Semantic search

This page or action requires JavaScript to work. Please enable JavaScript in your browser or use a browser where it is supported, so that functionality can be provided as requested. For further assistance, please have a look at the noscript help page.

Search Clear all entries

	Quarter	Site	Title	Description
05000390/FIN-2018003-07	2018Q3	Watts Bar	Licensee-Identified Violation	This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Watts Bar Unit 1 TS LCO 3.8.7, Inverters-Operating, requires that two inverters in each of the four channels shall be operable. Contrary to the above, the licensee failed to ensure that two inverters in each of the four channels were operable. Specifically, from April 9, 2017 to January 10, 2018 inverter 1-II was inoperable due to an unqualified class 1E capacitor associated with the inverter.
05000390/FIN-2018003-06	2018Q3	Watts Bar	Licensee-Identified Violation	This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Watts Bar Unit 1 TS 3.8.1, AC Sources - Operating, Condition A, requires, in part, that an inoperable required offsite circuit be restored to operable status within 72 hours. Contrary to the requirements of Technical Specification 3.8.1, a required offsite circuit was determined to be inoperable from May 27, 2017, to June 2, 2017.
05000390/FIN-2018003-05	2018Q3	Watts Bar	Licensee-Identified Violation	This violation of very low safety significance was identified by the licensee and has been entered into the licensees corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Watts Bar Nuclear Plant (WBN) Unit 1 Operating License Number NPF-90, Condition 2.F, requires, in part, that TVA shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the Fire Protection Report for the facility, as approved in Appendix FF Section 3.5 of Supplement 18 and Supplement 29 of the SER (NUREG-0847). The WBN Fire Protection Report was developed for WBN to ensure compliance with the requirements of this license condition. Fire Protection Report, Part II, is the Fire Protection Plan. The Fire Protection Plan, Section 14, Fire Protection Systems and Features Operating Requirements (ORs), Subsection 14.10, Fire Safe Shutdown Equipment, paragraph 14.10.4, requires a fire watch to be established in auxiliary building room 757-A10 within one hour of closing pressurizer block valve 1-FCV-68-332-B. Contrary to the above, on July 19, 2018, the licensee failed to establish a fire watch in auxiliary building room 757-A10 within one hour of closing pressurizer block valve 1-FCV-68-332-B.
05000391/FIN-2018003-04	2018Q3	Watts Bar	Inadequate Sensitive Equipment Control Results in Unit 2 Reactor Trip on April 12, 2018	A self-revealed Green finding and associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion V, Instructions, Procedures, Drawings, was identified for the licensees use of a procedure that was not appropriate to the circumstances, which led to the conduct of improperly planned maintenance on sensitive equipment, ultimately resulting in a reactor trip. Specifically, an inadequacy was identified in station procedure 0-TI-12.10, Control of Sensitive Equipment, which lists the sensitive equipment defined, in part, as equipment that could cause a unit trip, on which work activities are required to be appropriately planned and conducted in a manner that will preclude a unit trip. The procedure did not list the high side reactor coolant system loop flow transmitter common drain line as sensitive equipment, which allowed the licensee to improperly perform maintenance on it without the appropriate planning and control necessary to preclude the Unit 2 reactor trip that occurred on April 12, 2018.
05000390/FIN-2018003-03	2018Q3	Watts Bar	Failure to Collect Compensatory Samples for an Out-of-Service Effluent Monitor	The inspectors identified a Green finding and associated NCV of TS 5.7.2.3 when the licensee failed to take compensatory samples in accordance with Table 1.1-1 of the Offsite Dose Calculation Manual when the Unit 1 steam generator blowdown effluent monitor was out of service. Specifically, radiation monitor 1-RM-90-120/121 was inoperable from April 27 to May 27, 2018, and compensatory samples were not collected and analyzed within the required frequency of at least once per 24 hours.
05000391/FIN-2018003-02	2018Q3	Watts Bar	Unauthorized Entry Into a High Radiation Area	A self-revealed Green finding and associated NCV of TS 5.11.1.e was identified when the licensee failed to maintain current survey information and failed to inform a worker of increased dose rates in a high radiation area. As a result, a worker received an electronic dosimeter alarm on the Unit 2 pressurizer platform due to changing radiological conditions associated with a reactor mode change.
05000390/FIN-2018003-01	2018Q3	Watts Bar	Configuration Control Error Results in Actual Auxiliary Building Internal Flooding Event	A self-revealed Green finding and associated NCV of Technical Specification (TS) 5.7.1, Procedures, was identified when the licensee failed to maintain adequate configuration control in the high pressure fire protection (HPFP) system in accordance with station configuration control procedure, NPG-SPP-10.2, Clearance Procedure to Safely Control Energy. Specifically, the licensee failed to restore HPFP system vent and drain valves to their appropriate configuration prior to returning the system to service which resulted in a significantly large amount of HPFP system water (on the order of 10,000 gallons) being introduced into many areas (including all levels) of the Unit 1 side of the auxiliary building and wetting numerous structures, systems, and components (SSCs) (including cables, ventilation ducts, motor-operated valves, etc.)
05000250/FIN-2016004-01	2016Q4	Turkey Point	Unrecognized Inoperable Reactor Protection System Instrument Channel	A self-revealing NCV of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.1 was identified for the licensees failure to input the correct Eagle 21 resistance temperature detector (RTD) coefficients into the Eagle 21 reactor protection system (RPS) which resulted in channels being inoperable for longer than their allowed outage times. Immediate corrective actions to restore compliance included inputting the correct RTD coefficients into the Eagle 21 RPS. Planned corrective actions to prevent recurrence included revising engineering procedures to include validation that the RTD coefficients were derived via the correct methodology. This issue was entered into the licensees corrective action program as action request (AR) 02129632. The licensees failure to input the correct RTD coefficients into the Eagle 21 RPS was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage) because the specified safety function of each functional unit was not met. The inspectors evaluated the significance of this finding and determined the finding was of very low safety significance (Green) because the finding did not affect the function of other redundant or diverse methods of reactor shutdown. The NRC assigned a cross cutting aspect associated with the Resources element of the Human Performance area because the licensee failed to ensure that procedures related to RTD replacement contained adequate information for verifying and inputting correct RTD coefficients (H.1).
05000269/FIN-2016003-01	2016Q3	Oconee	Failure to Translate Design Requirements to Prevent the Effects of Waterhammer	The NRC identified a finding for the licensees failure to translate the limiting flow rate design requirement into station procedures used to start and operate the alternate reactor building cooling (RBC) system, in accordance with the Duke Energy Carolinas Topical Report, Quality Assurance Plan (QAP). Specifically, the licensee failed to translate the limiting flow rate of 170 gallons per minute (gpm) into Procedure AP/0/A/1700/051, Alternate Reactor Building Cooling, Revision (Rev.) 2, to ensure prevention of waterhammer on the A reactor building cooling unit (RBCU) or connecting low pressure service water (LPSW) lines when starting the RBCU Hale pump. The licensee entered this issue into their corrective action program as Action Request (AR) 02049903 and revised Procedure AP/0/A/1700/051 to limit the RBCU Hale pump discharge flow to each affected unit to an initial fill rate of 120 gpm or less. The performance deficiency was determined to be more than minor because it adversely affected the protection against external factors 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, opening the RBCU Hale pump discharge valve four turns, as specified in the procedure, would have resulted in filling the alternate RBC system at approximately 600-700 gpm and exceeding the design flow rate of 170 gpm established to prevent equipment and piping damage as a result of waterhammer. This provided a reasonable doubt that the alternate RBC system had the capability to reliably perform its intended safety function and, in turn, that the protected service water (PSW) system had the capability to meet its 30-day mission time during a turbine building fire that resulted in a loss of offsite power. The finding was determined to be of very low safety significance (Green) because the finding would not have resulted in a fire that caused secondary fires outside of the originating fire area due to circuit issues and did not affect the ability to reach and maintain a stable plant condition within the first 24-hours of a fire event. The inspectors determined the finding was indicative of present licensee performance and was associated with the cross-cutting aspect of design margin, in the area of human performance. Specifically, the licensee failed to operate and maintain the alternate RBC system equipment within design margins when they did not translate design requirements from Engineering Change (EC) 110008 and Calculation OSC-8107 into station procedures.
05000287/FIN-2016003-02	2016Q3	Oconee	Licensee-Identified Violation	Technical Specification (TS) 5.4.1., Procedures, states, in part, written procedures shall be established, implemented, and maintained covering activities described in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Procedure MP/0/A/3009/017, Visual PM Inspection and Electrical Motor Tests is used by the licensee during maintenance of electric motors. Contrary to the above, on April 25, 2016, the licensee did not adequately implement maintenance procedure MP/0/A/3009/017. Specifically, the licensee incorrectly wired the 3C RBCU motor control center contactor leads during maintenance causing 3C RBCU fan to operate in the reverse direction. On June 16, 2016, during an engineer walkdown, the engineer noted anomalies in the RBCU inlet temperature readings. On June 28, 2016, while investigating the temperature readings the licensee discovered that the 3C RBCU fan was operating in the reverse direction and declared the 3C RBCU inoperable. The 3C RBCU was inoperable when the plant entered Mode 4 on May 14, 2016 until June 28, 2016 when the 3C RBCU was repaired (approximately 45 days). Technical Specification 3.6.5, Reactor Building Spray and Cooling Systems, requires all three trains of RBCU operable while in Modes 1, 2, 3, and 4. On May 14, 2016, Unit 3 was starting-up from the refueling outage and entered Modes 4 through 1 with one train of RBCU inoperable. This action of changing modes with the 3C RBCU inoperable is prohibited by TS 3.0.4. The licensee entered this condition into their corrective action program as NCR 02041501. The licensee also restored 3C RBCU operability, trained/counseled technicians, and incorporated a procedure change which will enhance configuration control for the lifted leads aspect in the maintenance procedure for this activity. This finding was assessed using IMC 0609, Phase 1 screening worksheet of Attachment 4, Appendix A, and Appendix H, and was determined to be of very low safety significance (Green).
