedures and instructions. Specifically, the end-of-life replacement requirements for the Unit 2 HPCI exhaust pressure switches were not translated into maintenance procedures and instructions. As such, Exelon did not replace the switches prior to the end of their documented qualified life.
05000277/FIN-2018010-03	2018Q2	Green		Licensee-identified	Licensee-Identified Violation	This violation of very low safety significance was identified by Exelon and has been entered into Exelons corrective action program and is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Peach Bottom Unit 2 and Unit 3 Renewed Facility Operating License Condition 2.C.(4) requires, in part, Exelon to implement and maintain in effect all provisions of the approved fire protection program as described in the Updated Final Safety Analysis Report. Fire Protection Program, Peach Bottom Atomic Power Station, Units 2 and 3, is incorporated by reference into the Updated Final Safety Analysis Report, as discussed in Section 10.12, Fire Protection Program. Fire Protection Program Chapter 5.1, Methodology, assumes that two or more circuit failures resulting in spurious operation of two or more valves in series at a high/low pressure interface may occur due to a postulated fire in any given area.Fire Protection Program Chapter 6.2, Analysis of High/Low Pressure Interfaces, requires Exelon to address the situations for which the isolation valves at a given interface point consists of two electrically controlled valves in series and where the potential may exist for a single fire to cause damage to cables associated with both valves. 8 Contrary to above, as ofMarch 14, 2018, Exelon identified they failed to evaluate two motor-operated valves in series, MO-2-06-2663 and MO-2-06-038B for Unit 2, and MO-3-06-3663 and MO-3-06-038B for Unit 3, where the potential may exist for a single fire to cause damage to cables associated with both valves. Specifically, a postulated fire scenario could cause spurious opening of the valves, which may potentially result in a fire-induced loss of coolant accident through the high/low pressure system interface. Exelons evaluation identified the affected valves cables are routed through Fire Area 6N for the Unit 2 valves, and Fire Area 13N for the Unit 3 valves, and thus, a possibility exists for a single fire to cause damage to cables associated with both valves. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. Significance/Severity: The inspectors performed a Phase 2 Significance Determination Process screening for this issue, in accordance with IMC 0609, Appendix F, Fire Protection Significance Determination Process. This finding affected the post-fire safe shutdown category because of spurious operations of safe shutdown components. Based on a walkdown of Fire Areas 6N and 13N, the inspectors did not identify any credible fire ignition source scenarios that could affect both Unit 2 motor-operated valves or both Unit 3 motor operated valves. Therefore, based upon task number 2.3.5, the inspectors determined that this finding screened to very low safety significance (Green).Corrective Action References: IR 04115309, EC 623585, EC 623586
05000277/FIN-2018010-02	2018Q2	Green		NRC identified	Failure to Develop and Maintain Mitigating Strategy	The inspectors identified a Green non-cited violation of 10 CFR 50.54(hh)(2), Conditions of Licenses, and Peach Bottom Unit 2 and Unit 3 Renewed Facility Operating License Condition 2.C.(11), Mitigation Strategy License Condition, because Exelon did not develop and maintain strategies for addressing large fires and explosions that include operations to mitigate fuel damage. Specifically, Exelon did not adequately develop and maintain procedures to manually depressurize the reactor using the automatic depressurization system safety relief valves in the event of a challenge to the reactor due to a postulated large fire and/or explosion.
05000277/FIN-2018010-01	2018Q2	Green	P.2	NRC identified	Failure to Identify Time-Critical Action	The inspectors identified a green finding because Exelon did not identify, validate, and incorporate a time-critical action referenced in calculation PF-0016-025, Fire Area 025 Fire Safe Shutdown Analysis, in accordance with Sections 4.2 and 4.3 of OP-AA-102-106, Operator Response Time Program. Specifically, Exelon did not identify a 10-minute time-critical action to take the transfer/isolation switch for the high pressure coolant injection (HPCI) inboard steam isolation valve (MO-2(3)-23-015), to the EMERG position
05000277/FIN-2018002-01	2018Q2	Green	P.1	NRC identified	Failure to Identify and Promptly Correct a Condition Adverse to Quality Concerning Battery Charger 2B-003-1	The NRC identified a Green non-cited violation (NCV) of 10 Code of Federal Regulations(CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not identify and promptly correct a condition adverse to quality (CAQ) commensurate with its safety significance concerning the 2BD-003-1 safety-related battery charger. Specifically, Exelon did not appropriately prioritize repairs for a CAQ and, as a result, the 2BD-003-1 battery charger failed to operate when placed in service on June 5, 2018
05000278/FIN-2018001-01	2018Q1	Green		Self-revealing	Untimely Corrective Actions to Address Primary Containment Isolation Valve Condition Adverse to Quality	A Green self-revealing non-cited violation(NCV)of 10 Code of Federal Regulations(CFR)50, Appendix B, Criterion XVI, Corrective Action, was identified because Exelon did not implement prompt corrective actions to address a condition adverse to quality (CAQ) on primary containment isolation valve (PCIV) SV-3-7D-3671G.Specifically, drywellair sampling valve SV-3-7D-3671G failed to perform its PCIV function on February 1, 2018, by failing to stroke closed during its surveillance test as a result of untimely corrective actions.Exelon isolated the associated piping in accordance with technical specifications(TSs)
05000277/FIN-2017003-02	2017Q3	Severity level IV		Licensee-identified	Licensee-Identified Violation	10 CFR 55.25 states, in part, that if an operator develops a permanent physical or mental condition that causes the operator to fail to meet the requirements of 10 CFR 55.21, the facility licensee shall notify the Commission within 30 days of learning of the diagnosis, in accordance with 10 CFR 50.74(c),which states,that the regional administrator shall be notified if a licensed operator develops a permanent disability or illness. Contrary to these requirements, as the result of Exelons medical examination audit completed September 26, 2017, Exelon identified a change in a licensed operators medical condition that was not communicated to the NRC within the required 30 days. The results of the medical examination audit were documented in IR 4054146 and subsequent notifications were made to the NRC.This violation is subject to traditional enforcement because of the potential impact upon the regulatory process for issuing restrictions to operators licenses. The inspectors determined that this issue meets the criteria for a Severity Level IV violation using example 6.4.d.1(a) from the NRC Enforcement Policy because no incorrect regulatory decision was made as the result of the failure of the licensee to report within 30 days. This is of very low safety significance because after NRC review of the subsequent notifications, no changes to license restrictions were required.
05000277/FIN-2017403-02	2017Q3	Green	H.12	NRC identified	Security
05000277/FIN-2017403-01	2017Q3	Green	H.11	NRC identified	Security
05000278/FIN-2017003-01	2017Q3	Green		Self-revealing	Instructions Not Followed for Replacement of HPSW Ventilation Switch Block	A self-revealing NCV of Technical Specification (TS) 5.4.1, Procedures,of very low safety significance (Green) was identified for Exelonnot implementing procedural instructions for the replacement of the HS-3-40H-3AV060 switch block associated with the 3AV060 high pressure service water (HPSW) ventilation fan. Exelon did not ensure that electrical connections were free of loose wire strands per their procedural standard E-1317,Wire and Cable Notes and Details, Power, Control, and Instrumentation, Revision 55, and from the vendor manual instructions. As a result,on July 10, 2017, the 3AV060 HPSW ventilation fan failed its surveillance test(ST)and rendered one subsystem of Unit 3 HPSW inoperable. Exelon entered this issue into their corrective action program (CAP) asissue reports(IR)4030367 and 4044444, straightened out the remaining loose strands, and specified additional electrical panels for an extent of condition (EOC) review.Thisfinding ismore than minor because it isassociated with the equipment performance attribute of the Mitigating Systemscornerstoneand affected the cornerstones objective to ensure the reliability, availability, and capability of systems to respond to initiating events to prevent undesirable consequences (i.e. core damage).By not implementing theE-1317 procedural instructions, the 3AV060 fan failed and affected the reliability of one HPSW subsystem.The inspectors evaluated the finding in accordance with Exhibit 2 of IMC 0609, Appendix A, SDP for Findings At-Power and determined the finding was of very low safety significance (Green) because it did notrepresent a loss of system function or represent an actual loss of function of at least a single train for longer than itsTSallowed outage time. The inspectors determined no cross-cutting aspect applied because the PD occurred in 2010 and was not indicative of current performance.
05000277/FIN-2017002-02	2017Q2	Severity level Enforcement Discretion		NRC identified	EDG Exhaust Stacks Nonconforming Design for Tornado Missile Protection	On January 9, 2017, it was determined that PB's EDGs do not conform with the licensing basis for protection against tornado-generated missiles. The exhaust stacks for the four on-site EDGs extend approximately seven feet above the roof of the EDG building. In the event of a tornado, debris generated from the tornado could strike the exhaust stacks and, if at a sufficient mass and velocity, could crimp the exhaust stacks in a manner that would affect EDG operation.As a result of the non-conforming condition, on January 9, 2017, at 1530, all four EDGswere declared inoperable. Compensatory measures were put in place and, in accordance with NRC guidance contained in Enforcement Guidance Memorandum (EGM) 15-002, the EDGs were returned to an operable but non-conforming status.There are no actual consequences as a result of the non-conforming condition. This LER is closed.b. FindingsDescription. 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that the applicable regulatory requirements and the design basis for SSCs are correctly translated into specifications, drawing, procedures, and instructions. Contrary to the above, Exelon failed to correctly translate the design basis for protection against tornado-generated missiles into their specifications and procedures. Specifically, Exelon did not adequately protect Unit 2 and Unit 3s EDG exhaust stacks from tornado-generated missiles.Exelon documented the condition adverse to quality in their CAP under IR 3961028 and took immediate compensatory actions. The inspectors evaluated Exelons immediate compensatory measures, which included verifying that procedures are in place, equipment was appropriately staged, and training is current for performing actions in response to a tornado to preserve EDG operability. Enforcement. Because this violation was identified during the discretion period covered by EGM 15-002, Revision 1, Enforcement Discretion for Tornado Generated Missile Protection Non-Compliance, (ML16355A286) and because Exelon has implemented compensatory measures, the NRC is exercising enforcement discretion, is not issuing enforcement action, and is allowing continued reactor operation.
05000278/FIN-2017002-01	2017Q2	Green	H.8	Self-revealing	Corrective Action Not Implemented Correctly for Replacement of RCIC RCR Contacts	A self-revealing non-cited violation (NCV) of 10 Code of Federal Regulation(CFR)Part 50, Appendix B, Criterion XVI, Corrective Actions, of very low safety significance (Green) was identified for Exelon not correcting a condition adverse to quality concerning reverse control relay (RCR) contacts for valves associated with the reactor core isolation cooling (RCIC) system. Specifically, Exelon specified a corrective action (CA) from an October 18, 2013, Unit 3 RCIC equipment apparent cause evaluation (EACE) to replace RCR contacts after 12 years of service, however, the CA was not correctly implemented. As a result, on January 12, 2017, an RCR contact associated with the Unit 3 RCIC suppression pool suction valve remained in service for 15 years, exhibited a high resistance failure during a surveillance which resulted in Unit 3 RCIC being inoperable. Following the failure, Exelon initiated issue reports (IRs) 03962563 and 03977949, implemented corrective actions to replace the RCR contact, restored Unit 3 RCIC operability, and risk-informed their corrective maintenance schedule for replacing all RCR contacts that currently exceeded the recommended 12-year service life.Exelons failure to recognize and correct a condition adverse to quality associated with certain RCR contacts in their Unit 3 RCIC system that had exceeded their 12-year service life, was a performance deficiency (PD) that was within their ability to foresee and correct and should have been prevented. The finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstones objective to ensure the reliability of systems to respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, not recognizing that existing RCR contacts were installed in safety-related equipment beyond their 12-year service life, resulted in the failure of the Unit 3 RCIC suppression pool suction valve. The inspectors evaluated the finding in accordance with Exhibit 2 of IMC 0609, Appendix A, SDP for Findings At-Power, and determined the finding was of very low safety significance (Green) because it did not represent a loss of system function or represent an actual loss of function of at least a single train for longer than its technical specification (TS) allowed outage time of 14 days. The inspectors determined that the finding has a cross-cutting aspect in Human Performance, Procedure Adherence, because Exelon did not validate that the correct revision of procedure WC-AA-120, Attachment 2, Preventive Maintenance (PM) Change Review Form, was used when creating a new PM to replace RCR contacts. (H.8)
05000277/FIN-2017201-02	2017Q2	Green		NRC identified	Security
05000277/FIN-2017201-01	2017Q2	Green		NRC identified	Security
05000278/FIN-2017008-02	2017Q1	Green	P.3	Self-revealing	Untimely Corrective Actions to Address Elevated Primary Containment Isolation Valve Leakage	Green. The inspectors identified a self-revealing non-cited violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, because Exelon did not promptly implement corrective actions to address a condition adverse to quality on two containment isolation valves. Specifically, drywell air sampling valves SV-3-7D-3671A and SV-3-7D-3671D failed to perform their primary containment isolation function on March 15 and September 26, 2016, respectively, as a result of untimely corrective actions to address elevated leakage. The valve internals were repaired, declared operable, and the issue was entered into the corrective action program (IR 3990490). The finding was more than minor, because it was associated with the barrier performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstones objective to provide reasonable assurance that the containment design barrier protect the public from radionuclide releases caused by accidents or events. In accordance with IMC 0609.04, Initial Characterization of Findings, dated October 7, 2016, and Exhibit 1 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined this finding was of very low safety significance, because the finding did not result in an actual open pathway in the physical integrity of the reactor containment or involve an actual reduction in the function of hydrogen igniters in the reactor containment. The inspectors determined this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because Exelon did not perform effective corrective actions in a timely manner commensurate with the safety significance of the issue. Specifically, corrective actions to address a CAQ on SV-3-7D-3671A and SV-3-7D-3671D were delayed which resulted in the valves failing their LLRT and being declared inoperable. (P.3)
05000277/FIN-2017008-01	2017Q1	Green	P.3	NRC identified	Untimely Corrective Actions to Address 2C Core Spray Motor Elevated Vibrations	Green. The inspectors identified a non-cited violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, because Exelon did not implement corrective actions in a timely manner to correct a condition adverse to quality on the 2C core spray motor. Specifically, Exelon did not perform appropriate corrective actions to evaluate and address an increasing motor bearing vibration trend that had existed for over ten years. Consequently, motor vibration reached the fault level established in Exelons vibration analysis procedure. The finding was more than minor, because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In accordance with IMC 0609.04, Initial Characterization of Findings, dated October 7, 2016, and Exhibit 1 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, the inspectors determined this finding was of very low safety significance because the performance deficiency did not impact the design or qualification of the component, did not result in a loss of system function, did not result in the loss of function of a train greater than its Tech Spec allowed outage time, and did not represent an actual loss of function for a high safety significant component in accordance with Exelons maintenance rule program. The inspectors determined the finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because Exelon did not take effective corrective actions in a timely manner commensurate with the safety significance of the issue. Specifically, corrective actions to address the elevated vibrations on the 2C core spray motor were not implemented before motor vibration reached the fault level and adversely impacted the long-term reliability of the motor. (P.3)
05000277/FIN-2016004-01	2016Q4	Green		NRC identified	Failure to Identify and Remove FM in CAD System Piping	Green. The inspectors identified a finding of very low safety significance (Green) involving a non-cited violation (NCV) of 10 CFR 50 Appendix B Criterion XVI, Corrective Action, because Exelon did not adequately identify and correct a condition adverse to quality associated with the containment atmospheric dilution (CAD) piping system. Specifically, in 2012, Exelon did not adequately identify the source of foreign material (FM) and implement corrective actions to remove the FM from the CAD piping which resulted in the failure of the CHK-2-07C-40145 containment isolation valve to close in 2016. Exelon documented the issue in issue report (IR) 2735344 and promptly replaced the valve and restored the valve to operable. As an interim corrective action, Exelon plans to increase the local leak-rate test (LLRT) frequency and replacement of the check valve to maintain reasonable assurance of operability. Exelon is implementing a detailed troubleshooting plan to identify the source of FM and perform corrective actions to address the condition adverse to quality. The performance deficiency (PD) is more than minor because it was associated with the containment barrier performance attribute of the barrier integrity cornerstone and it adversely impacted the cornerstone objective to provide reasonable assurance that physical design barriers (containment) protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings at-Power, Exhibit 3, and the inspectors determined this finding to be of very low safety significance (Green) because the degraded condition did not represent an actual open pathway in the physical integrity of containment, and did not involve an actual reduction in function of hydrogen igniters in the reactor containment. The inspectors determined that a cross cutting aspect does not apply because the performance deficiency occurred greater than three years ago and is not indicative of current plant performance.
05000277/FIN-2016003-01	2016Q3	Green		Self-revealing	Reactor Feed Pump Controller Power Supply Shelf Life Not Maintained	A self-revealing finding of very low safety significance (Green) was identified for Exelons failure to maintain the Unit 2 C reactor feed pump (RFP) Woodward controller secondary power supply in accordance with PES-S-002, Exelon Shelf Life Program. Specifically, on May 27, 2016, the Unit 2 C RFP experienced speed oscillations due to an age-related failure of the Woodward controller secondary power supply, which resulted in an automatic recirculation runback to 53 percent rated thermal power (RTP). The power supply contained an electrolytic capacitor that had exceeded its shelf life per PES-S-002. This issue was entered into Exelons corrective action program (CAP) under issue report (IR) 02691322. Exelons corrective actions included replacement of the faulted power supply and an extent of condition (EOC) review of proper expiration date entry for shelf life program components. The finding was more than minor because it was associated with the equipment performance attribute of the Initiating Events cornerstone and affected the cornerstones objective of limiting the likelihood of events that upset plant stability during power operations. The inspectors evaluated the finding in accordance with Exhibit 1 of Inspection Manual Chapter (IMC) 0609, Appendix A, SDP for Findings At-Power, and determined the finding was of very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that no cross-cutting aspect was applicable to this finding because the performance deficiency (PD) was not indicative of current performance. The PD occurred between 1997 and 1999 when the power supply expiration date was incorrectly coded in Exelons work management process in accordance with PES-S-002.
05000277/FIN-2016404-01	2016Q3	Green	H.14	NRC identified	Security
05000277/FIN-2016002-02	2016Q2	Green	H.1	NRC identified	Untimely Corrective Actions to Address Condition Adverse to the Fire Protection Program Alternative Shutdown Capability	The inspectors identified an NCV of very low safety significance (Green) of PB Unit 2 and Unit 3 Facility Operating License condition 2.C.(4) for failure to implement and maintain in effect all provisions of the approved fire protection program. Exelon did not correct a condition adverse to the fire protection program alternative shutdown capability in a timely manner. Specifically, Exelon did not establish testing requirements for transfer/isolation switches since the identification of the issue on February 6, 2014, and the due date to complete this action was extended to February 24, 2018. As a result, Exelon has delayed assurance that the components credited for alternative shutdown capability would perform their fire protection design basis function. Exelon entered this issue into their CAP as IR 02669323. This performance deficiency (PD) was more than minor because it was associated with the protection against external factors (fire) attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, by failing to correct the condition, Exelon has not ensured that the control circuit for the safe shutdown components would be isolated from the effects of fire damage. The inspectors determined that the finding was of very low safety significance (Green) based on IMC 0609, Appendix F, Fire Protection SDP, task number 1.3.1, because Exelon had demonstrated reasonable expectation of functionality for these switches by having comparable switches in the test program and periodically testing those switches. The test results did not indicate any kind of significant failures of these switches. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Resources, in that, Exelon extended the due date to complete the corrective action to support the completion of higher priority items, indicating lack of resources.