05000251/FIN-2016003-01	2016Q3	Turkey Point	Failure to provide adequate flood protection for the 4A RHR train	The NRC inspectors identified a non-cited violation (NCV) of Technical Specification (TS) 6.8.1, for the licensees failure to implement required housekeeping controls in the 4A residual heat removal (RHR) pump room to ensure flood protection devices would not be damaged or otherwised clogged. Specifically, the licensees failure to adequately implement station housekeeping procedure MA-AA-100-1008 to ensure flood protection devices in the 4A RHR pump room were not challenged was a performance deficiency. Immediate corrective actions included removing the debris, entering this issue into the corrective action program (CAP), and initiating a past-operability review. The inspectors determined the performance deficiency to be more than minor because it was associated with the protection against external factors attribute of the mitigating systems cornerstone and there was reasonable doubt of operability which if left uncorrected could have adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings-At-Power, the inspectors screened the finding as Green because it did not involve the total loss of any safety function. The inspectors assigned a cross cutting aspect in the area of human performance associated with the work management element because the organization failed to adequately implement a process to control work activities in a high-risk flood area, and did not adequately identify and manage risk associated with the flood-sensitive area (H.5) (Section 1R06).
05000250/FIN-2016003-02	2016Q3	Turkey Point	Communication of an NRC Inspector Presence by Security Personnel	The NRC identified an NCV of 10 CFR 50.70, Inspections, paragraph (b)(4), for the licensees failure to ensure that the arrival and presence of an NRC inspector is not communicated to persons at the facility. The licensees actions of announcing the presence and location of an NRC inspector during an unannounced inspection in the protected area was a performance deficiency. Interim corrective actions included providing a site-wide communication to all employess and providing training briefs during shift turnovers informing employees of the regulation. The licensee entered this issue into the CAP as AR 2155881. The NRC evaluated this issue under the traditional enforcement process because the act of announcing NRC presence could impact NRC ability to perform its regulatory function. Specifically, the NRC relies on its ability to perform unannounced inspections to evaluate licensee performance, and communicating the presence and location of NRC inspectors affects their ability to perform these inspections, and as such the regulatory function is impacted. Because the violation was determined to be of very low safety significance, was not repetitive or willful, and was entered into the CAP, this violation is being treated as a Severity Level IV non-cited violation consistent with the NRC Enforcement Policy. This violation was evaluated under the traditional enforcement process and thus does not have a cross cutting aspect (Section 4OA2).
05000250/FIN-2016003-03	2016Q3	Turkey Point	Improper ECC Fuse Installation	A self-revealed Green finding and associated Non-cited Violation (NCV) of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.2.2 was identified for the failure to properly insert the control power fuse for the 3B Emergency Containment Cooler (ECC) fan. The ECC unit was determined to be inoperable for greater than the allowed outage time of 72 hours and the actions required by TS LCO 3.6.2.2, Action A, were not taken. An immediate corrective action was taken to adjust the fuse holder clips on the 3B ECC breaker to provide a tight fit. Additional corrective actions initiated by the licensee in AR 2108256 included a review of recently replaced similar breakers on Units 3 and 4 to identify and schedule inspection of fuse tightness. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of Equipment Performance and adversely 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). Specifically, the 3B ECC was not available to automatically start upon receipt of a safety injection signal, and during periods with two ECCs concurrently inoperable, the ECC system would not have been able to perform its specified safety function. To determine the significance of the finding, a Senior Reactor Analyst performed a bounding risk assessment by failing all three containment coolers in the Turkey Point Standardized Plant Analysis Risk (SPAR) model for the entire exposure time of 72 days. The dominant accident sequence was a very small loss of coolant accident (LOCA) where high head safety injection fails for independent reasons. The delta-core damage frequency (CDF) due to the performance deficiency was 1E-8. The low risk result was driven by the low frequency of LOCAs, the limited exposure time, and the low risk value of the containment coolers themselves. The finding was determined to be of very low safety significance (Green). This finding was assigned a cross cutting aspect associated with the avoid complacency element of the human performance area because the licensee failed to confirm fuse holder tightness following implementation of breaker maintenance. The licenee failed to recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while executing successful outcomes.
05000400/FIN-2016002-02	2016Q2	Harris	Licensee-Identified Violation	Section 50.48(c) of 10 CFR and NFPA 805, 2001 Edition, Section 2.4.2.2.2(b), Common Enclosure Circuits, require that those circuits which share enclosures with circuits required to achieve the nuclear safety performance criteria and whose fire-induced failure could cause the loss of the required component, shall be identified to prevent propagating fires outside of the immediate fire area due to fire-induced electrical faults on inadequately protected cables. Contrary to the above, from October 1986 to September 2014, the licensee failed to meet the requirements of 10 CFR 50.48(c) and NFPA 805, Section 2.4.2.2.2(b), in that, the licensee failed to identify and provide adequate electrical fault protection for the turbine emergency oil pump control cables 11376C and 11376D. The cables could have created a common enclosure fire hazard under postulated situations which could have resulted in a secondary fire in other fire areas and could have adversely affected the capability to achieve safe and stable plant conditions. A fire-induced failure could have caused the loss of the required safe shutdown components. This violation was determined to be of very low safety significance (Green) based on the results of the IMC 0609, Appendix F, Fire Protection Significance Determination Process, Phase III Quantitative Screening Approach. A detailed risk evaluation was performed in accordance with NRC IMC 0609 Appendix F, and NUREG/CR6850 Rev. 0 and 1, using inputs from the licensees NFPA 805 Fire PRA. The major analysis assumptions included a one-year exposure interval, and secondary fires occurring between the power supply and the fire induced hot short. The dominant sequence was a fire in the main control board causing a secondary fire in the B cable spreading room which if unsuppressed could result in the inability to achieve safe shutdown resulting in core damage. The quantitative screening approach resulted in a calculated delta core damage frequency of less than 1E-06, which screened this violation to Green (very low safety significance). This violation was documented in the licensees corrective action program as Condition Report 692766.
05000400/FIN-2016002-01	2016Q2	Harris	Licensee-Identified Violation	Section 50.48 of 10 CFR, Fire Protection, states that a fire protection program that is maintained to the requirements of National Fire Protection Association (NFPA) standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, is an acceptable method for complying with the requirements of Section 50.48. Section 3.8.1 of NFPA 805 states, in part, that alarm annunciation shall allow the proprietary alarm system to transmit fire-related alarms, supervisory signals, and trouble alarms to the control room or other constantly attended location from which required notifications and response can be initiated. Contrary to the above, from December 2015, to May 17, 2016, neither the licensees design reviews nor post-modification tests identified that the fire protection system installed on the 286-ft elevation of the turbine building did not transmit trouble alarms to the Harris main control room. Following installation and testing, the newly-installed Protecta WireTM system and fire detection panel, 1-SFD-E144, were placed in service in late December 2015. On May 17, 2016, while performing maintenance periodic test, MPT-I0052, Turbine Building Local Fire Detection Control Panel LFDCP-10 Test and 1-SFD-E144 Test of the fire detection system, the technicians performing the test recognized that the remote trouble alarm function would not cause an alarm in the control room. The licensee entered the issue concerning the inadequate remote alarm function into the corrective action program via AR 2030427 and implemented actions to incorporate and test the remote trouble alarm function into the EC package. The licensee also initiated corrective actions via AR 2033716 and AR 2038682 to address issues in the design review process. Using IMC 0609, Appendix F, Fire Protection Significance Determination Process, the inspectors determined this finding to be of very low safety significance (Green) since the reactor would still be able to achieve and maintain safe shutdown.
05000269/FIN-2016007-02	2016Q1	Oconee	Postulated Fire Affecting High Pressure Injection Pump Did Not Receive a VFDR Evaluation	The NRC identified a Green NCV of 10 CFR 50.48(c) and National Fire Protection Association Standard (NFPA) 805, Section 2.4.2.4 for the licensees failure to perform an adequate engineering analysis to determine the effects of fire on the ability to achieve the nuclear safety performance criteria, and consequently, did not add an associated variation from deterministic requirements (VFDR) into the Fire probabilistic risk assessment (PRA). Specifically, the licensees Nuclear Safety Capability Assessment (NSCA) failed to identify cables in the turbine building (TB) that could prevent the operation of the High Pressure Injection (HPI) Pumps. This item was entered into the corrective action program (CAP) as action request (AR) 02011673, and the licensee implemented compensatory measures in the form of hourly fire watches. The performance deficiency (PD) was more than minor because it was associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire), and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensees failure to analyze the effects of fire damage on the HPI cables in the TB could result in fire damage adversely affecting the ability to achieve and maintain safe and stable conditions. Using the guidance of IMC 0609, App. F, the finding was screened as Green because the finding did not affect the ability to reach and maintain a stable plant condition within the first 24 hours of a fire event (Task 1.4.5-B). A cross cutting aspect in the area of Human Performance, Consistent Process because the licensee did not use a consistent, systematic approach to make decisions, and did not incorporate appropriate risk insights (H.13).
05000269/FIN-2016007-01	2016Q1	Oconee	Pressure Boundary of Motor Operated Valves Could be Breached Due to Fire- Induced Hot Short	An unresolved item was identified regarding the licensees evaluation of certain motor operated valves (MOVs) in the NSCA. Specifically, based on the conclusions in the licensees NSCA, as well as subsequent evaluations, MOVs that are subject to a hot short that bypasses the torque or limit switch could result in damage to the valve that causes an unmitigated loss of reactor coolant system (RCS) inventory due to leakage through the damaged valves pressure boundary or the valves associated sealing components. Information Notice 92-18, Potential for Loss of Remote Shutdown Capability During a Control Room Fire, stated that fire damage could cause an electrical hot short that bypasses thermal overload protection for MOVs, and that this hot short could result in damage to the valve. As a part of the licensees transition to NFPA 805, the licensee identified a number of MOVs that could be susceptible to IN 92-18 type damage. These valves were classified as non-compliant components or variances from deterministic requirements (VFDRs). The subsequent evaluation of these valves by the licensees Fire PRA group determined that these VFDRs met the acceptance criteria of the Fire Risk Evaluation, as documented in OSC-9314, as being acceptable "as-is" and that no further action was required. These VFDRs and their FPRA dispositions were communicated to the NRC in the April 2010 Oconee NFPA 805 license amendment request (LAR). Subsequent to NRCs issuance of the SER, Oconee Valve Engineering determined that, due to the size of the installed motor/gearbox, 10 MOVs could potentially suffer IN 92-18 damage to the extent that the integrity of the valve body or bonnet could be compromised. Loss of valve integrity of the valve pressure boundary was not an assumption used in the FPRA evaluation. The licensee documented this condition in AR 01906086. After further evaluation, the licensee documented in AR 01999309 that 9 of the original 10 valves identified could potentially suffer IN 92-18 damage to the extent that the integrity of the valve body or bonnet could be compromised. For the 9 affected valves, the licensee has undertaken additional evaluations to determine whether some portion of the valve would fail before the valves pressure boundary is compromised, or that any possible leakage that may result can be bounded by the credited RCS make-up sourcein this case, the reactor coolant make-up pump. Inspectors determined that no immediate safety concern existed with this item because the licensee had implemented compensatory measures in accordance with the sites approved FPP. This item is unresolved pending inspector receipt and review of the licensees evaluation.
05000338/FIN-2015008-02	2015Q4	North Anna	ECST Level Indication/Setpoints and Associated Operator Action that Ensures the Auxiliary Feedwater Pumps have an Adequate Suction Source	The inspectors identified an Unresolved Item (URI) associated with the emergency condensate storage tank (ECST) level indication/setpoints and associated operator actions that ensures the auxiliary feedwater (AFW) pumps have an adequate suction source. UFSAR, Section 7.4-2, states that the emergency condensate storage tank (ECST) was designed to supply the initial eight hours of water to the auxiliary feedwater (AFW) pumps during licensing bases events. The inspectors noted that the licensee utilized operator actions to reduce AFW flow during the initial stages of events which is typically accomplished in order to prevent over cooling of the primary RCS during events where maximum AFW is not required. For events where maximum AFW may be required, the licensee developed calculations to ensure that an adequate water supply was maintained. The licensees Calculation ME-0584, Maximum AFW Pump Flow and NPSH Analysis, (dated 11/04/1999) determined that AFW flow reduction was required within the initial 30 minutes of an event to ensure that the pumps had sufficient net positive suction head. The inspectors determined, in some cases, that operator actions would be required prior to the receipt of the ECST tank level alarm that was described UFSAR Section 10.4.3.3, which stated that the ECST had redundant ECST safety-level alarms (1/2-CN-LI-200A and -200B) to alert operators that sufficient inventory remained for 20 minutes of pump operation at the highest-volume flow rates. Additionally, the inspectors noted that a Virginia Electric Power Company letter, dated December 22, 1999, stated that Technical Specifications ensure that the level maintained in the ECST is adequate to mitigate the accident without operator action during a design basis accident. Therefore, the indication of ECST level is not required as a Type A variable. Indication of ECST level remains a Type D, Category 1 variable... This issue is unresolved pending the NRCs review of applicable licensing requirements, calculations, and operating procedures to assess the adequacy of the ECST level indication/setpoints and associated operator actions to ensure that the AFW pumps have an adequate suction source as described by their licensing design basis. This issue is identified as URI 05000338 & 05000339/2015008-02, ECST Level Indication/Setpoints and Associated Operator Action that Ensures the Auxiliary Feedwater Pumps have an Adequate Suction Source.
05000338/FIN-2015008-01	2015Q4	North Anna	Inadequate Procedural Guidance for Implementing Alternative Shutdown for a Fire in the Unit 2 Quench Spray Pump House	The inspectors identified a Green non-cited violation (NCV) of Technical Specification 5.4.1.a, for the licensees failure to provide adequate procedural guidance for implementation of the alternative shutdown capability in the event of a fire in the quench spray pump house. In particular, the fire safe shutdown procedure did not include actions to locally fail open the Unit 2 turbine-driven auxiliary feedwater (TDAFW) pump steam admission valves to allow operation of the TDAFW pump in the event the motor driven auxiliary feedwater pumps (MDAFW) were adversely affected by fire damage. The licensee entered this issue in their corrective action program as CR 1017083 and established compensatory actions until the Unit 1 and 2 procedures were revised. The sites failure to maintain adequate procedural guidance to operate the Unit 2 TDAFW pump for a fire in the quench spray pump house was determined to be a performance deficiency. This performance deficiency was more than minor because it was associated with the procedure quality attribute of the reactor safety mitigating systems cornerstone and it affected the cornerstone objective of protection against external events (i.e., fire). The inadequate procedural guidance affected the fire protection defense-in-depth element involving safe shutdown of the reactor. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.3.1, Question A, based upon observations that there were no credible fire scenarios which would likely result in simultaneous fire damage to the cables for the Unit 2 TDAFW pump and both Unit 2 MDAFW pumps. No cross-cutting aspect was identified because the issue was determined to not reflect current licensee performance.
05000338/FIN-2015008-03	2015Q4	North Anna	Failure to Ensure that the Turbine-driven Auxiliary Feed Water Pump had the Capability to Provide Sufficient Flow Such that Residual Heat Removal Entry Conditions Could Be Achieved during Fire Event	The inspectors identified a Green non-cited violation (NCV) of North Anna Power Station, Units No.1 and No. 2, Renewed Facility Operating License, Conditions 2.D, Fire Protection, for the licensees failure to ensure that the turbinedriven auxiliary feed water (AFW) pump had the capability to provide sufficient flow such that residual heat removal (RHR) entry conditions could be achieved during fire events. The licensee entered this issue in their corrective action program as CR 1017291 with an action to re-evaluate the capability of the TDAFW pumps to achieve RHR entry conditions. The sites failure to provide reasonable assurance that the turbine-driven AFW pump had the capability to provide sufficient flow such that RHR entry conditions could be met was a performance deficiency. This performance deficiency was more than minor because it was associated with the design control attribute of the reactor safety mitigating systems cornerstone and it affected the cornerstone objective of protection against external events (i.e., fire). The performance deficiency adversely affected the sites capability to achieve cold shutdown conditions in 72 hours for a fire event. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.3.1, Question A because the issue was associated with achieving cold shutdown conditions. The inspectors determined that the performance deficiency had a cross-cutting aspect of Teamwork in the Human Performance area (H.4).
05000424/FIN-2015007-01	2015Q3	Vogtle	Failure to Fully Close and Latch Plant Fire Doors	An NRC-identified Green non-cited violation of Vogtle Units 1 and 2 Operating License Conditions 2.G, was identified for the licensees failure to ensure that fire doors V22108L1A67, V12111L1238, and V12111L1A41 in 3-hour rated fire barriers were fully closed and latched, as required by the approved fire protection program (FPP) and National Fire Protection Association (NFPA) Code 80-1983, Fire Doors and Windows (Vogtle NFPA Code of Record). The licensee took corrective actions and declared fire door V22108L1A67 inoperable and established a roving fire watch. The inoperable door was entered into the licensees corrective action program as condition report (CR) 10067247 and was repaired the next day. For doors V12111L1238 and V12111L1A41, the licensee immediately removed materials that were interfering with the latching of the doors and entered these into their corrective action program as CR 10096004 and CR10096008 respectively. Because these two conditions were corrected as soon as they were brought to the licensees attention by the inspectors, no fire watch was required to be established. The licensees failure to ensure the three fire doors were fully closed and latched as required by the approved FPP and NFPA Code 80-1983 was determined to be a performance deficiency. This performance deficiency was more than minor because it affected the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e., fire) and adversely affected the fire protection defense-in-depth element involving fire confinement and control of fires that do occur to protect systems important to safety. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding involved the ability to confine a fire. The finding category of Fire Confinement was assigned, based upon that element of the FPP being impacted. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.4.3, Question C, based upon observation that a fully functioning, automatically actuated, fire suppression system was installed on both sides of fire doors V12111L1238 and V12111L1A41 and on one side of fire door V22108L1A67. The inspectors determined that the finding had a cross-cutting aspect of Procedure Adherence in the Human Performance area because individuals did not follow processes and procedures for ensuring that fire doors were properly closed and latched after passing through the doors.