05000277/FIN-2016403-01	2016Q2	Severity level Enforcement Discretion		NRC identified	Security
05000277/FIN-2016002-01	2016Q2	Green	H.8	NRC identified	Improperly Stored Material in Reactor Building	The NRC identified a very low safety significance (Green) NCV of Technical Specification (TS) 5.4.1 for Exelons failure to adequately implement procedure requirements governing the storage of material in a safety-related structure. Specifically, on April 26, 2016, Exelon technicians stored ladders vertically without them being adequately tied off to prevent the ladders from falling over in accordance with MA-AA-716-026, Station Housekeeping / Material Condition Program. The inspectors identified that the ladders were stored in the PB Unit 2 reactor building (RB), such that they could fall over and impact safety-related equipment. The inspectors promptly notified Exelon, the ladders were immediately removed, and the condition was documented under IR 2661309. This finding was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Characterization of Findings, and Appendix A, The SDP for Findings At-Power, Exhibit 2. The inspectors determined this finding to be of very low safety significance (Green) because the degraded condition was not a design deficiency that affected system operability; did not represent an actual loss of function of a system; did not represent an actual loss of function of a single train or two separate trains for greater than its TS allowed outage time; and did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant. The finding was determined to have a cross-cutting aspect in the area of Human Performance, Procedure Adherence, because Exelon technicians did not store ladders in safety-related buildings in accordance with station procedures, such that they could not fall over and damage safety-related equipment.
05000277/FIN-2016002-03	2016Q2	Green	H.2	Self-revealing	Human Performance Event Results in Emergent Downpower	A self-revealing finding of very low safety significance (Green) was identified for the failure of Exelon operators to use human performance error reduction tools during equipment manipulation in accordance with HU-AA-101, Human Performance Tools and Verification Practices. Specifically, on March 28, 2016, an equipment operator failed to use self-check (STAR) while removing a circuit breaker from service and incorrectly tripped the E-124 480 volt supply breaker which required a rapid manual power reduction to 80 percent rated thermal power (RTP) due to lowering main condenser vacuum and a partial loss of feedwater heating. Exelon entered the issue into their corrective action program (CAP) under issue report (IR) 2646772 and performed a root cause which identified corrective actions to address the adverse human performance behaviors at the station. The finding was more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown, as well as power operations. Specifically, an equipment operator failed to adequately use human performance error reduction tools and opened an incorrect breaker which required a rapid downpower. The inspectors evaluated the finding in accordance with Exhibit 1 of IMC 0609, Appendix A, The SDP for Findings At-Power, dated June 19, 2012, and determined the finding was of very low safety significance (Green) because it did not result in a reactor trip and the loss of mitigation equipment relied upon for transition to a stable shutdown condition. This finding was determined to have a cross-cutting aspect in the area of Human Performance, Field Presence, because Exelon did not ensure that deviations from standards and expectations, which were identified by leaders, were corrected promptly. Specifically, Exelon identified that adverse human performance behaviors existed with certain equipment operators, however, those observations were not appropriately input into their performance management system, such that the behaviors could be addressed. Thus, these adverse behaviors were a primary contributor to this human performance error.
05000278/FIN-2016001-01	2016Q1	Severity level IV		Licensee-identified	Licensee-Identified Violation	On September 29, 2015, Exelon identified the door to the Unit 3 condensate backwash tank room was not secure. The room is controlled as a locked HRA, and a survey of the room indicated that actual radiation levels were greater than 1.0 rem/hour. TS 5.7.2.a requires, in part, that entryways to areas exceeding 1.0 rem/hour will be locked or continuously guarded to prevent unauthorized entry. Contrary to the above, on September 29, 2015, Exelon identified an area with radiation levels greater than 1.0 rem/hour with an entryway that was not locked or continuously guarded. Traditional enforcement applies in accordance with Inspection Manual Chapter (IMC) 0612, sections 0612-09 and 0612-13; and Enforcement Policy Section 2.2.4.d; because the inspectors did not identify an associated performance deficiency. Specifically, the inspectors determined that because Exelon had an acceptable door maintenance program, conducted weekly checks of LHRA doors, and has not had previous issues with unsecured doors, that the failure of the door lock mechanism was not apparent and, therefore, was not foreseeable and preventable. The issue was considered to be a SL IV violation of TS 5.7.2.a in accordance with Enforcement Policy Section 6.1.d. In addition, IMC 0612, Appendix B, Figures 1 and 2, Issue Screening, were utilized in documenting this as a SL IV licensee-identified NCV. The licensee took immediate corrective actions to ensure the door remained locked and documented the issue in condition report 2562192, and the investigation determined that no unauthorized access to the room had occurred.
05000277/FIN-2015004-01	2015Q4	Green		NRC identified	Failure to Ensure Design Basis of Emergency Diesel Generator Lubrication System	The inspectors identified a non-cited violation (NCV) of very low safety significance of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion III, Design Control, for not ensuring that the adequacy of PBAPS emergency diesel generator (EDG) lubrication oil (LO) supply was designed to withstand the effects of natural phenomena. Specifically, additional LO, evaluated by PBAPS to meet their EDG technical specification (TS) mission time of seven days of continuous operation, was housed in a non-class I structure that would be unable to withstand the effects of natural phenomena. PBAPS entered the issue into the correction action program (CAP) as issue report (IR) 02603369 and took immediate corrective actions to relocate the LO reserve inventory from their warehouse to the 135 elevation of the PBAPS radwaste building, which is a seismic class I structure The finding is considered more than minor because it is associated with the Protection Against External Factors attribute of the Reactor Safety Mitigating Systems cornerstone and adversely affected the cornerstones objective of ensuring reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the significance of this finding using IMC 0609 Appendix A, The 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 design deficiency which did not result in an actual loss of functionality of the EDGs. This finding did not have a cross-cutting aspect because the most significant contributor of the performance deficiency (PD) occurred during the 1994 conversion to improved technical specifications (ITS) and, thus, was not reflective of current plant performance. Specifically, PBAPS current engineering change request (ECR) process would evaluate for natural phenomena considerations such as seismic, tornado, flood, etc.
05000277/FIN-2015003-02	2015Q3	Green		Licensee-identified	Licensee-Identified Violation	The following violation of very low safety significance (Green) was identified by Exelon and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV. From 2010 to 2014, PBAPS made a total of 18 shipments of radioactive waste for disposal to the Energy Solutions Clive, UT facility, which contained category 2 levels of radioactive material quantity of concern (RAM-QC), but did not implement transportation security plan for these shipments, which is contrary to the requirements of 10 CFR 71.5 and 49 CFR 172, Subpart I, Safety and Security Plans. This PD adversely affected the Public Radiation Safety cornerstone attribute of Program and Process based on inadequate procedures associated with the transportation of radioactive materials. This issue was documented in Exelons CAP as assignment reports 02484424, 02487034, and 02490534.
05000277/FIN-2015003-01	2015Q3	Green	H.12	NRC identified	Incomplete Testing of Components from the Remote Shutdown Panels	The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1.a after Exelon did not establish and implement procedures to adequately test the Unit 2 and Unit 3 remote shutdown panels (RSPs). Specifically, Exelons surveillance procedure did not test all the control circuits, as required by Surveillance Requirement (SR) 3.3.3.2.1, for the Unit 2 and Unit 3 RSPs. Exelons corrective actions included entering this issue into their CAP, the development of RSP testing procedures for the reactor core isolation cooling (RCIC), control rod drive (CRD), and emergency service water (ESW) system components, and a revision to the bases for TS 3.3.3.2 The performance deficiency (PD) was determined to be more-than-minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Additionally, examples 1.c, 4.l, and 4.m from IMC 0612, Appendix E, detail that a PD was more than minor if required TS surveillance testing is not performed and subsequent testing reveals that the equipment is out of specification or otherwise unable to perform a safety-related function. A detailed risk evaluation concluded that the issue was of very low safety significance (Green). This finding had a cross-cutting aspect in Human Performance, Avoid Complacency, because Exelon failed to recognize and plan for the possibility of latent problems.
05000277/FIN-2015008-01	2015Q2	Green	P.1	NRC identified	Failure to Initiate IRs for Out-of-Calibration SPVs	The inspectors identified a finding of very low safety significance (Green) because PBAPS did not initiate issue reports (IR) to identify out-of-tolerance conditions for a number of single point vulnerability (SPV) instruments. An SPV instrument is any instrument for which a single failure could initiate a plant transient or cause a plant scram. Specifically, during routine preventative maintenance (PM) calibrations, certain SPV instruments as-found data was found outside expected tolerance bands, with many being significantly outside of their bands. In most cases, IRs were not written to document these adverse conditions contrary to station guidance. The finding is determined to be more than minor because it affected the reliability of the initiating cornerstones attribute of equipment performance and affected its objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, by not identifying and trending out-of calibration SPVs in a timely manner, a resulting transient from the loss of a single feed pump or a single reactor recirculation pump is more likely to occur. The inspectors conducted a Phase 1 screening in accordance with NRC Inspection Manual Chapter (IMC) Attachment 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feed water.) A loss of a single feed pump or a single recirculation pump typically results in a power reduction but not a reactor scram. The inspectors determined that the finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Identification. In the case of the finding, PBAPS did not ensure that degraded conditions, namely, out of tolerance SPV instruments, were promptly reported and documented in the corrective action program at a low threshold.
05000277/FIN-2015001-01	2015Q1	Green	H.3	NRC identified	Failure to Scope Flood Detection Level Switches into the MR	The inspectors identified a non-cited violation (NCV) of very low safety significance (Green) of 10 CFR Part 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," because Exelon did not include certain flood indication functions into the scope of the maintenance rule (MR). Specifically, level switches used to indicate flood levels in the Unit 2 and Unit 3 emergency core cooling system (ECCS) rooms were not included in the scope of the MR as required by 10 CFR 50.65 (b)(2)(i) as non-safety related components that are used in plant emergency operating procedures (EOPs). PBAPS entered the issue into their corrective action program (CAP) as issue reports (IRs) 02433897 and 02437502 and scoped the level switches into the MR. The finding is determined to be more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone and affected the cornerstones objective to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In the case of this finding, monitoring of components that provide alarm indication to operators during a flood hazard were not incorporated into the MR. The inspectors also reviewed IMC 0612, Appendix E, Examples of Minor Issues, and determined the issue was similar to example 7.d; in that, flood detection was not within the scope of the MR and that one of the flood detectors had experienced performance problems during preventive maintenance (PM) testing . The inspectors conducted a Phase 1 screening in accordance with IMC 0609.04, Phase 1 Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green), because the finding was not a design or qualification deficiency, did not represent an actual loss of system safety function, did not represent an actual loss of safety function of a single train for greater than its Technical Specification (TS) allowed outage time, and did not screen as risk significant due to external initiating events. The inspectors determined that the finding had a cross-cutting aspect in the area of Human Performance, Change Management because PBAPS did not use a systematic process for evaluating and implementing a change. Specifically, during PBAPSs MR database update and monitoring criteria development for new functions, PBAPS did not ensure that certain level switches that provide alarms for flooding used in plant EOPs were scoped into the MR despite identifying that it was required. (H.3)
05000277/FIN-2014004-03	2014Q3	Green	H.7	NRC identified	Inadequate Evacuation Time Estimate Submittals	The inspectors identified a Green 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 Part 50, Appendix E, Section IV.4, for failing to maintain the effectiveness of the PBAPS, Units 2 and 3, Emergency Plan. The station did not provide the evacuation time estimate (ETE) to the responsible offsite response organizations (OROs) by the required date. Exelon entered this issue into its CAP as IR 1525923 and IR 1578649. Additionally, Exelon re-submitted a new revision of the Peach Bottom ETE to the NRC on May 2, 2014. The performance deficiency is more than minor because it is associated with the Emergency Preparedness cornerstone attribute of procedure quality and it 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 finding was determined to be of very low safety significance (Green) because it was 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 the cross-cutting element of Human Performance, Documentation, because Exelon did not appropriately create and maintain complete, accurate and, up-to-date documentation.
05000277/FIN-2014004-02	2014Q3	Green	H.5	Self-revealing	Scaffold Obstructs A RHR Discharge Check Valve	A self-revealing finding was identified involving an NCV of very low safety significance (Green) for Technical Specification (TS) 5.4.1 Procedures, because Exelon did not correctly implement procedure MA-MA-796-024-1001, Revision 8, Scaffold Criteria for the Mid-Atlantic Stations. In addition, work order (WO) C0244158, Open/Close CHK-2- 10-48A for OPS Torus Support, instructions were not implemented as written to remove a gag (i.e., eyebolt) on the Unit 2 A residual heat removal (RHR) pump discharge check valve, CHK-2-10-48A, following restoration of the 2 A RHR system after a September 16, 2012, maintenance and fill activity. By not implementing these procedures and instructions, the eyebolt prevented full closure of CHK-2-10-48A after the 2 A RHR pump was secured. Exelon entered these issues into their CAP as IR 1680741, IR 1690648, and action request (AR) 02387793. Exelon removed the eyebolt and scaffold midrail to prevent any obstruction of movement on CHK-2-10-48A. The finding is more than minor because it affected the Mitigating Systems cornerstone attribute of equipment performance in the area of reliability and availability of the 2 A RHR train. Specifically, due to the stuck open check valve during a postulated loss of coolant accident (LOCA)/loss of offsite power (LOOP) scenario, voiding could occur and create a potential water hammer resulting in pipe support damage. This finding was determined to be of very low safety significance (Green) using IMC 0609, Appendix A, Exhibit 2, because the finding did not represent a loss of system function, did not represent a loss of a single train for greater than its allowed TS outage time, and did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event. Additionally, the inspectors determined that the function of 2 A RHR remained available because RHR piping would remain intact and containment cooling would not have been lost during the postulated water hammer scenario. The finding has a cross-cutting aspect in Human Performance, Work Management, because in the case of the erected scaffold, Exelon did not plan, control, and execute work activities such that nuclear safety was the overriding priority. Specifically, the work process did not coordinate effectively with different groups (i.e., operations, engineering, scaffold builders, and maintenance) and job activities to identify and preclude the scaffold from obstructing an eyebolt attached to the swing arm of the 2 A RHR pump discharge check valve.
05000277/FIN-2014004-01	2014Q3	Green	P.2	NRC identified	Corrective Actions Not Timely for EOC of Appendix R Broken Wires	The inspectors identified a Green non-cited violation (NCV) of the PBAPS Units 2 and 3 operating licenses, Section 2.C.4, Fire Protection, because Exelon did not have the ability to implement all provisions of their approved Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, UFSAR Section 5.2.2, Appendix R, Shutdown Method D, was found degraded due to the loss of the alternate 125 volts direct current (Vdc) control power to both E-2 and E-4 alternate shutdown panels. The alternate 125 Vdc power was found degraded during a planned inspection due to broken electrical wires located in the safety-related E-23 4.16 kilovolt (kV) breaker cubicle associated with the E-2 alternate shutdown panel. The extent-of-condition (EOC) corrective actions were not timely to identify and correct similar broken wires in the E-43 4.16 kV breaker cubicle associated with the E-4 alternate shutdown panel. PBAPS entered the following issue reports (IRs) into their corrective action program (CAP): IR 01629839, 01656255, 01662555, and 01662767. Exelon completed repairs of the broken wires in both electrical breaker cubicles. The finding is more than minor because it is associated with the external events (fire) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, following a postulated control room abandonment fire, the analyzed normal method was unavailable for closing three 4 kV circuit breakers locally with the switchgear mounted switch. Using IMC 0609, Appendix F, Fire Protection SDP, the Region I Senior Reactor Analyst (SRA) determined per Figure F.1, Phase 1 Flow Chart, and associated screening criteria that this finding is of very low safety significance (Green). The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R), Evaluation, because Exelon did not complete the EOC action in a timely manner commensurate with its safety significance. Specifically, the decision to implement corrective actions to address the EOC two months after the identification of the first breaker cubicle broken wire was not timely and commensurate with its safety significance. Additionally, the condition potentially existed for a longer period of time, but was not identified by established maintenance procedures. Even though the E-43 4.16 kV breaker wires could be checked without affecting the operability or availability of the E-4 emergency diesel generator (EDG), Exelon decided to perform the E-43 4.16 kV EDG breaker cubicle inspection during a future scheduled overhaul. Exelons corrective action procedure defines an immediate EOC concern when, as in this case, a work group evaluation (WGE) is required.
05000277/FIN-2014404-01	2014Q2			NRC identified	Security
05000277/FIN-2014007-02	2014Q2	Green	P.2	NRC identified	Non-Conservative Voltage Assumption Used to Verify MOV Capability	The team identified a Green non-cited violation of Title 10 Code of Federal Regulations 50, Appendix B, Criterion III, Design Control. Specifically, Exelon did not correctly verify the capability of alternating current motor-operated valves (MOVs) at a degraded voltage corresponding to the lowest voltage allowed by plant Technical Specification setpoints for the degraded grid voltage relays. Exelon initiated issue report 1642720 to evaluate the adequacy of their design and determined that 9 out of the 130 alternating current MOV program valves required further evaluation. The licensee performed an operability evaluation of the affected MOVs, assuming the appropriate voltage, and determined that, although significant design margin was lost, all MOVs remained operable. The finding was more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the capability of the 480 volt alternating current (AC) MOVs to respond to initiating events to prevent undesirable consequences. The team determined the finding was of very low safety significance because it was a design deficiency confirmed not to result in a loss of operability. The team assigned a cross-cutting aspect associated with this finding, because the deficient AC MOV operability evaluations were completed in November 2011 and were reflective of current performance. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Evaluation (PI.2), because Exelon did not thoroughly evaluate the issue addressed in a previous NCV contained in NRC Inspection Report 2010004, during 2011, for PBAPS such that, the resolution addressed causes and extent-of-condition commensurate with the safety significance. Specifically, the affected MOVs were not evaluated at the required voltage in operability evaluations performed following receipt of a non-cited violation.
05000277/FIN-2014007-01	2014Q2	Green	P.2	NRC identified	Deficient E2 EDG Loading Calculation Design	The team identified a Green non-cited violation of Title 10 Code of Federal Regulations 50, Appendix B, Criterion III, Design Control, for failure to verify and ensure that the emergency diesel generators (EDGs) were capable of performing their design safety functions at the limits of voltage and frequency allowed by Technical Specifications (TS). Specifically, the existing EDG loading calculation permitted the E2 EDG and associated bus to be loaded up to 3100 KW at nominal frequency and voltage. At the maximum frequency and voltage values permitted by TS, the calculation-allowed maximum load would have exceeded the EDG 30-minute rating limit of 3250 KW and potentially damaged the EDG. Immediate corrective actions included evaluation of EDG loading for TS maximum voltage and frequency and changing design calculation PE-0166 to reduce the maximum permitted E2 EDG load from 3100 kW to 3052 kW at nominal voltage and frequency. Exelon entered the issue into their corrective action program (issue report 1638255) to evaluate the adequacy of the design and ensure that the allowed maximum diesel loading would not exceed the design capabilities of the diesels. The finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the emergency diesels to respond to initiating events to prevent undesirable consequences. The team evaluated the finding in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, for the Mitigating Systems Cornerstone, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012. The team determined the finding was of very low safety significance because it was a design deficiency confirmed not to result in a loss of EDG operability. This team assigned a cross-cutting aspect associated with this finding because the performance deficiency continued during the 2012 assessment of WCAP-17308-NP and was reflective of current performance. The team determined this finding had a crosscutting aspect in the area of Problem Identification and Resolution, Evaluation (PI.2), because engineers did not thoroughly evaluate the EDG loading issue and ensure the resolution addressed its cause commensurate with the safety significance. Specifically, Exelon relied on invalid assumptions to determine the issue was not applicable, and did not thoroughly evaluat the technical issue addressed in the WCAP.