05000424/FIN-2015007-02	2015Q3	Vogtle	Failure to Identify and Repair a Degraded Fire Penetration Seal	An NRC-identified Green non-cited violation of Vogtle Unit 1 Operating License Condition 2.G was identified for the licensees failure to identify and repair degraded fire penetration seal 1-11-759A, as required by the approved fire protection program (FPP). The licensee took corrective actions to declare the penetration seal inoperable, entered the issue in their corrective action program as condition report 10102010 and established a roving fire watch. The licensees failure to identify and repair the degraded fire penetration seal 1-11-759A was a performance deficiency. This performance deficiency was more than minor because it affected the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e., fire) and adversely affected the fire protection defense-in-depth element involving fire confinement and control of fires that do occur to protect systems important to safety. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding involved the ability to confine a fire. The finding category of Fire Confinement was assigned, based upon that element of the FPP being impacted. Using the criteria contained in IMC 0609 Appendix F, Attachment 2, Table A2.2, the inspectors concluded that the seal degradation level was low because the silicone foam seal depth and a fully intact damming board on one side of the barrier would have been sufficient to provide at least two hours of fire resistance. In addition, it was noted that the fire zones on each side of the degraded fire penetration seal were protected with an automatic fire suppression system. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.4.3, Question C. The inspectors determined that the finding had a cross-cutting aspect of Avoid Complacency in the Human Performance area because individuals inspecting the seals failed to recognize and plan for the possibility of the penetration seal being damaged.
05000364/FIN-2014009-01	2014Q3	Farley	Installation of 1.5-hour UL Labeled Fire Door in a Required 3-hour Fire Barrier on Unit 2	An NRC-identified non-cited violation (NCV) of Unit 2 Operating License Condition (OLC) 2.C. (6), Fire Protection, was identified for the failure to ensure that a fire door that was part of a fire barrier was provided with a 3-hour labeled door as required by 10 CFR 50.48 and the approved Fire Protection Program (FPP). Fire Area 2-20, Auxiliary Building Corridor is required to be separated from Fire Area 2-21, Unit 2 Train B Switchgear Room, by 3-hour rated fire barriers. The inspectors observed that fire door 2219, in the wall separating these two fire areas, was installed with a Underwriters Laboratory (UL) label fastened to it, identifying it as a 1.5-hour rating rather than a labeled 3-hour rated fire door. The licensee entered these issues into the corrective action program (CAP) as CRs 814872, 843303 and 840832, and implemented an hourly roving fire watch in the affected Fire Areas as a compensatory measure, LCO No. 2-2014-0111. The licensees failure to ensure that fire door 2219 was a functional UL labeled Class A 3-hour door, as required by the approved FPP, was determined to be a performance deficiency. The performance deficiency 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 significance of this finding was evaluated using IMC 0609, Appendix F, Fire Protection Significance Determination Process , dated September 20, 2013 because the performance deficiency affected fire protection defense-in-depth strategies involving fire confinement. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.4.3, Question B, because the barrier door (as evidenced by a UL door label of 1.5-hours) will provide a 1-hour or greater fire endurance rating. A Cross Cutting Aspect of H.12, Avoiding Complacency was assigned to this finding because individuals did not recognize or plan for the possibility of mistakes, issues or risk during the fire doors receipt inspection, installation and post-installation surveillance.
05000400/FIN-2014008-01	2014Q2	Harris	Failure to Identify and Evaluate All Targets Within the Zone of Influence of Ignition Sources	An NRC-identified non-cited violation of 10 CFR 50.48 (c) and National Fire Protection Association Standard (NFPA) 805 Section 2.4.3.2 was identified for the licensees failure to address in the Fire Probabilistic Risk Assessment (Fire PRA) the risk contribution associated with all potentially risk significant fire scenarios for a given fire compartment/fire area. The licensee did not identify and evaluate all targets that were within the zone of influence (ZOI) of ignition sources for selected fire scenarios which could potentially contribute to the risk for the fire scenarios. The licensee entered the issue in the corrective action program as Nuclear Condition Reports 682633 and 685355 and established an hourly roving fire watch as compensatory measures. The licensees failure to comply with the requirements of 10 CFR 50.48(c) and NFPA 805 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external factors (i.e., fire) 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 missed targets in the ZOI for the selected fire scenarios had the potential to impact the ability to achieve safe and stable conditions. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding affected post-fire SSD. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the finding was screened as Green in step 1.6.1 Screen by Licensee PRA-Based Safety Evaluation. An SDP Phase 3 analysis was performed to document the review of the risk determination of the missed ignition source-target interactions using the licensees Fire PRA model. A senior reactor analyst performed the Phase 3 SDP analysis in accordance with the guidance in IMC 0609 Appendix F and NUREG/CR-6850 Revisions 0 and 1. The evaluation determined that the missed ignition source-target interactions resulted in a CDF increase of 5.91E- 8/year, a Green finding of very low safety significance. There was no cross cutting aspect assigned to this finding because it was not indicative of current licensee performance since the original ignition source and target walkdowns were performed in 2006 and 2007.
05000327/FIN-2014007-01	2014Q1	Sequoyah	Improper Orientation of Fire Dampers in Auxiliary Building	An NRC-identified Green non-cited violation of Sequoyah Operating License Conditions 2.C.(16) and 2.C.(13) for Units 1 and 2 respectively, was identified for the licensees failure to ensure that fire dampers were functional, as required by the approved fire protection program (FPP), in the Auxiliary Control Room (fire area FAA- 066), Vital Battery Board Room II (fire area FAA-068), and Vital Battery Board Room III (fire area FAA-087) fire area boundaries. The licensee entered this issue into the corrective action program as Problem Evaluation Reports 845913 and 848580, and implemented hourly roving fire watches in the affected fire areas. The licensees failure to ensure the fire dampers were functional as required by the FPP was determined to be a performance deficiency. This performance deficiency was more than minor because it affected the reactor safety mitigating systems cornerstone attribute of protection against external factors (i.e., fire) and it affected the fire protection defense in depth strategies involving the control of fires that do occur and to protect systems important to safety. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding involved the ability to confine a fire. The finding category of Fire Confinement was assigned, based upon that element of the FPP being impacted. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.4.3, Question C, based upon observation that a fully functional automatic sprinkler system was on either side of each affected fire barrier partition. No cross cutting was assigned to this finding because the cause of the finding was not indicative of current licensee performance. The dampers were purchased and installed in 1997.
05000327/FIN-2014007-05	2014Q1	Sequoyah	Failure to Perform the Required Reviews when Adding Fire Watches to the Fire Protection Program	An NRC-identified Green non-cited violation of Sequoyah Operating License Conditions 2.C.(16) and 2.C.(13), for Units 1 and 2 respectively, was identified for the licensee's failure to perform the required reviews when adding fire watches to the fire protection program. The licensee entered the issue into their corrective action program as Problem Evaluation Report 845593. The licensees failure to perform the required evaluation and review prior to revising the fire hazards analysis was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events (fire) to prevent undesirable consequences. Specifically, the sole use of fire watches as a mitigation measure for the unavailability of the credited pressurizer power operated relief valve would adversely affect the capability to achieve and maintain safe shutdown during a fire event. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding affected fire protection defense-in-depth strategies involving post-fire SSD. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the issue screened as having very low safety significance (Green) at Task 1.5.3 because the change in core damage frequency (delta CDF) was less than 1E-6 (i.e., delta CDF calculated to be 6.6E-7). The cause of this finding was determined to have a crosscutting aspect of Evaluation (P.2) in the Problem Identification and Resolution crosscutting area, because the licensee did not thoroughly evaluate the issue to ensure that resolutions addressed causes commensurate with their safety significance. Specifically, the establishment of effective corrective actions was adversely affected by the failure to perform an evaluation prior to revising the fire hazards analysis.
05000327/FIN-2014007-04	2014Q1	Sequoyah	Failure to Maintain Necessary Materials and Procedures for Cold Shutdown Repairs	An NRC-identified Green non-cited violation of Sequoyah Operating License Conditions 2.C.(16) and 2.C.(13), for Units 1 and 2 respectively, was identified for the licensee's failure to maintain necessary materials and procedures for cold shutdown repairs, as required by the approved fire protection program. The licensee entered this issue into the corrective action program as Problem Evaluation Reports 845931, 847420, 847428, 847449, and 847462. The licensees failure to provide adequate guidance for all repairs listed in the Appendix R casualty procedure and failure to maintain the required repair parts for the same procedure was a performance deficiency. The performance deficiency was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events (fire) to prevent undesirable consequences. Inadequate procedural guidance and the lack of required materials could adversely affect the licensees capability to achieve and maintain cold shutdown conditions. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding affected fire protection defense-in-depth strategies involving post-fire safe shutdown. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green) at Task 1.3.1, because it was determined that the reactor was able to reach and maintain a hot safe shutdown condition. The cause of this finding was determined to have a cross-cutting aspect of Teamwork (H4) in the Human Performance cross-cutting area because the licensee failed to assure that individuals and work groups communicated and coordinated their activities within and across organizational boundaries to ensure nuclear safety was maintained. Specifically, the coordination between operations department procedure writers, maintenance department procedure writers, and fire operations department personnel was inadequate to ensure the adequacy of cold shutdown repair procedures and the availability of required materials.