05000277/FIN-2014002-01	2014Q1	Green		Licensee-identified	Licensee-Identified Violation	Title 10 of CFR Part 50.65 (a)(4) requires, in part, that before performing maintenance activities (including but not limited to surveillance, PMT, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed activities. Contrary to the above, on January 30, 2014, PBAPS did not initially assess an increase in plant risk resulting in an upgrade in established risk classification from yellow to orange. PBAPSs additional risk management actions, required by procedure, were delayed. On January 30, 2014, at 2:55 am, PBAPS removed their SBO line from service for planned maintenance and upgraded on-line risk to yellow for the duration of the maintenance activity. At 5:55 am, Pennsylvania-Jersey-Maryland (PJM) Interconnection issued a Maximum Emergency Generation Action for the Mid- Atlantic Region. However, as required, PBAPS was not notified at this time by a Power Team Generation Dispatch. A reactor operator monitoring PJMs website subsequently noticed the Maximum Emergency Generation Action. During a followup call to the Power Team Generation Dispatch contact, the Peach Bottom reactor operator was erroneously told that the grid emergency did not apply to nuclear power plants. In accordance with Exelons risk model and procedures, a Maximum Emergency Generation Action requires an upgrade to the next color risk category. For PBAPSs configuration with the SBO OOS, a risk upgrade from yellow to orange was required. At 7:58 am, PBAPS was notified of the Maximum Emergency Generation Action, identified that their current risk category was incorrect, upgraded the plant risk to orange, and directed the safety tagout clearance on the SBO line to be suspended until the grid emergency was lifted. PBAPS also identified that this issue was a repeat problem from a similar event on July 18, 2012. This previous event, documented in IR 1389933 and IR 1390285, was for PBAPS not being notified as required of a grid emergency by the Power Team Generation Dispatch. The inspectors determined that the finding was of very low safety significance (Green) in accordance with Flowchart 1 of Appendix K of IMC 0609, Maintenance Risk Assessment and Risk Assessment Significance Determination Process, because the incremental core damage probability deficit was significantly less than one E-6. PBAPS was in the less conservative risk category for approximately two hours. The inspectors reviewed PBAPSs planned corrective actions, which were to train power team dispatchers and revise applicable procedures to address the communication problem between generation dispatch and PBAPS. The inspectors considered the planned corrective actions appropriate. Because this finding is of very low safety significance and the issue was entered into Exelon's CAP under IRs 1614646 and 1615043, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000277/FIN-2014201-01	2014Q1	Green		Licensee-identified	Security
05000277/FIN-2013005-01	2013Q4	Green		Licensee-identified	Licensee-Identified Violation	TS 3.4.3 Limiting Condition for Operation 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 October 1, 2013, the valve setpoint deficiencies existed with four SRVs and one SV that were in place during the Unit 3 19th operating cycle. The SRVs/SV were determined to have their as-found setpoints outside of the TS allowable 1% tolerance. The four SRVs and one SV outside of their TS allowable setpoint range were within the ASME Code allowable 3% tolerance. 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 3 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 SDP 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 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 3 reactor plant startup, and the issue was entered into Exelon's CAP under Issue Report 1567200, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000277/FIN-2013405-01	2013Q3			Licensee-identified	Licensee-Identified Violation
05000277/FIN-2013004-02	2013Q3	Green	H.5	NRC identified	Failure to Conspicuously Post and Lock/Guard a HRA on the Unit 3 Turbine Deck Scaffold	The inspectors identified a NCV of very low safety significance of Technical Specification (TS) 5.7.2 because Exelon did not control the access point to a Locked High Radiation Area (LHRA). The performance deficiency (PD) was related to not controlling access to a Unit 3 LHRA. The LHRA became accessible when temporary scaffold was built on the south shield wall between the electrical generator and the main turbine. On August 19, the inspectors identified a permanent ladder from the top of the north side of the shield wall to the turbine deck floor that could allow access to the LHRA. Radiation Protection (RP) procedure RP-AA-460, Controls for High and LHRA, Revision 24, provides guidance for the control of high radiation areas (HRAs). By the procedure definition of accessible area, the area was accessible after the scaffold was built, and no tools or other exceptional measures were needed to gain access. The violation was entered into Exelons corrective action program (CAP) as action request (AR) 01548397. The PD was more than minor because it is associated with the cornerstone attribute of Program and Process (RP controls), and negatively affected the Occupational Radiation Safety cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear power operation. There was also an example of this PD in example 6.g. of IMC 0612, Appendix E, Examples of Minor Issues. This example concludes that the issue is more than minor because actual dose rates in excess of the posting requirements existed in the area. LHRAs are required to be posted and controlled properly to avoid unnecessary worker exposure. The finding was evaluated using the Occupational Radiation Safety SDP and was determined to be of very low safety significance (Green) because it was not related to As Low As is Reasonably Achievable (ALARA) planning, it did not involve an overexposure, did not constitute a substantial potential for overexposure, and the ability to access dose was not compromised. The finding included a cross-cutting aspect in the area of Work Controls, Human Performance component, because Exelon did not appropriately plan the work activities and identify the potential job site conditions (radiological hazards) associated with building scaffold next to a LHRA wall.
05000277/FIN-2013004-01	2013Q3	Green	H.4 H.5	NRC identified	Inadequate EP Procedure Change Management Controls to Ensure Adequate EAL Classification and Assessment Capability for Effluent Parameters	The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulation (CFR) 50.54(q)(2) associated with 50.47(b)(4) because PBAPS failed to control emergency planning (EP) procedure changes in a manner that would ensure timely emergency action level (EAL) classification for effluent parameters. On June 27, 2013, PBAPS issued Revision 27 to EP-AA-1007, Exelon Nuclear Radiological Emergency Plan Annex for PBAPS. One of the plan changes involved removal of the \'A\' ventilation and main stack radiation monitors from radiological effluent EAL matrix Table 3-1, and thereby rendered the B ventilation and main stack radiation monitors as the only means of EAL classification for effluent releases. On July 24, 2013, the inspectors questioned shift operations on whether the ability to make timely and accurate EAL classifications was impacted with the B reactor building (RB) ventilation stack radiation monitor inoperable. Shift operations did not have an immediate response, but later in the same shift provided a response to the inspectors that compensatory measures were required for degraded EP equipment, and the \'A\' ventilation stack radiation monitor was established as a compensatory measure for the inoperable \'B\' monitor in response to questions by the inspectors. Following the inspectors questions, PBAPS initiated issue report (IR) 1539674 to capture programmatic deficiencies that were revealed as a result of the inspectors questions. PBAPS corrective actions included a revision to the PBAPS Emergency Plan, a revision to the EP compensatory measure procedure, issuance of Operations Information Update (OIU) 13-10 to the shift managers (SMs) to clarify the purpose of the compensatory measure procedure, and an assignment to incorporate the latest revision of the compensatory measure procedure into licensed operator training program curriculum review committee (CRC). This finding was more than minor because it was associated with the procedure quality attribute of the Emergency Preparedness cornerstone, and adversely affected the associated cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the public health and safety in the event of a radiological emergency. Using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and IMC 0609, Appendix B, Emergency Preparedness SDP, the inspectors determined that this finding was of very low safety significance (Green) using Table 5.4.1. Specifically, this finding rendered an EAL ineffective such that an unusual event (UE) declaration could be delayed. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Work Control, because PBAPS did not appropriately coordinate work activities by incorporating actions to address the impact of work on different job activities, and the need for work groups to communicate, coordinate, and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance (H.3(b)). Specifically, the impact of a PBAPS Emergency Plan Annex revision was not communicated properly or coordinated between the EP department and operations department, to assure that shift operations could implement compensatory measures as necessary for degraded EP equipment.
05000278/FIN-2013011-01	2013Q1	Severity level IV		NRC identified	Failure to Comply with a Posted High Radiation Area Boundary	The OI investigation, which was completed on March 14, 2013, was conducted to determine whether a PBAPS instrumentation and controls (I&C) technician deliberately failed to follow posted high radiation area (HRA) requirements when he crossed a boundary to manipulate a valve. The investigation was initiated after Exelon informed the NRC, on June 28, 2012, that the PBAPS I&C technician in question had potentially willfully failed to comply with a posted HRA boundary. This was contrary to Exelon procedures which requires, as indicated in the HRA radiation work permit (RWP), a HRA briefing prior to entering a HRA. Based on the evidence gathered during the OI investigation, the NRC concluded that on June 27, 2012, the I&C technician deliberately failed to follow posted HRA requirements when he crossed a HRA boundary during a Unit 3 High Pressure Coolant Injection (HPCI) system test. Specifically, the I&C technician crossed a posted HRA boundary and entered the Unit 3 HPCI room without a HRA briefing or the proper RWP. This conclusion was based on the I&C technicians admission to OI that he had done the wrong thing when he crossed the HRA boundary without the correct RWP; his experience and training working in the RCA; and his acknowledgement that he had alternative options that he should have chosen before violating HRA boundary requirements. The I&C technicians actions caused Exelon to violate the PBAPS Unit 3 operating license. Specifically, Technical Specification 5.4.1 requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Appendix A, dated November 1972. Regulatory Guide 1.33, Appendix A, Section G, dated November 1972, recommends procedures for control of radioactivity, including restrictions and activities in radiation areas (G.5.a), and RWPs (G.5.e). Exelon Procedure RPAA- 460, Revision 20, Section 4.3.2, requires, in part that a HRA briefing is required to enter a HRA. Because the violation was caused by the deliberate action of the I&C technician, it was evaluated under the NRCs traditional enforcement process using the factors set forth in the NRC Enforcement Policy. After careful consideration of these factors, the NRC concluded that this violation should be classified at Severity Level (SL) IV. In reaching this decision, the NRC considered that the significance of the underlying violation was minor because, while the I&C technician crossed a posted HRA boundary, the radiological conditions at the time did not actually constitute a HRA area in accordance with the regulatory definition of a HRA. However, the NRC decided to increase the significance of this violation to SL IV since it was deliberate and the NRCs regulatory program is based, in part, on licensees and their contractors acting with integrity. In accordance with Section 2.3.2 of the Enforcement Policy, and with the approval of the Director, Office of Enforcement, this issue has been characterized as a non-cited violation (NCV 05000278/2013011-01, Failure to Comply with a Posted High Radiation Area Boundary), because: (1) Exelon placed the issue in its CAP (CR No. 1382220); (2) Exelon identified the issue and immediately conducted an investigation; (3) the violation was not repetitive as a result of inadequate corrective action; and, (4) although the violation was willful, (a) Exelon identified the violation, notified the NRC, and took significant corrective and remedial actions; (b) the violation involved the acts of an individual who was not considered a licensee official with oversight of regulated activities as defined in the Enforcement Policy; and (c) the violation did not involve a lack of management oversight and was the result of the isolated action of the employee. The NRC has concluded that information regarding the reason for the violation, the corrective actions taken and planned to correct the violation and prevent recurrence, and the date when full compliance was achieved is already adequately addressed on the docket in this letter.
05000277/FIN-2013002-01	2013Q1	Green	H.14	NRC identified	Inadequate Operability Determination in Response to Power Load Unbalance Device Failure	The inspectors identified a Green finding for PBAPS\\\'s failure to follow the operability determination (OD) process described in Procedure OP-AA-108-115, Operability Determinations. Specifically, on February 24, 2013, between 6:15 a.m. and 10:30 a.m., an immediate determination of operability was not made in a timely manner, and was not initially documented in accordance with the corrective action process (CAP), following discovery that Unit 2 was operating outside of the analyzed limits specified in the core operating limits report (COLR) with the power load unbalance (PLU) circuit out of service (OOS). Consequently, operators entered the Unit 2 minimum critical power ratio (MCPR) technical specification limiting condition for operation (TS LCO) 3.2.2, Condition A, after exceeding the two-hour required action completion time. The inspectors determined that the immediate determination of operability was not performed in a matter commensurate with the safety significance of the two-hour LCO required action completion time. The inspectors determined that this was not a violation of TSs because subsequent analysis by a third party vendor determined that MCPR thermal limits were satisfied between 85 percent and 100 percent reactor power with the PLU circuit OOS on Unit 2. This finding is more than minor because it is associated with the design control attribute of the barrier integrity cornerstone and adversely affected the cornerstone objective of providing reasonable assurance that the physical design barriers (fuel cladding) protect the public from radionuclide releases caused by events. Using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, The SDP for Findings At-Power, the inspectors determined that this issue screened to Green, because it was associated only with the fuel cladding barrier. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, decisionmaking, because PBAPS did not use conservative assumptions in decision making and did not adopt a requirement to demonstrate that the proposed action was safe in order to proceed rather than a requirement to demonstrate that it is unsafe in order to disprove the action.
05000277/FIN-2012005-03	2012Q4	Green		Licensee-identified	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	Green		Licensee-identified	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	Green		Licensee-identified	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.
05000277/FIN-2012004-02	2012Q3	Green		Licensee-identified	Licensee-Identified Violation	10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as defective material and equipment, are promptly identified and corrected. Contrary to the above, PBAPS did not promptly correct defective welds in the E-3 EDG lube oil piping that were identified in 1998. Specifically, PBAPS identified partial penetration welds in Fairbanks Morse EDG lube oil pump outlet piping in response to a 1997 Part 21 notification. PBAPS corrected the defective welds on the E-2 and E-4 piping in 1998, but did not correct the defective welds on the E-3 or E-1 based on vendor testing and data provided in the Final Part 21 Notification. On September 3, 2012, PBAPS identified a leak on the E-3 lube oil pump outlet piping during surveillance testing. PBAPS subsequently declared E-3 inoperable and unavailable from September 3 to September 5, while corrective actions were performed to cut out the defective piping welds and re-weld the piping with full penetration welds. PBAPS determined the leak was a result of fatigue failure of the partial penetration weld. In 1998, PBAPS accepted the Final Part 21 Notification with no corrective action required on E-3 or E-1 based on the vendor testing and data, which did not include a vibration or fatigue analysis despite industry OE that specifically discussed vibration-induced fatigue failures of the EDG lube oil pump outlet piping at other stations with Fairbanks Morse EDGs. The inspectors reviewed PBAPSs planned corrective actions to address the E-1 partial penetration weld, and considered the scheduled repairs appropriate to the circumstances. The inspectors determined that this violation screened to Green using the Table 4a screening criteria in Appendix A of IMC 0609, SDP for Findings at Power, because there was no loss of the EDG system safety function. Because this finding is of very low safety significance, and has been entered into Exelon\\\'s CAP under IR 1408390, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000277/FIN-2012004-01	2012Q3	Green	H.5	Self-revealing	Inadequate Preplanning and Performance of Maintenance/Modifications Resulted in Unavailability of RHR B Loop	The inspectors identified a Green, self-revealing non-cited violation (NCV) of Technical Specification (TS) 5.4.1, Procedures. The inspectors determined that PBAPS did not properly preplan and perform maintenance/modifications to the Unit 2 low pressure coolant injection (LPCI) swing bus B motor control cabinet (MCC) while energized. Specifically, PBAPS did not appropriately consider the potential plant impact due to sensitive energized components within the MCC that could be activated and did not utilize sufficient physical barriers to prevent such activation. Consequently, on July 25, 2012, the B loop of the residual heat removal (RHR) system was declared inoperable and unavailable after workers pulling an electrical cable into the Unit 2 energized LPCI swing bus B MCC inadvertently contacted and actuated the LPCI inboard injection valve motor relay. The motor operated valve (MOV) relay actuation caused a potential over-thrust event and had the potential to impact the valves qualification and reliability. PBAPS conducted detailed examinations and diagnostic stroke testing on the MOV assembly and concluded that the design limits of the MOV assembly were not exceeded. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function of a single LPCI train for greater than its TS allowed outage time. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, work control, because PBAPS did not appropriately incorporate risk insights and job site conditions that could impact plant structures, systems, and components (SSCs) into its work activities. Specifically, PBAPS did not appropriately consider and reduce the potential for an over-thrust event on the B loop LPCI inboard injection valve MO-2-10-25B when performing work in the LPCI swing bus B MCC while it was energized.
05000277/FIN-2012007-01	2012Q2	Green		Licensee-identified	Licensee-Identified Violation	Licensee Event Report 0500027812011-004-00 described a modification error in which a control cable for the HPCI turbine steam supply MOV (MO-3-23-014) was routed through the same fire area the system is credited for post-fire safe shutdown. The valve is credited for post-fire safe shutdown capability for a fire in fire area 135, South CRD Equipment Room (Room 257) for Unit 3. This was a violation of Operating License Condition 2.C.(4) and 10 CFR Part 50, Appendix R, Section lll.G.2, for failure to ensure that the cable was protected per the Appendix R, lll.G.2 requirements. Contrary to the above, the control cable for the HPCI turbine steam supply MOV was routed in error during the period of time between September 2011 (RFO P3R18), and December 19, 2011. Specifically, PBAPS determined that a postulated fire in fire area 133 could cause damage to the HPCI turbine steam supply control cable and cause the HPCI pump to be unavailable. The issue was more than minor because it was associated with the protection against external events (fire) attribute of the mitigating systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined that the finding was of very low safety significance (Green), based on IMC 0609, Appendix F, Fire Protection Significance Determination Process (SDP), phase 2 screening, task number 2.3.5 because the cable was routed in conduit predominately through a transient combustible free zone. Additionally, the cable was not routed near a credible fire ignition source in the fire area. Because this finding is of very low safety significance and had been entered into Exelon\'s CAP under IR01290922, this violation is being treated as a Green, licensee-identified NCV consistent with the NRC Enforcement Policy.
05000277/FIN-2012003-03	2012Q2	Green		NRC identified	ADS SRV Actuator Diaphragm Thread Seal Leak	On September 25, 2011, while Peach Bottom Unit 3 was shut down for a scheduled refueling outage, Exelon personnel performed a routine ST on the Unit 3 71B SRV. The valve exceeded the maximum allowable leak rate for the pneumatic actuation controls associated with its ADS function, and Exelon declared SRV 71B inoperable. Exelon determined that the cause of the excessive leak rate was a failure of the 71B SRV actuator diaphragm thread seal, as a result of thermal degradation of the SRV actuator diaphragm thread seal material. The seal had been replaced during a November 2010 maintenance outage and, at that time, the SRV had passed its ST. Because no other leak testing had occurred since November 2010 (because the plant had been operating and the SRV is inside primary containment), Exelon could not assure that the SRV had been operable since the completion of the last successful leak test. Accordingly, Exelon concluded that it had not met the requirements of TS 3.5.1, Action E.1, which requires that, with one ADS valve inoperable, the licensee must return the valve to operable status within 14 days or be in Mode 3 within 12 hours. Exelon replaced the degraded 71B SRV thread seal on September 26, 2011, and the valve passed a subsequent leak test. Exelon also entered the 71B SRV failure into the CAP (IR 1268076), and, in accordance with 10 CFR 50.73(a)(2)(i)(B), submitted LER 11-003 to report to the NRC this condition prohibited by TSs. When inspected by Exelon maintenance personnel, Exelon identified that the thread seal had indications of being dry and brittle. Subsequent review by Exelon engineering personnel determined that the apparent cause of the seal leakage was the result of thermal degradation of the thread seal material. The NRC reviewed the licensees evaluation and actions related to this matter and concluded that the degraded seal condition was not caused by improper maintenance practices. Also, trend data did not indicate a potential degradation in that the same seal material had been used at PBAPS Units 2 and 3 for the last 20 years with no other failures. Further, the NRC considered that the 71B seal leakage would not have been detectable during normal plant operations, since it only occurred when the valve was actuated. Consequently, the NRC concluded that the inoperability of the 71B SRV was not within Exelons ability to foresee and correct, and therefore, did not identify any performance deficiency associated with the violation. The inspectors assessed the risk associated with the issue by using IMC 0609, Appendix G, Shutdown Operations SDP. The inspectors screened the issue, and evaluated it using Checklist 6 of IMC 0609, Appendix G, Attachment 1. SRV 71B is one of five PBAPS Unit 3 ADS reactor vessel relief valves. In order to perform the ADS system safety function, four of the five ADS SRVs are required to function. The four other ADS SRVs passed the leakage test, and would have been capable of depressurizing the reactor pressure vessel for design basis events. Therefore, during the period the 71B SRV was inoperable, the overall ADS safety function was maintained. As a result, this issue would screen as very low safety significance Because it was not reasonable for the licensee to be able to foresee and prevent the thread seal material degradation, or to have made the 71B SRV inoperability decision at an earlier time, the inspectors determined that no performance deficiency exists. Because no performance deficiency was identified, no enforcement action is warranted for this violation of NRC requirements in accordance with the NRCs Enforcement Policy. Further, because licensee actions did not contribute to this violation, it will not be considered in the assessment process or the NRCs Action Matrix.
05000277/FIN-2012003-02	2012Q2	Green		Licensee-identified	Licensee-Identified Violation	TS LCO 3.3.5.1, Condition E, requires that one inoperable channel of CS system bypass valve instrumentation be restored to operable in seven days, and, if the redundant emergency core cooling system initiation capability is inoperable, the supported feature(s) must be declared inoperable within one hour. Additionally, TS LCO 3.5.1, Condition I, requires that with two CS subsystems inoperable, LCO 3.0.3 be entered immediately. Contrary to the above, the A and D CS pump bypass valve instrumentation were both inoperable on April 18, 2012, for a period of time greater than one hour, the supported features were not declared inoperable, and LCO 3.0.3 was not immediately entered. Specifically, following discovery of the A CS pump bypass instrument inoperability during ST on April 18, 2012, the D CS pump bypass instrument was discovered to be inoperable on April 19, 2012. PBAPS determined that it was likely that the D CS instrument was also inoperable April 18, 2012, and therefore this event was reportable (see section 4OA3.3). Following successful recalibration, both switches were returned to an operable status on the day of their respective surveillance testing. The inspectors determined that this event screens to Green using the Table 4a screening criteria in Attachment 4 of IMC 0609, SDP, because there was no loss of the CS system safety function. Because this finding is of very low safety significance, and has been entered into Exelon\'s CAP under IR 1355773, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000277/FIN-2012003-01	2012Q2	Green	H.8	NRC identified	Inadequate Test Control to Demonstrate RCIC System Design Basis Start-up Response Time	The inspectors identified a NCV of very low safety significance of Title 10 Code of Federal Regulation (CFR) 50, Appendix B, Criterion XI, Test Control, because Exelon conducted unacceptable pre-conditioning of the reactor core isolation cooling (RCIC) system during response time testing. The performance deficiency was related to Exelons surveillance test (ST) procedure which required cold startup of RCIC to reach the rated pump discharge pressure and flow rate within 50 seconds. Exelon procedures required a 72 hour standby period between pump starts to ensure the pump cold start design criteria are satisfied without pre-conditioning. On numerous occasions, when the pump design parameters were not reached in less than 50 seconds on the first attempt, control room operators would routinely perform a second start attempt within a short period of time, typically less than one hour, to adjust the RCIC pump controls and attain the design values in less than or equal to 50 seconds. Exelon performed an extent of condition review of Units 2 and 3 RCIC cold start test data to ensure the current pump, valve, and flow results satisfied the response time testing requirements. The violation was entered into the corrective action program (CAP) as issue report (IR)1364066. The performance deficiency was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor Issues, example 2.a. Specifically, the RCIC cold start ST procedure was not implemented adequately to ensure that the RCIC pump design discharge pressure and flow were reached within the 50 second requirement on the first attempt. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because all of the mitigating system barrier questions in Table 4.a resulted in a no response. The finding included a cross-cutting aspect in the area of Work Practices, Human Performance component, because Exelon did not effectively communicate expectations regarding procedural compliance and personnel following procedures. Specifically, Exelon took credit for the Unit 2 ST performed on April 7, 2011, which started and shutdown RCIC three times in less than 72 hours to satisfy the response time testing acceptance criteria. On January 20, 2011, the same test was performed for Unit 3, when the RCIC system was run two times prior to satisfying the acceptance criteria. Exelon did not identify the unacceptable pre-conditioning of the RCIC system start-up time for either test because personnel did not follow the In-service Testing (IST) Program Corporate Technical Position procedure.
05000277/FIN-2012009-01	2012Q2	Severity level IV		NRC identified	Failure to perform Security post inspection and inaccurate post inspection records	10 CFR 50.9(a) requires that information required by the Commission\'s regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects. Contrary to the above, on January 16, 2011, and January 25, 2011, a security supervisor and a security officer at Peach Bottom Atomic Power Station: 1) did not perform a post inspection of a security post, in that the supervisor did not physically access the post to monitor and assess environmental conditions and to monitor the assigned security officer for signs of fatigue and inattentiveness; and, 2) created inaccurate records when the supervisor signed post inspection forms both for himself and for the security officer assigned to the posts, indicating that the post inspections had been completed when they, in fact, had not. The records were material in that they attest to the licensees ability to meet regulatory security response requirements.
05000277/FIN-2012002-04	2012Q1	Green		Licensee-identified	Licensee-Identified Violation	TS LCO 3.8.1, Condition A, requires that one inoperable offsite circuit be restored to an OPERABLE status within seven days during operational modes 1, 2 and 3. Condition G requires action, if the completion time for Condition A cannot be met, to place the unit in operational mode 3 within 12 hours. Contrary to the above, the offsite power circuit associated with transformer 00X011 was inoperable between March 18 and March 26, and May 10 and 28, 2010. Specifically, PBAPS determined that offsite power source transformers 00X011 and 00X005 were not designed with adequate physical separation to minimize, to the extent practical, a simultaneous failure per the requirements of 10 CFR Part 50, Appendix A, Criterion XVII, Electric Power Systems. The inspectors determined that this finding was very low safety significance (Green), for both Peach Bottom Units 2 and 3, in accordance with IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations (IMC 0609A) using SDP Phases 1, 2 and 3. Phase 1 screened this finding to Phase 2 because it represented a loss of the 00X011 function, between May 10 and 28, 2010 (approximately 18 days), for longer than the TS LCO of 7 days. A Region 1 SRA conducted a Phase 3 analysis because the Phase 2 analysis, conducted by the inspectors using the Peach Bottom Pre-solved Risk-Informed Inspection Notebook, did not model the loss of a single offsite circuit. The SRA used the Peach Bottom Standardized Plant Risk (SPAR) model, Version 8.18 dated September 10, 2009 and 8.17 dated July 8, 2009 for Units 2 and 3 respectively and SAPHIRE 8 to conduct the Phase 3 analysis.
05000277/FIN-2012002-03	2012Q1	Green	P.2	NRC identified	Untimely Corrective Actions Resulted in Spent Fuel Pool Boraflex Degradation Exceeding Design Limits	The inspectors identified a PD that was determined to be a finding of very low safety significance (Green) involving a NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure by PBAPS to take timely corrective action to correct a condition adverse to quality and the inability to comply with Design Technical Specification (TS) 4.3.1.1.b which requires, in part, that spent fuel pool (SFP) storage racks are designed and maintained with keff less than or equal to 0.95. Specifically, although PBAPS was aware of degradation of neutron absorbing material (Boraflex) within the SFP storage racks since at least 1996, PBAPS did not take effective measures to adequately monitor or manage the degradation to assure sufficient margin to criticality was maintained. Rather, in 2010, PBAPS deferred corrective actions in the SFPs until 2014 based on an operability determination (OD) that concluded sufficient margin would exist until that time. However, the NRC concluded that the OD did not accurately project the rate of boron degradation, and used several non-conservative assumptions. In June 2011, after addressing the errors in the OD, PBAPS declared 117 spent fuel bundle rack storage cells inoperable since the estimated Boraflex degradation indicated that PBAPS had exceeded design TS 4.3.1.1.b. The PD was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor Issues, Example 3.j, which considers that an issue is more than minor if an engineering calculation error results in a condition where there is now a reasonable doubt on the operability of a system or component, or if significant programmatic deficiencies were identified with the issue that could lead to more significant errors if uncorrected. Using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, the inspectors attempted to evaluate the risk significance of this issue. Applying the guidance in Table 3b, the inspectors made the assumption that the risk associated with this PD most appropriately impacted the Initiating Events cornerstone. A Region I Senior Reactor Analyst (SRA) determined that there were no probabilistic risk assessment tools currently available to adequately assess the risk of a SFP criticality event. Consequently, the inspectors followed the guidance in the Phase 1 SDP screening worksheet, Table 3b, Step 6, which states, in part, that where the SDP guidance is not adequate to provide reasonable estimates of a findings significance, use IMC 0609, Appendix M, SDP Using Qualitative Criteria. Using Appendix M, the inspectors identified criteria and associated considerations that supported the overall qualitative risk assessment. On April 3, 2012, a Significance and Enforcement Review Panel (SERP) was conducted involving staff from Region I, the Office of Nuclear Reactor Regulation, and the Office of Enforcement to discuss the significance of this event. The SERP determined the PD and subsequent consequences resulted in a condition of very low safety significance (Green), based on an assessment using Appendix M attributes. This finding was also determined to have a cross-cutting aspect in the area of Problem Identification and Resolution - Evaluation (P.1(c)). Specifically, Exelon did not properly evaluate a condition adverse to quality for operability in that the 2010 OD did not accurately predict the rate of Boraflex degradation and whether the issue challenged current SFP operability.
05000277/FIN-2012002-02	2012Q1	Green	P.2	Self-revealing	Inadequate Corrective Action to Address Residual Heat Removal Heat Exchanger Graphite Gasket Leaks	The inspectors determined that PBAPS did not promptly identify and correct residual heat removal (RHR) heat exchanger (HX) graphoil gasket leaks. The PD constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. Specifically, measures established to identify and correct previous graphoil gasket leaks were inadequate to correct the condition adverse to quality. Consequently, on February 16, 2012, the Unit 2 \'C\' RHRHX shell cover lower flange graphoil gasket failed during testing, rendering the \'C\' RHR subsystem inoperable. PBAPS entered this issue into CAP via IR 1327477. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events and prevent undesirable consequences. Using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, the inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function for a single RHR train for greater than its TS allowed outage time, and did not screen as potentially risk significant due to an external initiating event. The inspectors determined that this finding had a cross-cutting aspect in the area of PI&R, CAP, because PBAPS did not thoroughly evaluate previous graphoil gasket failures used in RHR HX applications to ensure the resolution addressed the cause and extent of condition.
05000277/FIN-2012002-01	2012Q1	Green	P.3	Self-revealing	Inadequate Corrective Action to Address Emergency Diesel Generator Control Power Circuit Chronic Internal Faults	The inspectors determined that PBAPS did not establish measures to promptly identify and correct a condition adverse to the quality related to the emergency diesel generator (EDG) control power circuit. The performance deficiency (PD) constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. Specifically, measures established to identify and correct chronic control power light socket assembly internal faults were inadequate. Consequently, on February 18, 2012, the E-1 EDG local control power station experienced a short circuit event during control power indicating light bulb replacement. PBAPS entered into this issue into the corrective action program (CAP) via issue report (IR) 1328736. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating System cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events and prevent undesirable consequences. Using IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, the inspectors determined that this finding was of very low safety significance (Green) because it did not represent an actual loss of safety function for a single EDG train for a duration greater than its Technical Specification (TS) allowed outage time, and did not screen as potentially risk significant due to an external initiating event. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification & resolution (PI&R), CAP, because PBAPS did not take appropriate corrective actions to address the adverse trend associated with chronic EDG control power circuit faults in a timely manner, commensurate with its safety significance
05000277/FIN-2011005-04	2011Q4	Green		Licensee-identified	Licensee-Identified Violation	TS LCO 3.5.1, Condition A, requires that one inoperable low pressure ECCS injection subsystem should be restored to an OPERABLE status within seven days during operational modes 1 and 2, or requires action to place the unit in operational mode 3 within 12 hours. Contrary to the above, the \'D\' LPCI pump was inoperable during a period of time between April27, 2O1O, and October2, 2011. Specifically\' PBAPS determined that the leaking relief valve body, as identified on April 27,2010, could have become detached from the \'D\' RHR suction piping during the worst case design basis seismic event. This condition would result in the \'D\' RHR pump being inop6rable, thereby affecting the RHR LPCI function. Because the \'B\' RHR pump was unaffected by this even-t, there was no total loss of the \'B\' LPCI train safety function. The inspectors determined that this event screens to Green using the Table 4b seismic screening criteria in Attachment 4 of IMC 0609, SDP. Because this finding is of very low safety significance and has been entered into Exelon\'s CAP under lR i264g09, this violation is being treated as a Green, licensee-identified NCV consistent with the NRC Enforcement Policy
05000277/FIN-2011005-03	2011Q4	Green		Licensee-identified	Licensee-Identified Violation	TS b.4.1 states, in part, that written procedures shall be implemented a1d maintained as recommended in RC 1.33, Appendix A, November 1972. RG 1\'33, Appendix A\' Section l, procedures for Performing Maintenance, subsection 1, states the following: Maintenance which can affect the performance of safety-related Equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances\' Skill, notably possessed by qualified maintenance personnel may not require detailed step--by-step delineation in a procedure. Contrary to the above,. PBAPS did not properly preplan and perform maintenance which affected the E-1 EDG\' Specifically, PBAPS determined that a damaged lubricating oil drain line should have been identified and replaced during planned maintenance activities prior to the occurrence of leakage. As a consequence of not identifying and replacing the damaged drain line, PBAPS determined that the E-1 EDG was unable to perform its 24-hour mission time, and therefore was inoperable, during the period of time between April27 , 2011, and September 23, 2011\' The finding was determined to be of very low safety significance, for both Peach Bottom Units 2 and 3, in accordance with lMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations (lMC 06094) using SDP phase s 1,2 and 3. Phase 1 screened the finding to Phase 2 because it represented a loss of the E-1 EDG safety function, between April27 and September 23, 2011 (149 days), longer than the TS limiting condition for operation (LCO) of 14 days. A Region I senior Reactor Analyst (SRA) conducted a Phase 3 analysis because the Phase 2 analysis, conducted by the inspectors using- the Peach Bottom pre-solved Risk-Informed Inspection Notebook, indicated that the finding could be more than very low significance\' The SRA used the peach Bottom Standardized Plant Analysis Risk (SPAR) model, Revision 8.19 and 8.17, for units 2 and 3 respectively and SAPHIRE 8 to conduct the phase 3 analysis, with the conservative assumption that the E-1 EDG would not have operated at all for its 24 hour mission time over the 149 day exposure period\' This analysis was conservative given the EDG could have operated for over two hours assuming that the drain line broke and the potential that operators could have temporarily limited the leakage from the supercharge lube oil drain line. This analysis indicated an increase in core damage frequency (CDF) for internal initiating events in the range of one core damage accident in 2,500,000 years of reactor operation, in the low E-7 range per year for each unit. The dominate core damage sequences included losses of offsite power with the failure of all EDGs resulting in a station blackout (SBO), followed by the failure of operators to reduce direct current loading to allow extended operation of the RCIC system and - depressurize the realtor, and with inability to recover offsite power, the SBO source of power from the Conowingo Dam or an EDG in two hours. In accordance with IMC 0609A, for a finding with an internal events ACDF above 1E-7, the SRA assessed the impact of the finding on: 1) External events such as fire, seismic and flooding, determining, using the external events portion of the Peach Bottom Unit 2 and 3 SPAR models, that the total ACDF (internal plus external) would not be above the 1 E-6 threshold; and 2) the increase in large early release frequency (ALERF)\' determining that given the operators ability, following core damage, to recover offsite power and depressurize and inject water to the reactor from low pressure sources and to flood the containment that the ALERF was in the low E-8 per year range\' Because this finding is of very low safety significance and has been entered into Exelon\'s CAP under lR 1266b37, this violation is being treated as a Green, licensee identified NCV consistent with the NRC Enforcement Policy.
05000277/FIN-2011005-02	2011Q4	Green	H.8	NRC identified	Failure to Establish, Implement, and Maintain Adequate QA for Effluent and Environmental Monitoring	The inspectors identified a Green finding associated with the failure to establish, implement, and maintain adequate quality assurance (QA) program elements in the area of effluent and environmental monitoring as required by Peach Bottom, Units 2 and 3 Technical Specification (TS), Section 5.4.1. Specifically, Exelon\\\'s QA program for effluent and environmental monitoring was not sufficient to ensure: 1) that both adequate and timely evaluation and assessment of changes described in the Public Land Use Census were conducted for purposes of dose validation and sampling program modification; 2) that changes in meteorological parameters, used for public dose projections and assessment, were promptly and adequately evaluated; and 3) that laboratory QA programs for effluent and environmental sample analysis measurement systems were adequate and implemented properly. Exelon placed these issues in its CAP as Action Requests (ARs): 1226969, 1226202,1299543, 1299476,1302720, and 1303308. The finding is more than minor because it is associated with the Public Radiation Safety cornerstone attribute of programs and processes and adversely affected the associated cornerstone objective in that failure to establish, implement, and maintain an adequate QA program in the effluents and environmental monitoring program area adversely affected the licensee\\\'s ability to ensure adequate protection of public health and safety. The finding was assessed for significance using IMC 0609, Appendix D, and determined to be of very tow safety significance (Green) because: the issue was contrary to TSs and is a radioactive effluent release program deficiency; there was no indication of a spill or release of radioactive material on the licensee\\\'s site or to the offsite environs that would impact public dose assessment, and there was no substantial failure to implement the radioactive effluent release program. The licensee re-assessed the dose to members of the public from routine releases and determined that projected doses did not, nor were likely to, exceed applicable limits, including as low as is reasonably achievable (ALARA) design specifications of 10 CFR Part 50, Appendix l; or 10 CFR 20.1301(e). The cause of this finding is related to the cross-cutting area of Human Performance, Work Practices, Aspect H.4(b) because the licensee did not ensure Personnel followed procedure compliance requirements activities for effluent and environmental monitoring program.