05000327/FIN-2014007-03	2014Q1	Sequoyah	Design Control Requirements not met During Safety-Related Circuit Breaker Replacements	An NRC-identified Green non-cited violation (with two examples) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the licensees failure to assure that design documents were controlled and appropriate quality standards for design were specified as required by site procedures. The licensee entered this issue in the corrective action program as Problem Evaluation Reports 845951,846017, 848756, and 849220. The licensees failure to assure that design documents were controlled and appropriate quality standards for design were specified in accordance with design control procedures was a performance deficiency. The performance deficiency was more than minor because if left uncorrected it could lead to installation of breakers that may not meet the critical characteristics needed to perform their safety function. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process for Findings At-Power. Using IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to have very low safety significance (Green) because it did not represent an actual loss of safety function. No cross-cutting aspect was identified, since the issue was determined to not reflect current licensee performance.
05000327/FIN-2014007-02	2014Q1	Sequoyah	Auxiliary Control Instrument Room 2A Sprinklers Not in Compliance with NFPA 13-1975	An NRC-identified Green non-cited violation of Sequoyah Operating License Conditions 2.C.(16) and 2.C.(13), for Units 1 and 2 respectively, was identified for the licensees failure to properly install an automatic pre-action fire sprinkler system in Auxiliary Control Instrument Room 2A (fire area FAA-090) in accordance with the approved FPP and applicable National Fire Protection Association (NFPA) Standard No. 13, Automatic Sprinkler Systems. The licensee entered this issue in the corrective action program as Problem Evaluation Report 847948. The licensees failure to install the sprinkler heads in accordance with the applicable NFPA Code of Record specified in the approved FPP for Sequoyah is a performance deficiency. This performance deficiency is more than minor because it is associated with the reactor safety mitigating systems cornerstone attribute of protection against external factors (i.e., fire) 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 potential delayed actuation of the sprinkler system could affect the fire protection defense in depth strategy involving suppression of fires. The finding was screened in accordance with NRC IMC 0609, Significance Determination Process, Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609, Appendix F, Fire Protection Significance Determination Process, review was required as the finding involved fixed fire suppression systems. Using IMC 0609, Appendix F, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, a low degradation rating was assigned, based on the fact that four sprinkler heads were installed in a room of 110 ft2 and at least one head would be installed within 10 feet of combustibles of concern. Due to their spacing the sprinklers would be within the fire plume zone of influence for the combustibles of concern and the expected heat release rate (HRR) of postulated fires. Except as noted, the system was considered to be nominally code compliant, and therefore, met the low degradation criteria for water based suppression systems. Using IMC 0609, Appendix F, Attachment 1, Fire Protection Significance Determination Process Worksheet, the inspectors determined that the finding was of very low safety significance (Green), at Task 1.4.2, Question A. The cause of this finding was determined to have a cross-cutting aspect of Evaluation (P.2) in the Problem Identification and Resolution cross-cutting area, because the licensee did not thoroughly evaluate the issue to ensure that resolutions addressed extent of conditions commensurate with their safety significance.
05000321/FIN-2013009-01	2013Q4	Hatch	Adequacy of Carbon Dioxide (CO2) Concentration in FZ 0024B	Hatch Renewed OLCs 2.C.(3) and 2.C.(3)(a), for Units 1 and 2 respectively, state, in part, that Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the Updated Final Safety Analysis Report for the facility, as contained in the updated Fire Hazards Analysis and Fire Protection Program for the Edwin I. Hatch Nuclear Plant, Units 1 and 2, which was originally submitted by letter dated July 22, 1986. Section IV.C.5, Carbon Dioxide Suppression Systems, of Appendix D of the FHA states, in part, that the computer room design concentrations are in compliance with NFPA Standard No. 12, Section 2421, which requires a 50-percent concentration for dry electrical, wiring insulation hazards in general . NFPA 12 states, in part, that an acceptable CO2 system deliver and hold a minimum gas concentration of 50 percent in the protected area. Contrary to the above, the CO2 system design concentration in the computer room is not in compliance with the Hatch FHA, in that the CO2 system would not deliver and hold a minimum gas concentration of 50 percent in the protected area. The violation has existed since initial plant start-up. The licensee entered the deficiency in the CAP as CR 736771. Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement and reactor oversight process (ROP) discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, was not likely to have been previously identified by routine licensee efforts, was not willful, and it was not associated with a finding of high safety significance.
05000366/FIN-2013009-03	2013Q4	Hatch	Review and Documentation of Fire Protection Program Changes	Introduction: The NRC identified a non-compliance of Hatch Unit 2 Renewed OLC 2.C.(3)(a), Fire Protection, for making a change to the FPP that adversely affected the licensees ability to achieve and maintain safe shutdown. Specifically, the licensee removed the installed Unit 2 RSDP halon suppression system that was required to meet an approved exemption. The licensee failed to submit the FPP change to the NRC for review and approval prior to implementing the modification, which impacted the ability of the NRC to perform its regulatory oversight function. Description: In an SER dated April 18, 1984, the NRC allowed an exemption request from 10 CFR 50, Appendix R, Section III.G.2 for the Unit 2 Reactor Building elevation 130. In this SER, the NRC documented that the licensee committed to several modifications, which included the installation of an automatic halon fire suppression system for the Unit 2 RSDP. The halon suppression system would limit the consequences of a fire internal to the RSDP. The NRC concluded that the existing fire protection measures, with the proposed modifications, would achieve a level of safety equivalent to that provided by 10 CFR 50, Appendix R, Section III.G.2. During a plant walkdown of FA 2203 to support the review of LER 2013-004, the team noted that the halon suppression system had been abandoned in place. Discussions with the licensee revealed that the system had been abandoned since 1999. Additionally, in 2006, the licensee initiated a design change (DCP 2009001901) to completely remove the halon system, along with its associated piping and support, from the Unit 2 RSDP. The team noted that the licensees FPP is based on the defense-in-depth concept, and that this approach includes promptly detecting and extinguishing fires that occur. The condition of not having the committed suppression system was a degradation of the defense-in-depth concept. Specifically, the lack of a suppression system would adversely affect the ability to control and promptly extinguish a fire. The licensee entered the deficiency into their CAP as CR 736483. An hourly fire watch was already in place for the affected FA, because of LER 2013-004. Analysis: The team determined that the failure to obtain NRC approval prior to making a change to the FPP that was adverse to safe shutdown was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire), and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee removed the halon suppression system for the RSDP, which degraded the ability to suppress a fire that originated in the panel. The finding was screened in accordance with IMC 0609, Significance Determination Process (SDP), Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process review was required because the finding affected fixed fire protection systems. Using the Fire Protection SDP Phase 1 Screening, the finding was assigned a category of Fixed Fire Protection Systems. The team used step 1.3 Ability to Achieve Safe Shutdown, task 1.3.1 Screen Fire Finding for Ability to Achieve Safe Shutdown, of IMC 0609, Appendix F, Attachment 1 to determine the finding to be of very low safety significance (i.e., Green) because the reactor would have been able to reach and maintain safe shutdown conditions. The reactor would be able to reach and maintain safe shutdown conditions because photoelectric detectors were installed inside the RSDP and linear heat detection was installed along the sides of the cable raceways located directly above the RSDP. The installed detectors would aid in preventing the growth and spread of a fire by allowing sufficient time for the fire brigade to intervene. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Additionally, the licensees failure to submit the adverse FPP change to the NRC for review was screened under the traditional enforcement criteria, because it impacted the ability of the NRC to perform its regulatory oversight function. In accordance with Section 6.1.d.2 of the NRC Enforcement Policy, this violation was characterized as Severity Level IV because the resulting changes were evaluated by the SDP as having very low safety significance (Green). Enforcement: Hatch Unit 2 Renewed OLC 2.C.(3)(a) states, in part, that the licensee may make changes to the fire protection program without prior Commission approval only if the changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. This license condition also states that the Hatch Fire Protection Program is referenced in the Updated Final Safety Analysis Report for the facility, as contained in the updated Fire Hazards Analysis and Fire Protection Program for the Edwin I. Hatch Nuclear Plant Units 1 and 2, which was originally submitted by letter from GPC to the Commission dated July 22, 1986. Contrary to the above the licensee made a change to the FPP, without prior Commission approval, that adversely affected the ability to achieve and maintain SSD in the event of a fire. Specifically the licensee completed a 10 CFR 50.59 evaluation that erroneously concluded that the halon suppression system installed for the RSDP was not required to meet Appendix R requirements and, therefore, could be removed without prior Commission approval. The removal of the halon suppression system degraded the ability to suppress a fire and challenged the ability to achieve and maintain SSD in the event of a fire. Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement and reactor oversight process (ROP) discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48), and Inspection Manual Chapter 0305. Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, was not likely to have been previously identified by routine licensee efforts, was not willful, and it was not associated with a finding of high safety significance (i.e., Red).