05000277/FIN-2011005-01	2011Q4	Green	P.3	NRC identified	Untimely Corrective Action to Correct MOV Degraded Stem Lubrication	The inspectors determined that Exelon\'s failure to promptly correct a condition adverse to quality associated with a safety-related motor-operated valve (MOV) constituted a Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XVl, Corrective Action. Specifically, corrective actions to prevent recurrence of MOV program testing failures due to degraded stem lubrication in 2009 were not performed in a timely manner to prevent the inoperability of a safety-related MOV due to degraded lubrication, as identified on September 22, 2011. PBAPS entered this issue into the CAP via issue reports (lRs) 1266600 and 1266604. This finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity (Bl) cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the Unit 3 reactor water cleanup (RWCU) outboard isolation valve MO-3-12-018 did not develop sufficient thrust at the torque switch trip setpoint during diagnostic testing on September 22, 2011. The RWCU MOV would not have been able to perform its safety function to close during the most limiting design condition. Using the Phase \'1 worksheet in Appendix 4 of IMC 0609, SDP, the finding affected the Bl cornerstone and was of very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of containment. This finding had a cross-cutting aspect in the area of Problem ldentification & Resolution (PI&R), CAP, because Exelon did not take appropriate corrective actions to address the adverse trend of degraded stem lubrication on a safety-related MOV in a timely manner
05000277/FIN-2011502-02	2011Q3	Green		NRC identified	Changes to EAL Basis Decreased the Effectiveness of the Plan without Prior NRC Approval	The inspector identified a finding of very low safety significance involving a Severity Level IV NCV of 10 CFR 50.54(q) for failing to obtain prior approval for an emergency plan change which decreased the effectiveness of the plan. Specifically, the licensee modified the Emergency Action Level (EAL) Basis in EAL HU6, Revision 13, which indefinitely extended the start of the 15-minute emergency classification clock beyond a credible notification that a fire is occurring or indication of a valid fire detection system alarm. This change decreased the effectiveness of the emergency plan by reducing the capability to perform a risk significant planning function in a timely manner. The violation affected the NRC\\\'s ability to perform its regulatory function because it involved implementing a change that decreased the effectiveness of the emergency plan without NRC approval. Therefore, this issue was evaluated using Traditional Enforcement. The NRC determined that a Severity Level IV violation was appropriate due to the reduction of the capability to perform a risk significant planning standard function in a timely manner. The licensee entered this issue into its corrective action program and revised the EAL basis to restore compliance. The finding was more than minor using IMC 0612, because it is associated with the emergency preparedness cornerstone attribute of procedure quality for EAL and emergency plan changes, and it 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. Therefore, the performance deficiency was a finding. Using IMC 0609, Appendix B, the inspector determined that the finding had a very low safety significance because the finding is a failure to comply with 10 CFR 50.54(q) involving the risk significant planning standard 50.47(b)(4), which, in this case, met the example of a Green finding because it involved one Unusual Event classification Due to the age of this issue, it was not determined to be reflective of current licensee performance and therefore a cross-cutting aspect was not assigned to this finding.
05000277/FIN-2011010-01	2011Q3	Green	P.3	NRC identified	Inadequate Corrective Actions Associated With SRV Lift Setpoint Drift	The inspectors identified a finding of very low safety significance (Green) involving a NCVof 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, because Exelon staff did not implement timely corrective action associated with safety relief valve (SRV)/safety valve (SV) lift setpoint drift in excess of Technical Specification (TS) 3.4.3, Safety Relief Valves and Safety Valves requirements. Specifically, Exelon staff did not implement timely or adequate actions to correct SRV lift setpoint drift that, on four occasions since 2004, has exceeded TS acceptance criteria and resulted in repeat TS violations. The station entered this issue into their corrective action program (CAP) as issue report (IR) 1250472 to evaluate the corrective actions needed to address this issue including evaluation of the proposed revision to the Peach Bottom licensing basis through a TS amendment. The inspectors determined that 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 of ensuring the capability and reliability of systems that respond to initiating events to prevent undesirable consequences (Le., core damage). Specifically, SRVs continue to experience reliability challenges regarding SRV/SV lift setpoint drift and the station remains vulnerable to future TS compliance issues. The inspectors evaluated the significance of this finding using IMC 0609.04, Phase 1 -Initial Screening and Characterization of Findings. The inspectors determined that this finding was of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of safety system function, and did not screen as potentially risk-significant due to external initiating events. The inspectors\' review did not identify a loss of SRVlSV safety function with regard to SRVs/SVs being able to lift within the necessary pressure range to maintain margin to design pressure and stress limits. The finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because Exelon personnel did not implement timely corrective actions to address a longstanding SRV tolerance setpoint condition that has resulted in multiple TS compliance violations.
05000277/FIN-2011004-01	2011Q3	Green		Licensee-identified	Licensee-Identified Violation	10 CFR, Part 50, Appendix B, Criterion III requires, in part, that measures shall be established to assure that the design basis for those SSCs that mitigate the consequences of postulated accidents are correctly translated into procedures. Contrary to the above, PBAPS did not ensure that the CS system required flow of 6,874 gallons per minute (gpm) was correctly translated into Emergency Operating Procedure T-111, Level Restoration, to ensure long term core cooling following a loss of coolant accident. The 6,874 gpm flowrate was determined by engineering analysis to account for the 624 gpm leakage through the CS sparger headers and into the reactor vessel annulus region, thereby bypassing long-term cooling of the fuel in the core shroud region. The inspectors determined that this finding was of very low safety significance (Green) in ac ordance with NRC IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, Mitigating Systems cornerstone, because the finding did not result in the actual loss of safety function. PBAPS engineering review of quarterly surveillance tests for the last three years determined that the CS pumps have more than sufficient margin to account for the leakage. The inspectors verified the determination through an independent inspection sampling of surveillance test data. This finding has been documented in I the CAP under IR 1245207.
05000277/FIN-2011502-01	2011Q3	Severity level IV		NRC identified	(Traditional Enforcement) Changes to EAL Basis Decreased the Effectiveness of the Plan without Prior NRC Approval	The inspector identified a finding of very low safety significance involving a Severity Level IV NCV of 10 CFR 50.54(q) for failing to obtain prior approval for an emergency plan change which decreased the effectiveness of the plan. Specifically, the licensee modified the Emergency Action Level (EAL) Basis in EAL HU6, Revision 13, which indefinitely extended the start of the 15-minute emergency classification clock beyond a credible notification that a fire is occurring or indication of a valid fire detection system alarm. This change decreased the effectiveness of the emergency plan by reducing the capability to perform a risk significant planning function in a timely manner. The violation affected the NRC\\\'s ability to perform its regulatory function because it involved implementing a change that decreased the effectiveness of the emergency plan without NRC approval. Therefore, this issue was evaluated using Traditional Enforcement. The NRC determined that a Severity Level IV violation was appropriate due to the reduction of the capability to perform a risk significant planning standard function in a timely manner. The licensee entered this issue into its corrective action program and revised the EAL basis to restore compliance. The finding was more than minor using IMC 0612, because it is associated with the emergency preparedness cornerstone attribute of procedure quality for EAL and emergency plan changes, and it 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. Therefore, the performance deficiency was a finding. Using IMC 0609, Appendix B, the inspector determined that the finding had a very low safety significance because the finding is a failure to comply with 10 CFR 50.54(q) involving the risk significant planning standard 50.47(b)(4), which, in this case, met the example of a Green finding because it involved one Unusual Event classification Due to the age of this issue, it was not determined to be reflective of current licensee performance and therefore a cross-cutting aspect was not assigned to this finding.
05000277/FIN-2011003-01	2011Q2	Green		Licensee-identified	Licensee-Identified Violation	In Mode 1, with the HPCI system inoperable for more than 14 days, TS Limiting Condition for Operation 3.5.1 requires the unit to be in Mode 3 within 12 hours. Contrary to the above, the Unit 2 HPCI system was determined to be inoperable from approximately January 20 to March 18, 2011, with the reactor in Mode 1, due to a leaking relief valve (RV-2-238-066) on the HPCI cooling water header. With HPCI aligned to the normal, non-safety-related, Condensate Storage Tank (CST) suction source, no voiding would occur in the HPCI discharge piping due to the higher elevation of the CST. However, during a subset of design basis events where HPCI suction would be transferred to the suppression pool, its alternate and safety-related suction source, and the HPCI pump secured, voiding could develop in the discharge piping. The licensee concluded that if HPCI was then restarted, a water hammer condition could potentially result and render Unit 2 HPCI unable to perform its deterministic design function. The voiding in the HPCI discharge piping had been discovered by PBAPS personnel during a ST while transferring Unit 2 HPCI suction from the CST to the suppression pool to support an l&C surveillance. The relief valve was replaced, and subsequent to testing, HPCI was declared operable on March 18, 2011. The inspectors reviewed this condition using IMC 0609, Attachment 4, and in consultation with a Region I Senior Reactor Analyst (SRA), concluded the Unit 2 HPCI system would likely have been able to perform its Significance Determination Process safety function, given the numerous postulated equipment failures and specific system configurations that would have to occur to cause a system failure. Therefore, and as such this issue screened to very low safety significance. A Region I SRA also confirmed the very low significance (mid E-9 increase in core damage frequency) with a conservative analysis. This analysis assumed the HPCI system would have failed if the operators failed to refill the CST, and HPCI switched over to the torus suction, for the 58 day exposure period. The licensee documented the event in their CAP as lRs 1 1 88457 and 1 188987. The LER associated with this event was documented in Section 4OA3.
05000277/FIN-2011403-01	2011Q1	Green	H.8	NRC identified	Security
05000277/FIN-2011007-02	2011Q1	Green	P.2	NRC identified	Temporary Battery Cart Seismic Configuration Deficiency	The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that Exelon did not verify the adequacy of the seismic design for temporary battery cells that had been placed in-service in safety-related station batteries that were required to be operable. Specifically, Exelon did not evaluate whether mechanical stress could be transferred from one temporary battery cell to another via rigid bus bars attached to the cell terminal posts and, as a consequence, did not verify that damage to a cell post or cell case would not result during a seismic event. During the inspection period, the temporary battery cells were not in-service and were not required to be operable. In response, Exelon entered this issue into the corrective action program and performed a preliminary calculation to verify seismic adequacy. This finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 SDP screening, in accordance with NRC IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because it was a design or qualification deficiency confirmed not to result in loss of operability or functionality. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because Exelon did not thoroughly evaluate the problem such that the resolution addressed the cause. Specifically, a 2009 issue report identified that the battery cells on the cart did not have seismic spacers between the cells and did not have steel tie-rods installed for a cell clamp assembly, similar to the station battery. The issue report incorrectly determined that plastic tubes in between the two cells would provide an adequate seismic restraint.
05000277/FIN-2011007-01	2011Q1	Green		NRC identified	Failure to Demonstrate the Capability of the EDG Fuel Oil Transfer Pumps to Fulfill Their Safety Functions Under all Postulated Conditions	The team identified a finding of very low safety significance involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that, Exelon did not ensure the ability to transfer fuel oil between underground fuel oil storage tanks. Specifically, Exelon had not performed adequate analyses or testing to demonstrate adequate net positive suction head available (NPSHA) for the EDG fuel oil transfer pumps. In response, Exelon entered this issue into their corrective action program and performed an evaluation to assure the fuel oil transfer pump NPSHA was adequate. The finding was more than minor because it was associated with the design control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team performed a Phase 1 SOP screening, in accordance with NRC IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because it was a design or qualification deficiency confirmed not to result in loss of operability or functionality. This finding does not have a crosscutting aspect because the most significant contributor of the performance deficiency is not reflective of current licensee performance.
05000277/FIN-2011002-03	2011Q1	Green		Licensee-identified	None	TS LCO 3.4.3 requires the safety function of 11 valves (any combination of SRVs and SVs) to be operable during operational Modes 1,2, and 3 or else be in Mode 3 within 12 hours and in Mode 4 within an additional 36 hours. Contrary to the above, two SRVs and one SV were determined to have their as-found setpoints in excess of the TS allowable tolerance, thus leaving 10 operable SRVs and SVs. The SRVs and SVs were replaced with refurbished valves for the 19th Unit 2 operating cycle. Additionally, LER 2-10-3 stated that PBAPS will pursue a change to the plant\'s licensing bases to increase SRV and SV setpoint tolerances to the ASME Code allowable + 3 percent tolerance. The licensee documented the event in JR 1120516. Since there was no actual loss of safety function as a result of this event, this issue is of very low (Green) safety significance. The LER associated with the event was documented in Section 40A3.2.
05000277/FIN-2011002-02	2011Q1	Green		Licensee-identified	None	In Modes 1, 2 and 3, with one ESW subsystem inoperable for more than seven days, TS Limiting Condition for Operation (LCO) 3.7.2, condition C, requires the unit to be in Mode 3 within 12 hours and in Mode 4 within 36 hours. Contrary to the above, since original construction and prior to September 13, 2010, an engineering evaluation determined that the \'A\' ESW subsystem was inoperable due to the degraded seismic capability of rod hanger 33HB-S143 that only affected the \'A\' ESW subsystem. During upgrades to the ESW discharge pipe support system during the week of September 13, 2010, PBAPS personnel identified that the original installation of the rod hanger had not been carrying adequate pipe load. This condition was considered as a condition prohibited by TS due to one subsystem of ESW being inoperable for greater than the time period allowed by TS. The cause of the event was due to an inadequate design drawing. PBAPS documented this issue in the CAP as IRs 1114812 and 1118711. Since there was no actual Joss of safety function as a result of this event, this issue is of very low (Green) safety significance. The LER associated with the event was documented in Section 40A3.1.
05000277/FIN-2011002-01	2011Q1	Green	H.11 H.12	Self-revealing	FH Procedures Were Inadequate to Prevent Fuel from Contacting an Obstruction	A Green self-revealing NCV of Technical Specification (TS) 5.4.1 Procedures was identified, because PBAPS\'s procedures for refueling equipment operation and core alterations were inadequate to prevent a fuel bundle from contacting a core spray inspection (CSl) submarine device while the fuel bundle was being transported from the core to the spent fuel pool (SPF). In particular, system operating (SO) procedure 18.1.A-2, Operation of Refueling Platform, and fuel handling (FH) procedure 6C, Core Component - Core Transfers, did not provide sufficient procedure steps, precautions, or human performance tools to prevent contact while the refueling platform was operated in the automatic mode and when core components were in close proximity to obstructions and interferences. The inspectors determined that the finding was more than minor because the finding was associated with the Procedure Quality attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone\'s objective to provide reasonable assurance that physical design barriers (i.e., fuel cladding) protect the public from radionuclide releases caused by accidents or events. Although no fuel damage occurred during this event, the inadequate procedure resulted in a FH event that could have impacted the cladding and affected the cornerstone\'s objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. IMC 0609, SDP, Attachment 0609.04, Phase 1-lnitial Screening and Characterization of Findings, was used to evaluate the significance of the finding. Attachment 0609.04, Table 4a, was used to evaluate the impact of the finding on fuel clad integrity. Appendix G was considered for the evaluation, but was not used because it does not directly address fuel clad integrity. Based on the results of fuel sipping done in February 2011, PBAPS concluded that there was no damage to the clad integrity of the impacted fuel bundle that was permanently discharged to the SFP. Since the finding did not affect SFP cooling or inventory and since there was no damage to fuel clad integrity from the impact with the CSI submarine, the finding was determined to be of very low safety significance (Green). The finding has a cross-cutting aspect in Human Error Prevention Techniques in the Work Practices component of the Human Performance area. Specifically, PBAPS FH procedures did not require human error prevention techniques that were commensurate with the risk of moving fuel in close proximity to obstructions and interferences. (H.4(a))
05000277/FIN-2010004-02	2010Q3	Green		NRC identified	Potentially Inadequate Fuel Handling Procedures Lead to Personnel Performance Errors While Handling Fuel	The inspectors identified an URI related to potential procedure inadequacy issues that allowed inadequate coordination of simultaneous close proximity activities within the reactor vessel and personnel performance error issues while handling fuel in the reactor core and the SFP. These events appear to be examples where inadequate procedures contributed to fuel handling issues. This issue will remain unresolved pending completion of PBAPS\\\'s investigation and cause evaluation processes under the CAP. On September 18, 2010, during Core Shuffle I, the safety spotter had to stop the refueling bridge to avoid contact with the CS inspection (CSI) submarine. On September 19,2010, during the execution of fuel move 302 of Core Shuffle I, a discharged fuel bundle (JLM491), that had been picked up from the core, came in contact with the CSI submarine as the refueling bridge began transiting to the SFP (IR 1115041). Both fuel movement and NOEs using a remotely operated vehicle (CSI submarine) were being conducted within the same core quadrant. On September 24, 2010, during preparations for Core Shuffle II, a dummy fuel bundle came in contact with a discharged fuel bundle at location JJ-37 in the SFP while the refueling bridge\\\'s mast was being lowered over an occupied storage cell using the travel override pushbutton (IR 1115041). At the time, the mast was being exercised in accordance with a refuel bridge ST. At the end of the inspection period, PBAPS\\\'s causal analysis activities were still in progress; therefore, this item remains unresolved: URI 05000277, 278/2010004- 02, Potentially Inadequate Fuel Handling Procedures Lead to Personnel Performance Errors While Handling Fuel.
05000277/FIN-2010004-03	2010Q3	Green		NRC identified	Failure to Ensure Adequate Voltage was Available to Safety-Related Equipment	The inspectors identified a finding of very low safety significance involving a NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, in that Exelon did not assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, Exelon did not use the safety-related Function 4 degraded grid relay trip setpoint specified in the Technical Specifications (TS) as a design input in calculations to ensure adequate voltage was available to all safety-related components required to respond to a design basis loss-of-coolant accident (LOCA). Instead, Exelon used the results from calculation PE 0121, Voltage Regulation Study, to establish the voltage level for system operability. The study credited the use of non-safety related equipment to raise the voltage level. This allowed higher voltages to be used in the design calculations for components than would be allowed by the TS setpoint. The team verified the licensing basis via Task Interface Agreement (TIA) 2009-07 and informed Exelon that the degraded grid relay setpoint must be used for design basis calculations. Exelon entered the issue into the CAP (IR 1119440), performed operability assessments, and established some compensatory measures to restore PBAPS to an operable but nonconforming condition. The finding is more than minor because it is associated with the design control attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was also similar to example 3j in IMC 0612, Appendix E, in that there was reasonable doubt as to the operability of safety-related components and Exelon was required to perform operability determinations to address potentially inadequate voltage to several safety-related components. The inspectors, including the Region I Senior Reactor Analysts (SRAs), performed a Phase 1 SOP screening, in accordance with NRC IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because it was a design deficiency that impacted operability but not functionality, did not represent a loss of system safety function, did not represent an actual loss of safety function of a single train, and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. There was no cross-cutting issue associated with the finding because the degraded grid relay setpoints had been most recently evaluated in 2004 and the issue was not reflective of current performance.
05000277/FIN-2010004-01	2010Q3			NRC identified	Non-conservative TS and Potential Non-compliance Associated with Degraded SFP Boraflex Panels	The inspectors identified an unresolved item (URI) related to issues of concern with the degrading Boraflex panels in the PBAPS SFPs. Additional information and specialized technical support from the NRC\\\'s Office of Nuclear Reactor Regulation (NRR) are required to determine whether a performance deficiency exists. Specifically, NRR will be requested to provide a technical review of the PBAPS\\\'s operability determination ((00) 10-007) to determine if it is technically sufficient and to confirm the time limitations associated with the referenced technical evaluation. This will support an evaluation of whether PBAPS\\\'s corrective actions to address the non-conservative TS (4.3.1.1.a) associated with the design limit for peak in-core reactivity (k-infinity) of spent fuel have been timely when judged against the standards established in NRC Administrative Letter (AL) 98-10, Dispositioning of TSs That Are Insufficient To Assure Plant Safety, and the requirements in 10 CFR 50, Appendix B, Criterion XIV, Corrective Actions. Additionally, the inspectors will use the results of the NRR technical review to determine whether the PBAPS 00 has demonstrated with reasonable assurance that the subcritical margin limit for the SFP as specified by TS 4.3.1.1.b (K-effective\\\': 0.95) will continue to be met through the time limit established in the technical evaluation and until the licensee\\\'s specified corrective actions can be completed. The current technical evaluation concludes that with administrative limits on the reactivity of the fuel added to SFPs, K effective will conservatively remain below 0.95 until approximately 2014. Since 1996, PBAPS has known that the Boron-10 (B-10) neutron absorber used in the Units 2 and 3 SFPs\\\' racks had begun a degrading trend. Specifically, the degradation caused some of the Boraflex neutron absorber material imbedded in the rack panels to fall below the minimum certified B-10 density of 0.021 grams B-10 per square centimeter (g/cm2). The panels had degraded from the as-manufactured average areal density of 0.0235 g/cm2that was 11.9 percent greater than minimum certified density. In response to degrading trends, PBAPS secured analyses from AEA Technology and NET Co that quantified the reactivity effects associated with varying degrees of B-1 0 density loss in the Westinghouse racks. The reactivity penalty derived from this analysis was transposed into Global Nuclear Fuel (GNF) SFP criticality analyses. PBAPS asserted that these analyses were incorporated into the plants\\\' licensing and design bases through the 10 CFR 50.59 process. However, none of these methods have been reviewed and approved by the NRC for application at Peach Bottom. In 2007, PBAPS recognized that the B-1 0 degradation of the Units 2 and 3 SFPs storage was projected to exceed the 10 percent loss limit (0.0189 g/cm2) established by the AEA Technology, NETCo, and GNF analytical methods. PBAPS also recognized that the K infinity value in TS (4.3.1.1.a) would become non-conservative and the guidance in NRC AL 98-10, Dispositioning of TSs That Are Insufficient to Assure Plant Safety, would apply. Subsequently, PBAPS submitted a license amendment request (LAR) to change the Kinfinity value in the TS. In response to issues raised by the NRC\\\'s technical reviewers, PBAPS made several supplemental submittals to the LAR before it was withdrawn by a letter dated June 18, 2010 (ML 101690377). Subsequently, PBAPS developed 00 10-007 to address the non-conservative TS (4.3.1.1.a). The 00 evaluated the acceptability of storing fuel bundles in the Unit 2 and 3 SFP storage racks with a minimum B-10 average areal density of 0.01155 gm/cm2, which is 55% of 0.021g/cm2 (45% degradation). In comparison, it is noted that the most degraded panel in either units\\\' SFP storage racks was measured in January 2010, to be degraded to an areal density of 0.0169 g/cm2 (19.5 percent of 0.021g/cm2 ) and has been projected to have degraded to 0.0146 g/cm2 (30.5 percent of 0.021g/cm2 ) on November 1, 2010. The degradation projections have been made by the RACKLIFE version 2.0 computer modeling program; however, it is noted that the licensee plans to convert to version 2.1 of RACKLIFE program. The OD referenced and relies on Revision 3 of a technical evaluation (IR 864431-15, and two previous revisions) that PBAPS has used since 2009 to justify continued operability of the SFPs and to show that the SFP will be maintained 5% subcritical (Keff $ 0.95). The basis for the approach in these documents was to reduce the design basis limiting fuel assembly reactivity to a maximum Kinfinily of 1.26. The current technical evaluation concludes that with administrative limits on the reactivity of the fuel added to SFPs, K effective will conservatively remain below 0.95 until the maximum B-10 density depletion reaches approximately 45 percent in 2014. As an additional compensatory measure, PBAPS plans to remove from service any SFP storage rack panels with Boraflex degraded more than 45 percent. PBAPS\\\'s current plans are to submit a new LAR in late 2011. The inspectors reviewed OD 10-007 and concluded that assistance from NRR was needed to determine the technical adequacy and correctness of the licensee\\\'s operability evaluation and to confirm the time limitations associated with the referenced technical evaluation. This assistance is needed by the region to determine whether one or more performance deficiencies exist. Specifically, to evaluate whether PBAPS\\\'s corrective actions to address the non-conservative TS (4.3.1.1.a) associated with the design limit for peak in-core reactivity (k-infinity) of spent fuel have been timely when judged against the standards established in NRC AL 98-10, Dispositioning of TSs That Are Insufficient To Assure Plant Safety, and the requirements in 10 CFR 50, Appendix B, Criterion XIV, Corrective Actions. Additionally, the inspectors will use the results of the NRR technical review to determine whether the PBAPS OD has demonstrated with reasonable assurance that the subcritical margin limit for the SFP as specified by TS 4.3.1.1.b (K-effectives. 0.95) will continue to be met through the time limit established in the technical evaluation and until the licensee\\\'s specified corrective actions can be completed. The inspectors plan to submit their technical questions to NRR in accordance with Office Instruction, COM-106, Control of Task Interface Agreements. Therefore, this issue remains unresolved pending NRR\\\'s response to the TIA and subsequently inspector review. URI 05000277, 278/2010004-01, Non-conservative TS and Potential Noncompliance Associated with Degraded SFP Boraflex Panels.
05000277/FIN-2010003-01	2010Q2	Green		Licensee-identified	Licensee-Identified Violation	License Condition 2.C.(11).(b) requires, in part, that PBAPS shall develop and maintain strategies for addressing large fires and explosions. On May 11, 2010, the licensee discovered that equipment used for a single mitigation strategy, described in TSG-4.1, Attachment 15, had been removed from its designated location. The finding was assessed in accordance with IMC 0609, Appendix L, Table 2, and determined to be of very low (Green) safety significance because the finding only impacted an individual mitigation strategy. The licensee restored the equipment and entered the issue into their CAP as IR 01068128.
05000277/FIN-2010009-01	2010Q2	Severity level IV		Self-revealing	Inaccurate Personnel History Questionnaire	a former contract outage employee at Peach Bottom deliberately failed to disclose on a Personal History Questionnaire (PHQ), a previous, non-nuclear employment from which he had been terminated for a positive FFD test, in order to gain unescorted access (UA) to Peach Bottom. As a result of the investigation, the NRC determined that, on September 8, 2008, the contract employee did fail to disclose his prior employment with the non-nuclear company on the PHQ, and also failed to provide information about the positive FFD test. However, after considering the information developed during the investigation, the NRC concluded that it did not have sufficient evidence to conclude that the individuals failures were deliberate. Nonetheless, as a result of these failures by the contract employee, Exelon granted the individual UA to Peach Bottom from September 11, 2008, until September 28, 2008. Exelon learned of the individuals positive FFD in August 2009, when the contract employee attempted to gain UA to Progress Energys Crystal River Nuclear Generating Plant 3 (Crystal River) Although the contract employee did not enter any Vital Areas at Peach Bottom and also did not perform work on any safety-related equipment during the time he was granted access, the contract employees actions caused Exelon to be in violation of NRC requirements, specifically: 1) 10 CFR 50.9, which states in part that information required by the Commissions regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects; and, 2) 10 CFR 73.56(c) and Section 9.1 of the Peach Bottom Physical Security Plan, both of which state, in part, that the licensees access authorization program must provide high assurance that the individuals who are granted unescorted access are trustworthy and reliable. Although Exelon was unaware of the contract employees omission of information regarding the positive FFD test, Exelon is responsible for the adequacy of its Physical Security Plan and background checks to identify past actions and appropriately evaluate the trustworthiness and reliability of applicants for UA. (This item was also discussed in Inspection Report 2010-004.)
05000277/FIN-2010002-02	2010Q1	Green		Licensee-identified	Licensee-Identified Violation	TS Limiting Condition for Operation 3,6,1,3, Condition A, requires a main steam line flow path to be isolated within eight hours when one MSIV is inoperable in Modes 1, 2, and 3, TS 3,6,1,3, Condition F, requires the unit to be in Mode 3within 12 hours, and Mode 4 within 36 hours, if Condition A cannot be met. Contrary to the above, on September 18, 2009, an engineering evaluation determined that the outboard MSIV AO-3-01A-086A did not meet its required TS minimum closure time of greater or equal to three seconds, This determination was based on MSIV stroke time testing performed on September 14,2009, when entering the P3R17 outage, This issue was considered as a condition prohibited by TS since there was evidence that the condition had existed during plant operations, The cause of the event was due to not requiring preventive maintenance for the MSIV oil dashpot needle control valve, PBAPS documented this issue in the CAP as IR 964717, Since PBAPS analysis concluded this condition did not have a significant effect on the safety analysis and the plantnever operated outside of the safety analysis, this issue is of very low (Green)safety significance, The LER associated with the event was documented in Section 40A3,2 of this report.
05000277/FIN-2010002-01	2010Q1	Green	P.2	Self-revealing	Inadequate Corrective Action to Address Multiple Slow Control Rods with Adverse SSPV Diaphragms	A self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, occurred when PBAPS failed to identify and correct a condition adverse to the quality. Specifically, an issue related to control rod drive scram solenoid pilot valve (SSPV) diaphragms, as described in vendor documents and NRC generic communication, was not corrected after several slow control rods were identified during scram time testing between 2004 and 2010. Consequently, 21 slow rods were identified during Unit 2 scram time testing that was conducted from January 30 to January 31, 2010. PBAPS immediately performed maintenance to replace the defective SSPV Diagrams on all 21 Unit 2 slow control rods by February 1, 2010, and successfully performed post-maintenance scram time testing. Additionally, the issues were entered into the PBAPS CAP. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems (MS) cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the phase 1 worksheet in Attachment 4 of IMC 0609, Significance Determination Process, the inspectors determined that the finding affected the MS cornerstone and was of very low safety significance (Green) because it was not a design or qualification deficiency, did not represent a loss of safety system function, and was not associated with any external events. The inspectors determined that this finding had a cross-cutting aspect in the area of problem identification & resolution (PI&R), CAP, because PBAPS did not thoroughly evaluate previously identified conditions adverse to the quality of the SSPV diaphragms, such that the resolution addressed the cause and extent-of-condition
05000277/FIN-2009005-02	2009Q4	Green	P.5 P.2(b)	NRC identified	Failure to Follow Procedures and Implement the Exelon Nuclear Cable Condition Monitoring Program for Non-Safety-Related Control and Power Cables within the Scope of the Maintenance Rule	The inspectors identified a finding for the failure to follow the Exelon fleet procedure for cable monitoring (ER-AA-3003) of non-safety-related cables within the scope of the 10 CFR 50.65 (the Maintenance Rule). Specifically, PBAPS had reported to the NRC that they were implementing this procedure for cables within the scope of GL 2007-01; however, actions were not specified to identify or remediate the cause of repetitive flooding and restore the function of the degraded electrical manhole/vault drain systems. PBAPS initiated IR 1016075 to enter the issues associated with this finding into the CAP. This finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone and the associated cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. This finding was evaluated in accordance with IMC0609.04, Phase 1 - Initial Screening and Characterization of Findings and was determined to be of very low safety significance because it did not represent an actual loss of safety function or contribute to external event core damage sequences. This finding had a cross-cutting aspect in the area of PI&R, Operating Experience, because Exelon did not adequately implement and institutionalize industry operating experience through changes to station processes and procedures P.2(b). Specifically, work order instructions were inadequately scoped in that they were limited to manholes with safety-related cables and did not include all manholes with Maintenance Rule power cables contrary to the scope identified in ER-AA-3003 or GL 2007-01
05000277/FIN-2009005-01	2009Q4	Green	P.2	NRC identified	Continuously Submerged Cables design Deficiency	The inspectors identified an NCV of 10 CFR, Part 50, Appendix B, Criterion III, Design Control, because PBAPS has not maintained safety-related power cables (including low voltage cables) in an environment for which they were designed and tested. Specifically, PBAPS did not adequately select and review for suitability of application of materials a 480 volt ac power cable feeding a safety-related motor control center (E424-0-A) that has been in a submerged environment in manhole 35 for an extended period of time and at least since 2002. Additionally, PBAPS personnel did not take actions to properly evaluate and mitigate the effects of long term submergence of these safety-related electrical power cables. The issue was entered into the licensee\'s CAP as IR 1022206.This finding is more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone and the associated cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. This finding was evaluated in accordance with IMC 0609.04, Phase 1 Initial Screening and Characterization of Findings and was determined to be of very low safety significance because it did not represent an actual loss of safety function nor contribute to external event core damage sequences. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because Exelon did not thoroughly evaluate problems such that the resolutions addressed causes including evaluating for operability conditions adverse to quality P.1 (c). Specifically, station personnel did not adequately evaluate the impacts on operability and service life of operating the cables submerged in water for an extended period of time.
05000277/FIN-2009005-03	2009Q4	Green	H.11 H.12	Self-revealing	Inadequate Verification Practices while Handling Fuel and Fuel Components	A Green self-revealing NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when PBAPS inadequately implemented human performance tools and verification practices for fuel handling and fuel component handling activities, resulting in a dropped fuel channel in the spent fuel pool (SFP) and a mispositioned fuel bundle in the reactor core during the P3R17refueling outage (RFO). The inspectors verified that corrective actions were promptly performed, including an operability evaluation and video inspection of the SFP racks, and reactor engineering evaluation for the mispositioned fuel bundle. Additionally, the issues were entered into the PBAPS CAP. 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 of providing reasonable assurance that physical design barriers protect the public from radionuclide release cause by accidents or transients. This finding was determined to be of very low safety significance (Green) in accordance with IMC 0609, Appendix M, SDP Using Qualitative Criteria, because evaluations performed by PBAPS, and verified by the inspectors, determined that there was no actual degradation to the physical barrier integrity. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because PBAPS management and personnel did not effectively communicate human error prevention techniques commensurate with the risk of the assigned tasks, such that the work activities were performed safely H.4(a). Specifically, PBAPS management and personnel did not adequately reinforce the importance of using human performance tools and verification practices, including self-check (STAR), concurrent verification, and independent verification, prior to performance of activities involving fuel component handling.
05000277/FIN-2009005-04	2009Q4	Severity level IV		Licensee-identified	Licensee-Identified Violation	The Reload 16, Cycle 17, Revision 4, mid-cycle Core Operating Limits Report (COLR)was prepared and approved between November 21 and 26, 2008. This COLR revision was issued for implementation on March 12, 2009, and was submitted to the NRC by a letter from P. B. Cowan to the U.S. NRC, Issuance of Proprietary and Non-Proprietary COLRs, dated October 1,2009. TS 5.6.5.d, COLR, states, in part, the COLR, including any mid-cycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC. Contrary to the above, between its issuance on March 12,2009, and its submittal on October 1,2009, the Reload 16, Cycle 17, Revision4, mid-cycle COLR was not provided in a timely manner to the NRC nor upon its issuance. This issue was documented in the CAP as IR 970608. Traditional enforcement applies since this was a violation that potentially impeded or impacted the regulatory process. This was considered a non-cited Severity Level IV violation since the untimely submittal did not have a material impact on licensed activities
05000277/FIN-2009004-03	2009Q3	Green		Licensee-identified	Licensee-Identified Violation	The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy for being dispositioned as a NCV: As documented in report section 40A3.2, LER 05000278/2009004-00 reported a condition prohibited by TS which was discovered when engineering personnel determined that the Unit 3 \'B\' HPSW 1ESW ventilation subsystem was rendered inoperable as a result of preventive maintenance performed on April 13, 2009. The TRM Section 3.11, Engineered Safeguards Compartment Cooling and Ventilation, required immediate compliance with the TS Actions for the inoperability of one HPSW subsystem if one HPSW I ESW pump structure ventilation subsystem is inoperable. TS 3.7.1, Condition A, required action to restore one inoperable HPSW subsystem to an operable status within seven days. TS 3.7.1, Condition B, required the plant be in Mode 3 within 12 hours if Condition A is not met. Contrary to the above, between April 13 and July 5, 2009, the Unit 3 \'B\' HPSW I ESW ventilation subsystem was inoperable and TS 3.7.1 was not entered until the inoperability was discovered on July 3, 2009. PBAPS documented this issue in the CAP as IR 938565. The inspectors reviewed the PBAPS Risk-Informed Inspection Notebook Table 2and concluded that the HPSW I ESW pump structure ventilation system was not required to support HPSW and ESW pump core damage mitigation safety functions. A Region I senior reactor analyst verified this conclusion. Therefore, this issue was of very low (Green) safety significance, because of no impact on the safety function for either subsystem of the HPSW or ESW systems
05000277/FIN-2009004-02	2009Q3	Green	H.11 H.12	Self-revealing	Inadequate Procedure Adherence Results in the Loss of Safety Function of Systems Supplied by the Sgig System	A self-revealing Green NCV was identified for failure to comply with Technical Specification (TS) 5.4.1 J Procedures, which required that procedures be established, implemented, and maintained for the safety grade instrument gas (SGIG) system. Specifically, the SGIG Pressure Building Circuit Outlet Block Valve (HV-0-7C-1 0) was manipulated without procedure guidance, was out of its normal position, and resulted in the inoperability of certain valves associated with the primary containment and containment atmosphere dilution (CAD) systems for both units. Based on the above, the inspectors determined that manipulating the SGIG Pressure Building Circuit Outlet Block Valve (HV-0-7C-10) without procedure guidance was a performance deficiency that was reasonably within PBAPS\'s ability to foresee and prevent. The inspectors concluded that the manipulating HV-0-7C-10 without a procedure was a more than minor finding because it was associated SSC and barrier performance attribute of the Barrier Integrity cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that the containment would protect the public from radionuclide releases caused by accidents or events. Specifically, certain valves associated with the primary containment and containment atmosphere dilution (CAD) systems could not be operated as designed due to this valve being out of its normal position. Traditional enforcement does not apply since there were no actual safety consequences or potential for impacting the NRC\'s regulatory function, and the finding was not the result of any willful violation of NRC requirements. Accordingly, the inspectors assessed the finding in accordance with IMC 0609, SOP, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a, for the Containment Barrier cornerstone. The finding was determined to be of very low safety significance (Green) since the finding did not represent an actual open pathway in the physical integrity of the reactor containment (isolation valves). The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, Work Practices component, because human error prevention techniques, such as peer and self checking, were inadequately used to prevent mispositioning the SGIG Pressure Building Circuit Outlet Block Valve (HV-0-7C-10). (IMC 0305 Aspect H.4(a)
05000277/FIN-2009004-01	2009Q3	Green	H.14	NRC identified	Failure to Perform a 50.59 Review Prior to Installing Jumpers on E Wrnm	An inspector-identified, Severity Level IV NCV of 10 CFR 50.59 was identified when PBAPS made temporary alterations to their facility to address a degradedcondition without performing a 50.59 review. Specifically, PBAPS installed a jumper that bypassed the trip feature of the Unit 3 \'E\' wide-range neutron monitoring (WRNM) system instead of using the WRNM bypass switch as is described in their plant\'s Final Safety Analysis Report (FSAR). Exelon entered this issue into their CAP and the jumper was subsequently removed restoring the original system configuration. Because this was a violation of 10 CFR 50.59, it was considered a violation that potentially impeded or impacted the regulatory process; therefore, this violation was dispositioned using the traditional enforcement process. This finding was more than minor because there was a reasonable possibility that the change requiring a 10 CFR 50.59 Safety Evaluation (SE) would require NRC review and approval prior to implementation in accordance with 10 CFR 50.59(c)(2). This possibility is based on the likelihood that a second WRNM could be bypassed, with the bypass switch built into the WRNM system, without resulting in a trip of the associated reactor protection system (RPS). This condition would be contrary to the design of the WRNM and RPS, thereby . creating the possibility for a malfunction of a structure, system, and component (SSC) important to safety with a different result than any previously evaluated in the FSAR (as updated). Although the SOP is not designed to assess traditional enforcement violations, the NRC assesses the significance of 10 CFR 50.59 violations through the SOP for risk insights. Accordingly, the inspectors evaluated the finding in accordance with IMC 0609, SOP, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a, for the Mitigating Systems cornerstone. The issue, associated with the installation of the one jumper, was determined to be of very low safety significance (Green) since the issue was determined to be a qualification issue confirmed not to result in loss of operability of the system. This violation involved a facility change that likely would have required a license amendment before its implementation. Comparing this item to the examples in NRC Enforcement Policy, Supplement I, Reactor Operations, this finding is similar to Item 0.5, Violations of 10 CFR 50.59 that result in conditions evaluated as having very row safety significance (i.e., Green) by the SOP. This is a Severity Level IV violation. Additionally, this finding was determined to have a crosscutting aspect in the area of Human Performance, Decision Making component, which states the licensee should use conservative assumptions in decision making and adopt a requirement to demonstrate that the proposed action is safe. Specifically, Exelon did not perform a 10 CFR 50.59 safety evaluation or screening when making a temporary alteration to the RPS system which would be installed for the remainder of the operating cycle
05000277/FIN-2009008-01	2009Q3	Green	P.3	NRC identified	Failure to Take Adequate Cas for Grease Applied to DC Contactors	The inspectors identified a non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for failure to identify and correct a condition adverse to quality. Specifically, in March 2009, Exelon did not take adequate corrective action to address a procedure deficiency and to ensure that grease inappropriately applied to Cutler Hammer direct current (DC) contactor pivot pins, in an unknown number of DC breakers in the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems at Unit 2 and 3, would be identified and removed in a timely manner. Because the grease could harden over time and cause inadequate DC breaker performance, the inspectors determined that this condition, if left uncorrected, could prevent certain Units 2 and 3 HPCI and RCIC system valves from performing their safety-related function. Exelon entered this issue into their corrective action program as issue report (IR) 950438 and IR 950439. The finding affected the Mitigating Systems cornerstone and was determined to be more than minor because the condition, if left uncorrected, could have become a more significant safety concern. By not requiring, by procedure, the removal of all grease from the affected Cutler Hammer DC contactor pivot pins, Exelon did not ensure that all of the potentially affected DC motor-operated valves in the Unit 2 and Unit 3 HPCI and RCIC systems would be available to perform their design functions if called upon. The inspectors evaluated this finding using Phase I of Manual Chapter 0609 and determined the finding to be of very low safety significance (Green) because it was not a design or qualification deficiency confirmed not to result in loss of operability or functionality, did not represent a loss of system or train safety function, and was not potentially risk significant due to external events. This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because Exelon failed to take appropriate corrective actions to address a safety issue in a timely manner, commensurate with the safety-significance and complexity P.1(d). Specifically, Exelon did not take appropriate corrective actions to ensure that grease inappropriately applied to Cutler Hammer DC contactor pivot pins would be, by procedure, identified and removed in a timely manner
05000277/FIN-2009003-02	2009Q2	Green	H.8	Self-revealing	Inadequate Procedure Adherence Results in Trip of 3 \\\'A\\\' Recirc Pump and Plant Transient	A self-revealing finding was identified when PBAPS personnel incorrectly performed a maintenance procedure for tuning the reactor recirculation pump (RRP) motor generator (MG) set voltage regulator. Specifically, maintenance personnel adjusted a potentiometer in the wrong direction, which resulted in a trip of the RRP and an unplanned plant transient. This finding is more than minor because the finding is associated with the human performance attribute of the Initiating Events Cornerstone, and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions. Specifically, this error resulted in an unplanned plant transient that reduced reactor power from 75 percent to 33 percent. In accordance with IMC 0609, Attachment 4, the inspectors determined this finding to be of very low safety significance (Green) since the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding has a cross-cutting aspect in the area of human performance, Work Practices, because PBAPS did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures H.4(b). Specifically, PBAPS personnel did not follow procedure IC-11-02011instructions for tuning the 3 A RRP MG set voltage regulator.