05000321/FIN-2013009-02	2013Q4	Hatch	Failure to Meet Section IV.C, Fire Detection and Suppression of Appendix D of the Fire Hazards Analysis	Introduction: The NRC identified a non-compliance of Hatch OLCs 2.C.(3) and 2.C.(3)(a), for Units 1 and 2 respectively, for the failure to locate fire extinguishers in the cable spreading room (CSR) in accordance with NFPA 10 and for the failure to locate manual hose stations in or near the CSR, such that an effective hose stream could be directed to any area in the room. Description: The FHA stated that the CSR (FZ 0024A) was equipped with a hose station and a fire extinguisher located in the adjacent room (FA 0025 mezzanine) for manual firefighting. The FHA stated that the area had mostly Class A (cable insulation) combustibles with a fire duration of greater than three hours. As a result, the licensee designated the CSR as having a high combustible loading. The FHA stated that manual firefighting equipment was fully adequate to extinguish the fire if the automatic suppression system failed. The requirements for manual firefighting capabilities were described in Section IV.C, Fire Detection and Suppression of Appendix D of the FHA. Section IV.C.6 required the licensee to provide portable fire extinguishers in the plant in accordance with NFPA 10, Standard for Portable Fire Extinguishers. For Class A hazards (such as cable insulation), NFPA 10 required fire extinguishers to be located such that the maximum travel distance to an extinguisher was 75 feet. The team identified that there were no fire extinguishers located in the CSR. The closest fire extinguisher to the CSR was located in an adjacent room (FA 0025 mezzanine). Based on the physical dimensions of the CSR, and physical obstructions in the room due to cable trays, the team determined that the travel distances from at least half of the CSR to the closest fire extinguisher exceeded the 75 foot maximum travel distance specified in NFPA 10. Section IV.C.3.d of Appendix D of the FHA required the licensee to provide manual hose stations throughout the plant to ensure that an effective hose stream could be directed to any area in the plant. The team observed that there was one hose station (HS-C20) inside the CSR and another hose station (HS-C21) in the adjacent room (FA 0025 mezzanine). However, the team noted that the licensee had deemed HS-C20 as not usable because cable trays blocked access to the hose. On July 20, 2011, the licensee implemented LDCR 2011-024 to remove the regulatory requirements for this hose station. Hose station HS-C21 was selected to serve the CSR. Additional fire hose was staged at HS-C21 to ensure that area wide coverage of the CSR was available with the fire hose stream. The team noted that the licensee did not consider physical obstructions presented in the room due to cable trays and the torturous path that responders would have to take to cover the entire CSR. Therefore, the team determined that the additional fire hose staged at HS-C21 was not sufficient to provide an effective hose stream to all areas in the CSR. In response to these issues, the licensee initiated CR 740396 for the deficiency related to fire extinguisher placement; and CR 741521 for the deficiency related to the CSR fire hose coverage. The licensee also began evaluating potential locations in the CSR where fire extinguishers could be installed to facilitate firefighting efforts in the CSR. Analysis: The team determined that the licensees failure to locate fire extinguishers in the CSR, and failure to locate manual hose stations in or near the CSR such that an effective hose stream could be directed to any area in the room were performance deficiencies. The performance deficiencies were determined to be more than minor because they were associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e. fire), and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiencies could adversely impact timely manual fire suppression capability of a fire. The finding was screened in accordance with IMC 0609, Significance Determination Process (SDP), Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, review was required because the finding affected manual firefighting. Using the Fire Protection SDP Phase 1 Screening, the finding was assigned a category of Manual Firefighting. The team used step 1.3 Ability to Achieve Safe Shutdown, task 1.3.1 Screen Fire Finding for Ability to Achieve Safe Shutdown of IMC 0609, Appendix F, Attachment 1 to determine the finding to be of very low safety significance (i.e., Green) because the finding was assigned a low degradation rating. Using IMC 0609, Appendix F, Attachment 2, the finding was assigned a low degradation rating because the CSR was equipped with pre-action sprinkler system and fire detection that would alarm in the control room. Additionally, a hose station and fire extinguisher located outside the room would provide partial coverage for the CSR. The team determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance. Enforcement: Hatch Renewed OLCs 2.C.(3) and 2.C.(3)(a), for Units 1 and 2 respectively, states, in part, that Southern Nuclear shall implement and maintain in effect all provisions of the fire protection program, which is referenced in the Updated Final Safety Analysis Report for the facility, as contained in the updated Fire Hazards Analysis and Fire Protection Program for the Edwin I. Hatch Nuclear Plant, Units 1 and 2, which was originally submitted by letter dated July 22, 1986. Section IV.C, Fire Detection and Suppression of Appendix D of the FHA, contains requirements for the licensees manual suppression capability. Contrary to the above, the licensee failed to meet the requirements of Section IV.C. of Appendi D of the FHA, with the following examples: 1. Section IV.C.3.d, Water Sprinkler and Hose Standpipe Systems, of Appendix D of the FHA states, in part, that manual hose stations are located throughout the plant. An effective hose stream can be directed to any area in the plant. Contrary to the above, the licensee failed to locate manual hose stations in or near the CSR such that an effective hose stream could be directed to any area of the CSR. This issue has existed since 2011, when the licensee completed a plant change to take credit for hose HS-C21 to combat a fire in the CSR 2. Section IV.C.6, Portable Extinguishers, of Appendix D of the FHA states that portable fire extinguishers are provided in the plant in accordance with NFPA 10. NFPA 10 (1975 Edition), requires that fire extinguishers serving Class A hazards (such as cable insulation) be located such that the maximum travel distance to extinguisher is 75 feet. Contrary to the above, the licensee failed to locate fire extinguishers in an area serving Class A hazards such that the maximum travel distance to an extinguisher was not greater than 75 feet. Specifically, the licensee failed to locate portable fire extinguishers in the CSR, which contained Class A hazards such as cable insulation. This issue has existed since initial plant startup. Because the licensee committed to adopt NFPA 805 and change their fire protection licensin bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement and reactor oversight process (ROP) discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) and Inspection Manual Chapter 0305. Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, was entered into the licensees corrective action program, immediate corrective action and compensatory measures were taken, was not likely to have been previously identified by routine licensee efforts, was not willful, and it was not associated with a finding of high safety significance (i.e., Red).
05000269/FIN-2013007-05	2013Q3	Oconee	Non-Compliance to License Condition Requiring Modifications to LPG Tank was not Identified During Transition to NFPA 805	The team identified an unsecured 500 gallon (water capacity) LPG storage tank in the Transformer Yard adjacent to the CT1 transformer and the Unit 1 Turbine Building. The LPG storage tank sat on four concrete blocks and did not appear to have an excess flow control valve installed to prevent a large release of propane gas from a ruptured supply line to the Auxiliary Boiler. The licensee had previously identified these problems in PIPs O-06-01385, O-08-02163, O-11-10119 and O-13-03819. Initially, a work request was written to secure the tank but it was later closed without the work being performed. Subsequently, an engineering change request was initiated to address the issue but was never approved. In ONS License Amendment 64 for Unit Nos. 1 and 2 and License Amendment 61 for Unit 3, each units license was amended to state, in part, that The licensee is authorized to proceed and is required to complete modifications identified in Table 3.1 of the NRCs Fire Protection SER dated August 11, 1978. The modifications shall be completed on the schedule specified in Table 3.1. SER Section 3.1.7, states, Propane tanks located outside of the turbine building will be anchored and provided with excess flow valves. Table 3.1 states in part, The modification will be completed by the end of the first refuel outage for any unit which occurs after 6 months from the date of issuance of this Safety Evaluation. A letter from Duke Power Company to the NRC dated June 29, 1979 stated, in part that, The required modification had been completed. When questioned about the current configuration of the tank, the licensee stated that since the transition to their approved NPFA 805 FPP all prior FPP SERs and commitments have been superseded in their entirety by the revised license condition and that the tank was in compliance with the requirements of NFPA 805, Section 3.3.7.1 for the storage of flammable gases located outdoors. Offset distances from the tank to structures, systems or components were judged by the licensee to be sufficient to prevent adverse impact from fires or explosions. The team did not agree with this position and stated that the ONS April 14, 2010 License Amendment Request (LAR) did not address the tank or the non-compliance with the license amendment requirement of 1978. The NRC has requested additional information from the licensee to determine if a prior change to the license, made before the transition to NFPA 805, allowed the tank to remain in its current location without the originally required modifications; and, to determine if the tank had, at one time, been in compliance, but had been improperly relocated under a work order performed in 1986. This issue is unresolved pending NRC review of additional information requested to determine if the issue of concern constitutes a violation of NRC requirements. This issue is identified as URI 05000269, 270, 287/2013007-05, Non-Compliance to License Condition Requiring Modifications to LPG Tank was not Identified During Transition to NFPA 805.
05000269/FIN-2013501-02	2013Q3	Oconee	Licensee-Identified Violation	Technical Specification 5.4.1(a), Procedures, required in part that written procedures be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Rev. 2, Appendix A, February 1978. Procedure OP/0/A/1107/016, Enclosure 4.4, Removal and Restoration of 230KV Switchyard PCB, Step 2.2.4, stated, in part, Ensure locked closed PCB (27) Yellow (Red) Bus Side Disconnect. Contrary to the above, on October 22, 2012, the licensee failed to ensure PCB27 was locked closed. The licensee discovered and corrected this condition on April 24, 2013. The finding was determined to represent a loss of system and/or function which required a risk evaluation by a Senior Reactor Analyst (SRA). The SRA estimated the likelihood of faults that could lead to damage of the disconnect and multiplied these by the change in conditional core damage probability due to a loss of the transformer impacted. Dominant cutsets involved failure of one Keowee hydro unit in conjunction with LOOP sequences, operators failure to recover offsite power, or the Keowee faults within 4 hours, and failure of EFW. The risk impact was less than 1E-7 for the exposure period. In addition, the risk impact of seismic events was estimated not to be a major contributor to the change in risk. Because the risk impact was less than 1E-7, the finding was determined not to be greater than Green. Licensee personnel entered the issue into their corrective action program as PIP O-13-04503.