05000277/FIN-2009003-03	2009Q2	Green		Licensee-identified	Licensee-Identified Violation	TS 3.1.3, Condition C, requires that control rods that are inoperable for reasons other than being stuck shall be fully inserted and disarmed. TS 3.1.3, Condition E, requires the unit to be in Mode 3 within 12 hours if Condition C cannot be met. On February 11, the 10-51 CRD HCU was declared inoperable for the conduct of maintenance and the TS required actions to fully insert and disarm the CRD were met. Following the completion of maintenance on the HCU, an operator erroneously re-armed the CRD HCU DCVs during the modification of a safety tagging clearance that occurred at approximately 5:30 a.m. on February 12.Over 28 hours later and in excess of the 12-hour completion time allowed by TS3.1.3, PBAPS personnel discovered the error and disarmed the CRD for Control Rod 10-51. PBAPS documented this issue in the CAP as IR 880318. Since Control Rod 10-51 remained fully inserted and there was no loss of safety function during the period of non-compliance, this issue is of very low (Green) safety significance. The LER associated with the event was documented in Section 4OA3.3.
05000277/FIN-2009003-01	2009Q2	Green	P.2	Self-revealing	MOV Program Procedures were Inadequate with Regard to Periodicity of Preventitive Maintenance Activities for Stem Lubrication	A self-revealing NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified. Specifically, Exelons Motor Operated Valve (MOV) Program procedures lacked specific instructions to prescribe an acceptable frequency for performing valve stem lubrication, which resulted in test failures of safety related MOVs and affected the reliability of the MOVs safety functions. On Unit 2, the inspectors determined that 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 of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). In accordance with IMC 0609, Attachment 4, the inspectors determined that the finding was of very low safety significance (Green)because it was not a design or qualification deficiency, did not represent a loss of system safety function, and was not associated with any external events. On Unit 3, the inspectors determined that the finding was more than minor because it was associated with the configuration control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers (e.g., containment) protect the public from radionuclide releases caused by accidents or events. In accordance with IMC 0609, Attachment 4, the inspectors determined that the finding was of very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of reactor containment. For both units, this finding has a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R), Corrective Action Program, because PBAPS did not thoroughly evaluate problems such that the resolutions addressed the causes and extent of condition P.1(c). Specifically, PBAPS failed to thoroughly evaluate previous conditions of degraded and hardened grease on safety-related valves, such that the extent of the condition was considered and the cause was resolved.
05000277/FIN-2009002-02	2009Q1	Green	H.7	Self-revealing	Inoperable \'A\' WRNM Results in a Condition Prohibited by TSs	A self-revealing, Green NCV of Unit 3 TS 3.0.4 was identified by the inspectors on January 26, 2009, when a half-scram occurred on Unit 3, shortly after Unit 3 entered Mode 2 for plant startup. Specifically, the A Wide-Range Neutron Monitoring (WRNM) was inoperable as a result of inadequate procedural guidance regarding adjustments made to the mean square voltage (MSV) offset during the outage (prior to the January 26, 2009, startup). The inadequate procedural guidance allowed adjustments to be made which resulted in the WRNM not making a smooth transition from the counting region to the MSV region of operation, causing the AWRNM to be inoperable and resulting in an unexpected half-scram when the WRNM transitioned from the counting region to the MSV region of operation. As a result, TS3.3.1.1 requirements for the number of available channels of WRNM short period RPS trip in Mode 2 had not been met. TS 3.0.4 requires that when a LCO is not met, entry into a mode or other specified condition shall only be made when the associated actions to be entered permit continued operation in the mode or other condition specified for an unlimited period of time. Corrective actions included entering the issue into the CAP, conducting an event review, and submitting a License Event Report (LER) to the NRC, and revising the WRNM adjustment procedure. The finding is more than minor because it is associated with the procedure quality attribute and adversely affected the Initiating Events Cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions. The finding was of very low safety significance because it did not contribute to the likelihood that both a reactor trip would occur and that mitigation equipment would not be available. This finding has a cross-cutting aspect in the area of human performance (resources) because the licensees procedure did not provide adequate guidance to prevent adjusting the MSV offset to an unacceptable value. IMC 0305 aspect: H.2(c
05000277/FIN-2009002-01	2009Q1	Green	H.5	Self-revealing	Inadequate Work Instructions Result in Inadvertent ESF Actuation	A self-revealing NCV of 10 CFR 50 Appendix B, Criteria V, Instructions, Procedures and Drawings was identified when inadequate work instructions resulted in a momentary shorting of a terminal lead during maintenance, which caused an inadvertent Unit 3, primary containment isolation valve (PCIV) signal and entry into a one-hour shutdown Technical Specification (TS) Action Statement on March 3, 2009.Specifically, the work instructions allowed the technicians to lift and manipulate energized leads on a safety-related pressure switch without providing any guidance as to the risk and consequences that inadvertent grounding of those energized leads could cause. Because the risk and consequences were not considered and an inadvertent grounding occurred, a PCIV signal resulted that closed normally open valves on both the containment atmosphere control (CAC) system and the instrument nitrogen system containment penetrations. In addition, both PCIV valves on containment atmosphere dilution (CAD) system were rendered inoperable which required the operators to enter an unplanned one-hour TS Action Statement(3.6.1.3.B) and would have required a plant shutdown within the following 12 hours. Corrective actions included replacing the blown fuse, entering the issue into the CAP, and making a required 60 day verbal report to the NRC. The finding is more than minor because it could reasonably be viewed as a precursor to a significant event. Specifically, the failure to assess the risk of inadvertent grounding of energized leads on safety equipment could pose a credible hazard as an initiating event during plant operation. The finding was of very low safety significance because the valves in question failed closed and did not represent an actual open pathway in the physical integrity of reactor containment. This finding has a cross-cutting aspect in the area of human performance (work control) because the licensees work instructions did not provide appropriate risk insights regarding the risks associated with potential grounding of the energized leads. H.3(a
05000277/FIN-2009002-04	2009Q1			NRC identified	HPCI System Torus Suction Valve Failures	The inspectors identified an unresolved item (URI) related to the adequacy of preventive maintenance on MOVs. On March 12 and 21, 2009, HPCI torus suction valves in Unit 2 and Unit 3, respectively, failed to stroke fully open during routine testing. Dry and hardened stem lubricant was identified in both instances. This issue will remain unresolved pending completion of PBAPSs root cause determination and completion of extent of cause and condition evaluations of MOVs in other accident mitigation systems. On March 12, the Unit 2 HPCI system suppression pool suction valve, MO-2-23-058, failed to fully open when repositioned during quarterly surveillance testing. The valve stroke was interrupted by operation of the motor operator torque switch. On March 21, the Unit 3 HPCI system suppression pool suction valve, MO-3-23-057, failed to fully open when it was repositioned during quarterly testing. The valve stroke was interrupted by actuation of the motor operator torque switch. In both instances, the stem lubricant was found to be dry and hardened. Failures to stroke appeared to be repeat occurrences of a valve failure to stoke event which occurred in October 2007.PBAPS determined that other safety-related MOVs may be similarly affected by the stem lubricant hardening issue. The EOC and extent of cause evaluations were ongoing at the end of the inspection period. These evaluations included selecting a sample of MOVs to be visually examined for dry and/or hardened stem lubricant. In addition, PBAPS selected a number of MOVs for diagnostic testing with monitoring equipment connected to determine if any degradation of MOV capability had occurred since the last diagnostic testing of that MOV. At the end of the inspection period, these activities were still in progress; therefore, this item remains unresolved: URI 05000277, 278/2009002-04, High Pressure Coolant Injection (HPCI) System Torus Suction Valve Failures
05000277/FIN-2009002-03	2009Q1	Green		NRC identified	Departure from a Method of Evaluation without Prior NRC Approval	An inspector-identified, Severity Level IV NCV of 10 CFR 50.59 was identified when PBAPS made a safety analyses change that departed from a method of evaluation described in the UFSAR without obtaining prior NRC approval and a license amendment. Specifically, PBAPS used a spent fuel pool criticality analysis methodology that was not previously approved by the NRC, and did not adopt an NRC-approved methodology en toto and apply it consistent with applicable terms, conditions, and limitations of that methodology. Corrective actions for this problem included entering the issue into the CAP and making plans to develop a technical evaluation that would demonstrate, using methodologies approved for PBAPS, that adequate margin to criticality exists for the nonconforming condition presented by degraded Boraflex in the SFP storage racks. Additionally, PBAPS submitted a LAR, to use alternative SFP criticality analyses, to the NRC on June 25, 2008. This deficiency was evaluated using the traditional enforcement process since it potentially impacts or impedes the NRCs ability to carry out its regulatory mission, in that, PBAPS did not request and receive prior NRC approval for changes in licensed activities. The finding is more than minor and a Severity Level IV violation because it is similar to example D.5 of Supplement I, Reactor Operations, to the NRCs Enforcement Policy. Specifically, the finding involved a violation of 10 CFR 50.59that resulted in conditions evaluated as having very low safety significance (i.e., Green) by the SDP. Using the Phase 1 SDP, the inspectors determined that the condition resulting from the violation of 10 CFR 50.59 screened to Green because it could affect the functionality of the fuel barrier (cladding)
05000277/FIN-2008005-01	2008Q4	Green	H.4 H.5	Self-revealing	Incorrect Performance of Procedure Step Resulted in Inoperability of a DC Bus for Longer than the TS Allowed Outage Time	A self-revealing (Green) NCV of Technical Specification (TS) 5.4.1 was identified when operators inadequately implemented an abnormal operating (AO) procedure on two occasions. Specifically, an event where the Unit 2 Division II direct current (DC) electrical power subsystem was inoperable for longer than the allowed outage time specified in Unit 3 TS 3.8.4, resulted from PBAPS personnel not recognizing the existence of conflicting procedure guidance and the improper removal of a configuration control tool. This finding is more than minor because it was associated with the human performance attribute of the Mitigating Systems Cornerstone, and impacted the cornerstone objective of ensuring the reliability of the Unit 2, Division II, DC electrical power subsystem to respond to initiating events, in that, one of its associated battery chargers was being supplied from a non-qualified alternating current (AC) power source. The inspectors concluded that this finding affected the Mitigating Systems Cornerstone and answered \"No\" to all relevant questions. Specifically, the supply of a non-qualified AC power source to the Unit 2, Division II DC electrical power system was a qualification issue confirmed not to result in a loss of functionality. Although the Unit 2, Division II DC electrical power system was inoperable for longer than its 12-hour TS allowed outage time, this qualification issue did not result in an actual loss of safety function. Therefore, this finding was considered to be of very low safety significance (Green). The inspectors determined that this finding had a cross-cutting aspect in the area of human performance (work control component) because PBAPS personnel did not adequately coordinate work activities by incorporating actions to address: the impact of changes to the work scope or activity on the plant and human performance; nor the need to keep personnel apprised of the operational impact of work activities; and plant conditions that may affect work when conflicting procedures led to inadequate procedure adherence and the unplanned inoperability of the Unit 2 Division II DC electrical subsystem. (IMC 0305 aspect: H.3(b)). (Section 4OA3.1
05000277/FIN-2008004-02	2008Q3	Green	P.6 P.3(c)	NRC identified	Failure to Comply with 10 CFR 20 Appendix G	The inspectors identified a NCV of 10 CFR 20, Appendix G, Section III.C. 5. Specifically, the licensee did not conduct a Quality Assurance Program sufficient to assure conformance with 10 CFR 61.55, in that, the program was not adequate to identify incorrect gamma spectroscopy analyses of a principal gamma emitting radionuclide used to scale hard-to detect radionuclides for purposes of waste classification in accordance with 10 CFR 61.55. The licensee entered the deficiency into its CAP (IR799894). The failure to conduct a sufficiently robust 10 CFR 61 Quality Assurance Program, to assure conformance with 10 CFR 61.55, is a performance deficiency that was reasonably within the licensees ability to foresee and correct, and which should have been prevented. The finding is more than minor because it affected the associated cornerstone objective in that the licensees 10 CFR 61 Quality Assurance Program did not identify incorrectly analyzed waste samples used to classify radioactive waste for land disposal. This finding was determined to be of very low safety significance because no radiation limits were exceeded, there was no breach of packaging, there was no certificate of compliance finding, there was no low level burial ground non-conformance, and lastly, there was no failure to make notifications or provide emergency notification information. The cause of this finding was related to the cross-cutting area of PI&R, self and independent assessments component, in that, although actions were taken to coordinate and communicate results from assessments to affected personnel, corrective actions were not sufficiently comprehensive to identify incorrect vendor analyses (IMC 0305, aspect P.3(c)). (Section 2PS2)
05000277/FIN-2008004-01	2008Q3	Green	P.2	Self-revealing	Inadequate EOC Review Results in Delay in Discovery of ESW Leaks	A self-revealing NCV of 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures and Drawings, was identified for a failure to follow procedure, WC-PB-2000, Outage Control Center (OCC) Emergent Issue Response, that resulted in an inadequate extend of condition (EOC) evaluation being performed for an emergency service water (ESW) leak that was discovered on the E-1 emergency diesel generator (EDG). Specifically, Operations personnel failed to look at similar ESW locations on the E-2, E-3, and E-4 EDGs. This resulted in a nine-day delay in discovering a similar leak on the E-4 EDG. This finding is greater than minor because it is similar to the example 4a., Insignificant Procedural Errors, in Manual Chapter 0612, Appendix E, in that, the later evaluation of the ESW leak discovered on the E-4 EDG resulted in safety-related equipment being adversely affected. Using the Phase 1 worksheet in Manual Chapter 0609, Significance Determination Process, the finding was of very low safety significance (Green) since it did not represent an actual loss of system safety function for the ESW system. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution (PI&R), Corrective Action Program (CAP) because the licensee failed to thoroughly evaluate the EOC of the leak on the E-1 EDG and it resulted in a nine-day delay in discovering additional leaks associated with the E-3 and E-4 EDGs. (IMC 0305, aspect P.1(c)). (Section 1R15)
05000277/FIN-2008004-03	2008Q3			NRC identified	Failure to Make a 10 CFR 50.72(b)(2)(xi) Notification	The inspectors identified a NCV of 10 CFR 50.72(b)(2)(xi) because the NRC Operations Center was not notified of a reportable event. Specifically, PBAPS did not formally report, to the NRC Operations Center, a planned press release and the notification of other government agencies regarding a transformer fire and petroleum product spill event that occurred on July 23 and 24, 2008. This deficiency was evaluated using the traditional enforcement process since the failure to make a required report could adversely impact the NRCs ability to carry out its regulatory mission. This event was related to pubic health and safety because it involved a fire emergency that contributed to the loss of two of the plants three offsite power sources. This event was related to protection of the environment because it involved the spill of a more than minor quantity of oil that required reporting to the State of Pennsylvania. While reviewing this finding, the inspectors considered the fact that the NRC was informally notified. The inspectors considered the above and evaluated the severity of this violation using the criteria contained in Supplement I Reactor Operations and Section VI.A.1 of the NRCs Enforcement Policy and determined that this finding met the criteria for disposition as a NCV. (Section 4OA3.1
05000277/FIN-2008007-02	2008Q2	Green	H.7	NRC identified	Non-conservative Inputs Used in Design Calculations for Offsite Power Operability (Section 1R21.2.1.4)	The team identified a finding of very low safety significance, in that Exelon failed to use appropriate inputs in design calculations as required by Exelon Procedure CC-AA-102 - Design Input and Configuration Change Impact Screening. The requirements of the procedure include ensuring performance requirements are the maximum or minimum numerical values of specific design parameters, specifically, the Maximum time to automatically initiate a system action. The team determined the response speed used by Exelon for the automatic load tap changer (LTC) controller and mechanism for the stations startup transformers, in the calculation to determine offsite power availability, was non-conservative. This assumption resulted in the grid voltage limit, used to assess technical specification offsite power supply operability, to be nonconservative. In response, Exelon performed preliminary calculations with revised LTC times, which showed that the offsite grid remained operable at the specified voltage limits. Exelon entered the issue into the corrective action program to re-perform the calculation and raise the allowed offsite grid voltage level. This finding was more than minor because it is associated with the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined the finding was of very low safety significance (Green) because it was design deficiency that did not result in a loss of offsite power operability. Because the licensee had recently performed this calculation with the non-conservative inputs, the finding has a cross-cutting aspect in the area of Human Performance - Resources. (IMC 0305, aspect H.2.(c)) (1R21.2.1.4)
05000277/FIN-2008007-03	2008Q2			NRC identified	Vital Bus Degraded Voltage Protection (Section 1R21.2.1.8)	The team reviewed Exelons load flow and vital bus voltage calculations. The review was performed to verify the minimum vital bus voltage needed to ensure operation of safety related loads required during design basis events was adequate. The team determined that voltages used in these analyses were not based on the trip set point of the Technical Specification Function 4 (LOCA) degraded voltage relay. Exelon had used voltages higher than were afforded by the Function 4 relays based on their belief that minimum expected value, as defined in GL 79-36 Adequacy of Station Electric Distribution Systems Voltage, could be used to calculate adequate voltages to vital loads. In using this assumption Exelon credited voltage improvement due to operation of the non-safety related startup transformer load tap changers in their analysis. The tap changer restores voltage to the vital bus during and following the post accident voltage transient. The team reviewed NRC Letter dated June 2, 1977, which was the basis for the licensing requirement to install the degraded voltage relay protection scheme. This licensing requirement required the set points for the second level reduced-voltage relays provide adequate voltage, from offsite or onsite power sources, for safety related loads at all onsite system distribution levels. The inspectors reviewed the PBAPS licensing records related to degraded voltage protection and did not find where the NRC had allowed Peach Bottom to credit operation of automatic tap changers in lieu of the technical specification reduced voltage relays to provide protection. Exelon stated that their approach was acceptable and the NRC had given this credit when it reviewed and approved certain voltage studies submitted as part of licensing actions related to the degraded voltage relays. This unresolved issue is being opened to determine if the Peach Bottom approved licensing bases includes the use of automatic load tap changers to protect the vital bus from unacceptable low voltage conditions during loss of coolant accidents. (URI 05000277;278/2008007-003, Vital Bus Degraded Voltage Protection)
05000277/FIN-2008003-01	2008Q2	Green		Self-revealing	Foreign Material Discovered in Fire Valve	A self-revealing NCV of PBAPSs Unit 2 License Condition 2.C (4), Fire Protection Program, was identified when maintenance personnel discovered foreign material inside a supply valve to an automatic 13KV switchgear sprinkler system installed because there is a one-hour rated raceway encapsulated in the 13KV switchgear area. The Fire Protection Program requires automatic suppression when one-hour rated raceway encapsulation is used. PBAPS has removed the foreign material, replaced the affected valve, and entered this issue into their CAP for appropriate action. The inspectors determined that there was no cross-cutting aspect to this finding. The finding is more than minor because it is associated with the Mitigating Systems Cornerstone attribute of protection against external factors (i.e., fire), and it affects the objective of ensuring reliability and capability of systems that respond to initiating events. The finding was of very low significance because PBAPS demonstrated that the core damage frequency (CDF) associated with a fire in this area was in the 1 E-7 range for all assumed fires. (Section 1R12
05000277/FIN-2008007-01	2008Q2	Green	P.3	NRC identified	Inadequate Battery Connection Resistance Testing (Section 1R21.2.1.1)	The team identified a finding of very low safety significance involving a non-cited violation of Technical Specification (TS) 3.8.4.5, in that Exelon did not verify certain battery connection resistances were within the TS limit. Specifically, Exelon did not verify the inter-tier connection resistances to be within the TS 3.8.4.5 limit of less than or equal to 40 micro-ohms every 12 months. The team determined that Exelon exempted the inter-tier connections from the testing requirement. In response, Exelon performed the required testing and identified a connection in the 2B battery that was greater than the TS limit. Exelon restored the degraded connection and initiated actions to revise the surveillance test procedures to incorporate all battery connections. This issue was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined the finding was of very low safety significance (Green) because it did not result in a loss of safety system function. Because the licensee had previously identified a similar inadequacy in the test procedure, the finding had a cross-cutting aspect in the area of Problem Identification and Resolution - Corrective Actions. (IMC 0305, aspect P.1(d)) (1R21.2.1.1)
05000277/FIN-2008002-01	2008Q1	Green	P.3	NRC identified	Failure to Identify and Document Fire Brigade Deficiencies (Section 1R05.2)	The inspectors identified a non-cited violation (NCV) of Technical Specification (TS) 5.4.1, which requires that written procedures be implemented covering the Fire Protection Program. The Fire Drill Performance procedure was inadequately implemented because numerous fire brigade deficiencies were not discussed at the post-drill critique or documented in the fire drill record. The licensee has entered this problem into their CAP for action. This finding is more than minor because it affects the impairment or degradation of a fire protection feature, specifically, on the ability of the fire brigade to effectively carry out the defense-in-depth attribute of manual fire fighting and is associated with the Mitigating Systems Cornerstone and its respective attribute of human performance. This finding is of very low safety significance because the observed crew was only one of five crews of the site fire brigade team, the other crews had no known problems, and the overall condition of the fire detection and suppression systems had been satisfactory. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution because Peach Bottom Atomic Power Station personnel did not properly identify and assess deficiencies with the fire brigades performance. (IMC 0305, aspect P.3 (a)) (Section 1R05.2).