05000269/FIN-2013501-01	2013Q3	Oconee	Licensee-Identified Violation	Technical Specification 5.4.1(a), Procedures, required in part that written procedures be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Rev. 2, Appendix A, February 1978. Procedure OP/1/A/1102/008, Enclosure 4.35, On Line Valve Lineup for MOV Maintenance, Step 2.5, stated, in part, for the operator to cycle 1LP-22 (1B LPI BWST suction). Contrary to the above, on June 26, 2013, the licensee operator failed to follow written procedure when he closed 1LP-21 (1A LPI BWST suction) which isolated the operable LPI train from the BWST rendered Unit 1 LPI inoperable. The licensee restored the LPI A train to its proper alignment within thirteen minutes. The finding was determined not to be greater than Green because the loss of function of at least a single train did not exceed its TS allowed outage time. The licensee entered the issue into their CAP as PIP O-13-06879.
05000269/FIN-2013007-04	2013Q3	Oconee	Failure to Evaluate Unapproved Combustibles in Accordance With Procedures	An NRC-identified Green non-cited violation (NCV) of Oconee Nuclear Station Units 1, 2, and 3 Renewed Facility Operating License Condition 3.D was identified for the licensees failure to follow procedures for the control of transient combustible materials. The team identified five examples where the licensee failed to follow procedure Nuclear System Directive (NSD) 313, Control of Transient Fire Loads, in that unapproved combustible materials were stored in fire areas/fire zones without proper evaluation and without appropriate compensatory actions being implemented. The licensee entered these issues into the corrective action program as Problem Investigation Program documents O-13-07896, O-13-07897, O-13-07989, O-13-08051, and O-13-08459; and initiated immediate corrective actions to remove the unapproved combustibles from the identified fire areas/fire zones. The licensees failure to follow procedure NSD 313 for storage of transient combustibles in fire areas/fire zones was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), 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 finding was determined to be of very low safety significance (Green) because it only affected the ability to reach and maintain cold shutdown conditions. The cause of this finding was determined to have a cross-cutting aspect of H.4(b) in the Work Practices component of the Human Performance area, because the licensee did not define and effectively communicate expectations regarding procedural compliance and personnel did not follow procedures.
05000269/FIN-2013007-03	2013Q3	Oconee	Fire Protection Program Change did not Meet Oconee License Condition Requirements for NFPA 805 Chapter Three	An NRC-identified Apparent Violation (AV) and associated traditional enforcement violation of Oconee Nuclear Station Renewed Facility Operating License Condition 3.D for Units 1, 2, and 3 was identified for the licensees failure to implement and maintain in effect all provisions of the approved fire protection program (FPP) that comply with 10 CFR 50.48(c), National Fire Protection Association Standard NFPA 805. The licensee made a change to the approved FPP involving control of combustible materials when the definition of transient fire loads was revised to exclude fire retardant scaffolding materials as transient fire loads, which would not require the licensee to track these items as combustible fire loads. The licensee also failed to submit the FPP change to the NRC for review and approval prior to implementation which impacted the ability of the NRC to perform its regulatory oversight function. The licensee entered this issue into the corrective action program as Problem Investigation Program O-13-08584. This finding did not represent an immediate safety concern because the licensee implemented compensatory measures in the form of combustible tracking impairments and fire watches in the high safety significant fire zones which contained the scaffolding. Failure to comply with Oconee Operating License Condition 3.D for a change to the approved FPP involving control of fire retardant scaffolding materials was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external events (i.e. fire), and it adversely affected the cornerstone objective in that the change to the FPP had the potential to adversely affect the ability to achieve and maintain safe and stable plant conditions due to the increased transient fire load in the affected fire zones. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, review was required as the finding affected fire prevention and administrative controls. The performance deficiency applied to most fire zones within the plant because the licensee stopped tracking the use of the fire retardant scaffolding materials. The team determined that a systematic plant-wide assessment effort was beyond the intended scope of the fire protection SDP. Therefore additional analysis is required to assess the significance of this finding. The cause of this finding was determined to have a cross-cutting aspect of H.1(b) in the Decision- Making component of the Human Performance area because the licensee used nonconservative assumptions in the decision making associated with this FPP change. Additionally, the licensees failure to submit the FPP change to the NRC was a traditional enforcement violation. The severity level of the traditional enforcement violation will be assigned based on the significance determination of the associated finding.
05000269/FIN-2013007-01	2013Q3	Oconee	Modifications to Fire Doors did not Receive Engineering Equivalency Evaluations	An NRC-identified Green non-cited violation (NCV) of Oconee Nuclear Station Units 1, 2, and 3 Renewed Facility Operating License Condition 3.D and NFPA 805 was identified for the licensees modification of five fire doors from their tested configurations without performing engineering equivalency evaluations. The licensee entered this issue into the corrective action program as Problem Investigation Program O-13-06900, and declared the door nonfunctional and implemented fire watches in accordance with Selected License Commitment 16.9.5 Fire Barriers. The licensees modification of fire doors from their tested configuration without performing engineering equivalency evaluations was a performance deficiency. The performance deficiency was more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external events (i.e., fire) and it adversely affected the cornerstone objective in that the modifications performed on the five fire doors adversely affected the capability of the doors to provide the required level of fire resistance. The finding was determined to be of very low safety significance (Green) because the fire doors would have either provided a two-hour or greater fire endurance rating, or would have provided a minimum of 20 minutes fire endurance protection; and the fixed fire ignition sources, and combustible or flammable materials, were positioned such that the degraded fire doors would not have been subjected to direct flame impingement. A cross-cutting aspect was not assigned because the performance deficiency did not reflect current licensee performance.
05000269/FIN-2013007-02	2013Q3	Oconee	Failure to Identify Ignition Sources and Targets During Initial Fire Scenario Development	An NRC-identified Apparent Violation (AV) was identified for the licensees failure to comply with the requirements of 10 CFR 50.48(c) and National Fire Protection Association Standard 805 (NFPA 805). The Oconee fire probabilistic risk assessment (Fire PRA) failed to address the risk contributions associated with all potentially risk significant fire scenarios. This finding does not represent an immediate safety concern because the licensee entered the issue in the corrective action program as Problem Investigation Program (PIP) O-13-08059 and PIP O-13-08061 and implemented fire watches as compensatory measures. Failure to comply with the requirements of 10 CFR 50.48(c) and NFPA 805 to address the risk contributions associated with all potentially risk significant fire scenarios was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone objective of protection against external events (i.e., fire), 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 determined to be potentially greater than Green. Therefore, further analysis is required to assess the significance of the finding. The cause of this finding was determined to have a crosscutting aspect of H.4(c) in the Work Practices component of the Human Performance area because the licensee did not ensure supervisory and management oversight of work activities, including contractors, such that nuclear safety was supported.
05000335/FIN-2013007-03	2013Q1	Saint Lucie	Internal Conduit Seals Outside Appendix R Requirements	On January 27, 2011, the licensee submitted a supplement to their previous LER 2006-005-00 dated February 9, 2007, documenting the identification of degraded penetration seal configurations used for internal steel conduit penetration seals that penetrate fire-rated barriers. The internal conduit seal is a fire seal and also serves as smoke/hot gas barrier. The licensee concluded that these fire barriers, which are required for separation of 27 fire areas (both units) containing systems, components, and equipment required for fire safe shutdown were in a degraded condition. These fire seal inadequacies could affect the fire barriers capability to provide the required 3-hours of fire resistance in the case of a postulated fire. The Region II fire protection inspectors performed a detailed review of the information related to the LER. The inspectors performed in-office reviews of the licensees test documents and analyses, performed onsite walk-downs, and discussed the event with plant personnel to verify the qualification of internal steel conduit penetration seals installed in the plant. The inspectors assessed the licensees compensatory measures and corrective actions to ensure that they adequately restored compliance. The inspectors also evaluated the significance of degraded fire barriers that contained conduit configurations that did not meet the acceptance criteria of the qualification tests. The following finding that affected 10 CFR 50.48 was identified by the licensee and is a violation of NRC requirements. This finding has been screened and determined to warrant enforcement discretion per the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). This LER is closed.
05000335/FIN-2013007-02	2013Q1	Saint Lucie	Licensee-Identified Violation	PSL Unit 1 Renewed OLC 3.G and Unit 2 Renewed OLC 3.L required in part, that B.5.b equipment be pre-staged and readily available to mitigate fuel damage resulting from a large fire and/or explosion. Contrary to the above, the licensee failed to meet the requirements of Renewed OLCs 3.G and 3.L for Units 1 and 2 respectively, in that B.5.b equipment was not readily available to mitigate fuel damage following a large fire or explosion. Specifically, on multiple occasions between February 2009 and February 2013, B.5.b equipment would not have started and/or run for the required time following a large fire or explosion, due to various maintenance related issues. The inspectors determined that the B.5.b equipment would not have been recoverable within the time specified for one spent fuel pool mitigation strategy. The inspectors assessed this finding using the guidance in IMC 0609 Appendix L, B.5.b Significance Determination Process, Table 2, Significance Characterization, dated December 24, 2009. The inspectors determined this finding met the criteria listed in Table 2 for very low safety significance (Green) because it only affected unrecoverable unavailability of an individual mitigation strategy. The licensee entered this issue into the CAP as AR 01844823.