05000277/FIN-2008405-01	2008Q1	Severity level IV		NRC identified	Extent of Condition and Corrective Action Program Usage for Operator Watch Standing Issues. (Section 4OA2.2)	On September 10, 2007, representatives of WCBS-TV (New York City) contacted the NRC stating that they possessed videotapes of inattentive security officers at the Peach Bottom Atomic Power Station (PBAPS). Based upon this information, the NRC Region I Regional Administrator directed implementation of enhanced inspection oversight of security activities by the resident inspectors at PBAPS, and verbally informed Exelon management of the information received. Exelon commenced an internal investigation based upon this information. On September 19, 2007, WCBS-TV shared the videotapes with the NRC staff, which viewed the videos and determined that the situation warranted an Augmented Inspection. An Augmented Inspection Team (AIT) completed an inspection at PBAPS from September 21 through 28, 2007. The team concluded that Exelons prompt compensatory measures and corrective actions in response to the videotaped inattentive security officers at PBAPS were appropriate and ensured the stations ability to satisfy the Security Plan. However, the team determined that the security officer inattentiveness affected the defense-in-depth strategy, and that security force supervisors were not effective in ensuring unacceptable behavior was promptly identified and corrected. The AIT inspection results were published on November 5, 2007 in NRC Inspection Report 2007404 (ADAMS accession number ML073090061). On October 4, 2007, Exelon sent a letter to the NRC Region I Regional Administrator (ML072850708) which described their completed actions and initiatives to address the issues identified by the AIT. These initiatives included terminating the current security contract with their contractor and transitioning to a proprietary security force. Exelon also described plans to complete a root cause analysis of the security officer inattentiveness, identify corrective actions, and perform safety conscious work environment (SCWE) surveys of the Peach Bottom Security organization. On October 19, 2007, the NRC issued a Confirmatory Action Letter (CAL) to confirm Exelons commitments to assure that security officers remain attentive at all times while on duty (ML072920283). Exelon completed their root cause analysis in October 2007 and identified several causal factors related to the security officer inattentiveness issues and specific corrective actions to address the causal factors. One of the corrective actions was to perform a systematic SCWE assessment of all work groups at PBAPS (including the Security work group) based on an integrated review of information from the PBAPS Corrective Action Program (CAP), Employee Concerns Program (ECP), publicly available NRC allegation statistics, and SCWE surveys. The NRC conducted an AIT follow-up inspection from November 5 through 9, 2007, to review Exelons root cause analysis report and their planned corrective actions. The inspectors concluded the corrective actions were appropriate. With regard to the security officer inattentiveness issue, the AIT follow-up inspection identified a finding regarding Exelons failure to maintain the minimum required number of available security officer responders and an associated failure to implement an effective behavior observation program. The AIT follow-up inspection determined that the finding was related to SCWE because it involved security supervisors who did not encourage the free flow of information related to raising safety concerns, and who did not respond to security officer safety concerns in an open, honest, and non-defensive manner. The NRC determined the finding was of low to moderate safety significance (White). This was documented in a subsequent letter to Exelon dated February 12, 2008 (ML080440012). The AIT follow-up inspection results were issued in NRC Inspection Report 2007405 (ML073550590) dated December 21, 2007. Region I determined that Exelons actions to address the PBAPS inattentive security officer issues and their plans to transition to a proprietary security force warranted additional inspection and oversight beyond that specified in the Reactor Oversight Process (ROP) baseline inspection program. On November 28, 2007, the Regional Administrator recommended, through a Deviation Memorandum to the NRCs Executive Director for Operations (EDO), that PBAPS warranted additional inspection resources (ML073320344). One additional inspection activity was to conduct inspections of Exelons efforts to address SCWE issues, including a review of the results of SCWE surveys conducted at the site. The EDO approved this request on November 28, 2007. Consistent with the planned corrective actions from their root cause evaluation, Exelon arranged for a third party to conduct a survey of the SCWE at PBAPS. The survey was in the form of a series of questions provided to the staff in January 2008. The survey was completed and the results provided to Exelon in February 2008. A separate SCWE survey of the security organization was also conducted during November 2007. Exelon utilized the survey results to complete a self-assessment of the SCWE at PBAPS. In accordance with the NRC Action Matrix Deviation Memorandum, this inspection was conducted onsite from March 24 though 28, 2008, to review Exelons self-assessment of the PBAPS SCWE, including a review of the results of their SCWE survey. Other completed Deviation Memorandum activities included a security organization performance monitoring inspection (ML080720038) and a root cause corrective action evaluation (ML081090161).
05000277/FIN-2007405-01	2007Q4	White		NRC identified	Security	Inattentive security officers and the staff determination that the licensee failed to effectively implement its behavior observation program
05000277/FIN-2007002-05	2007Q1			NRC identified	Missed procedure step resulted in unplanned overloading of the E-3 EDG	The inspectors reviewed selected applicable plant records, correction action documents and approved procedures while evaluating the performance of operations personnel in response to non-routine evolutions. The inspectors assessed personnel performance to determine what occurred and how the operators responded, and to determine if plant personnels response was in accordance with plant procedures and training. The following non-routine evolution was reviewed: During the conduct of surveillance testing of the E-3 EDG on March 15, 2007, a licensed operator missed the performance of a required step in a supporting system operating procedure. The omission of the procedure step placed the E-3 EDG in the isochronous mode while synchronized with offsite power through a 4 kilovolt (kV) vital bus. This condition resulted in unexpectedly loading the E-3 EDG beyond its 30-minute load rating. The ST and supporting procedures directed the synchronization of the E-3 EDG to a selected 4 kV bus to pick up the bus loads. The procedure subsequently directed opening the offsite power feeder breaker to the 4 kV vital bus (the missed step) before placing the EDG in the isochronous mode. PBAPS placed this issue in the CAP by initiating IR 604364. Prompt corrective actions included the selected implementation of additional peer checking of procedure performance place-keeping. The E-3 EDG was inspected for potential damage and tested before being returned to an operable condition in accordance with TS on March 17, 2007. The causal evaluation of this event was ongoing at the end of the inspection period. At the close of this inspection period, the inspectors were reviewing the event and awaiting the results of the causal evaluation to understand the potential performance deficiencies. This issue is unresolved pending review of PBAPSs causal evaluation and corrective actions by the inspectors to characterize the issue. URI 05000277/2007002-05, Missed Procedure Step Resulted in Unplanned Overloading of the E-3 EDG.
05000277/FIN-2007002-04	2007Q1			NRC identified	Incorrect size breaker resulted in a fire in the 4T4 480 volt load center	At approximately 9:16 a.m. on February 27, 2007, a fire was suspected to have started based on the receipt of numerous secondary plant alarms in the main control room (MCR) and the report of smoke near the 4T4\' 480 Volt load center. The inspectors responded to the MCR following a site announcement for the fire brigade to respond to a suspected fire in the Unit 3 turbine building. The inspectors monitored the operators response to the event and the status of plant equipment. The observations were primarily focused on the nuclear safety aspects of the plants and operators responses. The inspectors also monitored the response of PBAPSs emergency response organization to the declaration of an UE. Subsequent to the fire, the inspectors discussed the fire with operations, engineering and PBAPS management personnel to gain an understanding of the event and to assess their followup actions. The inspectors reviewed operator logs and operators actions taken in accordance with licensee procedures. Based on the operators narrative logs, the fire brigade was dispatched to the Unit 3 turbine building at approximately 9:20 a.m. Fire personnel investigated and notified the MCR that an actual fire existed at 9:38 a.m. An Unusual Event for a fire not extinguished within 15 minutes (emergency action level (EAL) HU6) was declared at 9:41 a.m. All state and local government notifications were completed by 9:59 a.m. and the NRC Headquarters Operations Officer was notified of the event at 10:36 a.m. The fire was considered to be extinguished at approximately 10:32 a.m. At 11:37 a.m., the Unusual Event was terminated. Prior to the report of the potential fire, Unit 3 was operating at full power. As a result of fire and the associated response actions, numerous non-safety-related loads powered by the 4T4\' 480 Volt load center were de-energized. Equipment that was de-energized included: the B isophase bus cooler fan, the B drywell chiller, the B recirculation pump speed controller, the leading edge flow meters and the B reactor feed pump. Plant operators took the required TS actions and responded to the equipment losses by performing controlled reactor power reductions and stabilized the plant at approximately 50 percent of rated power. The inspectors verified that the required reports were made during the event and that no further reports are planned. The inspectors also verified that this issue (IR 569889) was placed into the CAP. Preliminarily, PBAPS has determined that the fire resulted from an apparent mismatch between the ratings of one breaker and its cubicle in the 4T4\' 480 volt load center. A root cause investigation was ongoing at the end of the inspection period and will be reviewed by the inspectors during a future inspection period. At the close of this inspection period, the inspectors were reviewing the event and awaiting the results of the root cause evaluation to understand the potential performance deficiencies. This issue is unresolved pending review of PBAPSs causal evaluation and corrective actions by the inspectors to characterize the issue. URI 05000277/2007002-04, Incorrect Size Breaker Resulted in a Fire in the 4T4\' 480 Volt Load Center.
05000277/FIN-2004003-03	2004Q2	Severity level IV		Licensee-identified	Licensee-Identified Violation	10 CFR 55.25 requires in part, that the facility licensee notify the Commission within 30 days of discovery, that a licensed operator has been diagnosed with a permanent physical condition that adversely affects the performance of assigned operator job duties, so that the Commission can make a determination of the licensed operators medical fitness. Contrary to this requirement on March 20, 2003, the facility licensee identified that a licensed operator underwent a medical procedure in December 1998 that should have been reported to the NRC. This issue was of very low safety significance because upon review of additional information provided by the facility licensee, the NRC physician determined that a restriction would not have been required because the licensed operator would have been able to perform licensed responsibilities without impairment. This failure to report medical information to the NRC impacted the regulatory process, and therefore, is classified at Severity Level IV.
05000277/FIN-2003013-01	2003Q4	White		Self-revealing	Failure to Adequately Maintain the E2 Emergency Diesel Generator	A self-revealing finding was identified for the failure to adequately maintain the E2 emergency diesel generator (EDG) between July 1992 and September 2003. This finding involved two apparent violations. An apparent violation of Technical Specifications was identified for the failure to maintain the maintenance procedure for installation of EDG adapter gaskets. The procedure did not incorporate certain vendor recommendations intended to provide proper sealing of the gaskets, leading to relaxation over several years that allowed combustion gases to enter the jacket coolant system. An apparent violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Actions was identified because Exelon did not correct a condition adverse to quality following two instances of low jacket water pressure observed on the E2 emergency diesel generator (EDG) in March and April 2003. Subsequently, the EDG failed due to a low jacket water pressure condition. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affects the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. The finding was assessed using a Phase 3 evaluation. The finding is of low to moderate safety significance (WHITE) at Unit 2 based on delta core damage frequency ( CDF) and delta large early release frequency ( LERF). The finding is of very low safety significance (GREEN) at Unit 3 based on CDF and LERF. The difference between the two units is attributable to differences in electrical bus loads. (Section 2.2)
05000277/FIN-2003004-04	2003Q3	Severity level IV		NRC identified	Inadequate Emergency Plan Change Documentation, 10 CFR 50.54(Q)	The inspector identified a Severity Level IV non-cited violation of 10 CFR 50.54(q). During the implementation of a new Standard Emergency Plan, Exelon did not retain a record that determined whether a decrease-in-effectiveness had or had not occurred when Exelon generated the new Standard Emergency Plan that deleted portions of the previous Combined Limerick/Peach Bottom Emergency Plan. Changing emergency plan commitments without documentation impacts the NRC's ability to perform its regulatory function and is, therefore, processed through traditional enforcement as specified in Section IV.A.3 of the Enforcement Policy, issued May 1, 2000 (65 CFR 25388). According to Supplement VIII of the Enforcement Policy, this finding was determined to be a Severity Level IV because it involved a failure to meet a requirement not directly related to assessment and notification.
05000277/FIN-2003008-01	2003Q1	Severity level IV		NRC identified	10 CFR 50.54(Q) Violation for Decreasing the Effectiveness of the Plan by Changing Eals That Address Toxic Gas Without Prior NRC Approval	Severity Level IV. The licensee changed its emergency action level schemes such that there would be a reduction in declarable events as the emphasis shifted from personnel safety to equipment status. The changes were determined to be a decrease in the effectiveness of the emergency plans. Decreases in the effectiveness of an emergency plan must Page 7 of 8 receive NRC review prior to implementation. The changes were implemented without NRC approval. The finding was determined to be more than minor as its significance was related to the impact it would have on the mobilization of the emergency response organization and preclude offsite agencies from being aware of adverse conditions on site. The licensee accepted the NRC's position and entered this issue into its corrective action program (Condition Report 139997) and will change the emergency action levels back to the original wording. The implementation of the changes which decreased the effectiveness of the emergency plans, without NRC review, is being treated as a non-cited violations consistent with Section VI.A of the Enforcement Policy, issued on May 1, 2000 (65 FR 25388).
05000277/FIN-2000013-01	2000Q4	Severity level IV		NRC identified	N/A	The team identified a non-cited Severity Level IV violation of 10 CFR 55.31(a)(4) because an operator license application was submitted to the NRC in August 1999 with incorrect information. The application was incorrect because it indicated that the individual completed all required training even though the emergency preparedness portion of his required training was not completed until May 2000 (approximately eight months after the individual had been licensed) When evaluating this issue according to NRC Manual Chapter 0610*, Appendix B, it did involve extenuating circumstances in that the issue potentially impacted the NRCs ability to perform its regulatory function. The teams evaluation of the apparent cause indicated a problem between the emergency preparedness and operator training organizations, and limited to one individual. The issue was documented in PECOs corrective action program as Performance Enhancement Program Issue I0012084. (Section 4OA2.a)

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