05000338/FIN-2013002-01	2013Q1	North Anna	Failure to Ensure Opposite Units Service Water Pumps Were Free of Fire Damage for a Postulated Fire in Either Units ESWGR	An NRC-identified non-cited violation was identified for the licensees failure to meet the requirements of North Anna Power Station (NAPS) Renewed Operating License Conditions 2.D, and the approved Fire Protection Program for Units 1 and 2. Specifically, the licensee failed to ensure that fire damage to cables associated with the opposite units service water (SW) pumps, located in each units emergency switchgear (ESWGR) room, would not prevent operation of the unaffected units SW pumps as described in Section 4.4.3.5 of the NAPS Appendix R Report. Postulated fire scenarios were identified in which the SW pumps for both units could be compromised due to a single fire in either units ESWGR room. The licensee had previously entered this issue in the NAPS corrective action program as condition report 500152 to evaluate this SW pump control circuit vulnerability and had implemented hourly roving fire watches in each units ESWGR room. Failure to perform an adequate safe shutdown (SSD) analysis as required by the NAPS FPP is a performance deficiency. This finding was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding had the potential to affect the ability to achieve post-fire SSD in the event of a fire in either units ESWGR. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005, review was required as the finding affected fire protection safe shutdown. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F. The inspectors performed Phase 1 and Phase 2 SDP screening assessments using IMC 0609, Appendix F, Attachments 1 and 2, and were not able to screen out this issue in the SDP Phase 1 or Phase 2. A senior reactor analyst from the Region II office performed a Phase 3 SDP analysis to assess the significance of this finding. The analyst determined that this finding was of very low safety significance (i.e., Green) because the risk was mitigated by the availability of at least one SW pump and the fire growth scenarios were mitigated by the gaseous suppression system. The inspectors determined that there was no cross-cutting aspect associated with this finding because it was not reflective of current licensee performance.
05000335/FIN-2013007-01	2013Q1	Saint Lucie	Failure to Demonstrate Feasibility of All Omas Used as Compensatory Measures	An NRC-identified non-cited violation of St. Lucie Unit 1 and Unit 2 operating license conditions 3.E was identified for the licensees failure to comply with the requirements of the St. Lucie Fire Protection Program for verifying the feasibility of unapproved operator manual actions (OMAs). Specifically, the licensees process for determining OMA feasibility did not include performing in-plant walk-downs to verify the feasibility of all the unapproved OMAs that were entered in the corrective action program (CAP) in 2006 and designated as alternate compensatory measures during the transition to National Fire Protection Association (NFPA) Standard 805. The licensee entered this issue in their CAP as Action Request (AR) 01860866 and performed in-plant walk-downs to verify feasibility of the OMAs which had not been previously field verified. Failure to comply with the requirements of the St. Lucie Fire Protection Program for verifying the feasibility of unapproved OMAs designated as compensatory measures is a performance deficiency. This finding was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), and it affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The licensees process for determining OMA feasibility could have resulted in non-feasible OMA compensatory measures not being identified which had the potential to adversely affect SSD in the event of a fire. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), Attachment 4, Initial Characterization of Findings, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, review was required as the finding affected fire protection safe shutdown. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F, Attachment 2, Degradation Rating Guidance, and assigned a low degradation rating to this finding because the licensee verified that the OMAs were feasible through in-plant walk-downs. Therefore, this finding was determined to be of very low safety significance (Green). The cause of this finding was determined to have a cross-cutting aspect in the Corrective Action Program (CAP) component of the Problem Identification and Resolution area in that the licensee did not thoroughly evaluate the problem such that the resolution addressed extent of condition.
05000335/FIN-2013007-04	2013Q1	Saint Lucie	Penetration Seals Outside Appendix R Requirements	On October 17, 2007, during the course of walkdowns being performed to evaluate internal conduit fire seals, the licensee identified three cable spreading room (CSR) floor penetrations which had not been installed or evaluated in accordance with 3-hour fire rating design details. The licensee generated AR 00479446 to track resolution of this issue in its CAP and submitted LER 05000335/2007-003-00. Region II fire protection inspectors performed a detailed review of the information related to this LER. The inspectors performed in-office reviews of licensee documents and analyses, performed onsite walkdowns, and discussed the event with plant personnel to verify the qualification of the fire penetration seals installed in the CSR. The inspectors assessed the licensees compensatory measures and corrective actions to ensure that they adequately restored compliance. The inspectors also evaluated the significance of degraded fire barriers that contained penetration seal configurations that did not meet regulatory requirements. The following finding was identified by the licensee and is a violation of NRC requirements. This finding has been screened and determined to warrant enforcement discretion per the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). This LER is closed.
05000338/FIN-2012012-01	2012Q4	North Anna	Loss of Service Water for a Postulated Fire in Unit 1 ESWGR	The SSD methodology described in the NAPS Appendix R Report for a postulated fire in FA 6-1 credited alternative shutdown capability by using Unit 2 charging pumps (via a manual cross-tie between Unit 1 and Unit 2) and the Unit 2 SW pumps to achieve post-fire SSD for the fire-affected Unit 1 and the unaffected Unit 2. The NAPS SW system is shared between Units 1 and 2 and has a combined total of four SW pumps. The inspectors reviewed cable routing information for the SW pumps, and noted that control cables for all four SW pumps were routed through FA 6-1. During further review of the SW pump circuits and discussions with licensee personnel, it was determined that a postulated fire in the Unit 1 ESWGR could potentially affect the SW pumps control circuits in Unit 2. A fire in the Unit 1 ESWGR could create a hot short in the control circuit cables located in the fire affected Unit 1 ESWGR that could energize the trip coil for the SW pumps of the unaffected Unit 2. The hot short could potentially shut down the running SW pumps and prevent the other SW pumps from starting. This could prevent the unaffected Unit 2 SW pumps from providing SW flow for both the fire affected Unit 1 and the unaffected Unit 2. The inspectors determined that, by not ensuring the credited SW pumps remained free of fire damage, the licensee failed to ensure that alternative shutdown capability would be maintained for a postulated fire scenario in FA 6-1. This condition may not be in compliance with 10 CFR 50, Appendix R, Sections III.G.3 and III.L.1. This issue was discussed with licensee personnel who initiated CR 500152 to assess this service water pumps control circuit vulnerability. The licensee determined that this condition was only possible during a postulated fire in either units ESWGR. Subsequent to the onsite inspection, the licensee documented its Reasonable Assurance of Safety (RAS) for this issue in CR 500152-RAS 219. The licensee indicated in RAS 219 that it was unlikely that one fire would adversely affect the emergency busses on the fire affected Unit 1 as well as the conduit for the unaffected Unit 2 SW pumps such that a loss of all four SW pumps would occur. The licensee implemented hourly roving fire watches in each units ESWGR while this issue was being evaluated. This issue is unresolved pending further NRC review of the licensees information and assessment to determine if a credible fire scenario could result in the loss of all four service water pumps due to a single fire in the Unit 1 ESWGR. This issue is identified as URI 05000338, 339/2012012-01, Loss of Service Water for a Postulated Fire in Unit 1 ESWGR.
05000338/FIN-2012012-02	2012Q4	North Anna	Emergency Lighting Not Installed as Required by 10 CFR 50 Appendix R Section III.J	An NRC identified non-cited violation of 10 CFR 50, Appendix R, Section III.J, and the North Anna Power Station (NAPS) approved Fire Protection Program, was identified for the licensees failure to install fixed emergency lighting units (ELUs) in all areas where local operator manual actions (OMAs) were being performed to support post-fire safe shutdown (SSD). Specifically, a fixed ELU was not installed in the Unit 1 auxiliary building in the vicinity where an OMA to close valve 1-CC-757 was specified by fire contingency action (FCA) procedures for a fire in the main control room (MCR) or the Unit 1 emergency switchgear room (ESWGR). The licensee entered this issue in the corrective action program as condition reports 499353 and 500023. The licensees failure to comply with the requirements of 10 CFR 50, Appendix R, Section III.J, and the NAPS approved FPP, was a performance deficiency. The finding was more than minor because it was associated with the reactor safety Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire), and it negatively affected the objective of ensuring the reliability and capability of systems that respond to initiating events. Specifically, the finding had the potential to affect the feasibility of performing the OMA required for SSD in the event of a fire in either the MCR or ESGR-1. Using IMC 0609, Appendix F, Fire Protection SDP Phase 1 Qualitative Screening Approach, Step 1.3, the inspectors concluded that the finding, given its low degradation rating, was of very low safety significance (Green) because the FCA procedures required the operators performing the SSD actions to carry a portable lantern, and the operators had a high likelihood of completing the tasks using the portable lanterns. The inspectors determined that no cross cutting aspect was applicable to this performance deficiency because this finding was not indicative of current licensee performance.
05000280/FIN-2012011-01	2012Q3	Surry	Licensee-Identified Violation	The following violation of very low safety significance was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation (NCV). 10 CFR Part 50.48(b)(1) requires that all nuclear power plants licensed to operate prior to January 1, 1979, must satisfy the applicable requirements of 10 CFR Part 50, Appendix R, Section III.G. Appendix R, Section III.G.2, requires that where redundant trains of equipment necessary to achieve and maintain hot shutdown are located in the same fire area outside of primary containment, one of three means of protecting cables to ensure that one of the redundant trains is maintained free of fire damage shall be provided. The three acceptable methods described in Appendix R, Section III.G.2 for maintaining one of the redundant trains in the same fire area free of fire damage are based on the use of physical barriers, spatial separation, and fire detection and an automatic fire suppression system. Appendix R, Section III.G.2, does not allow the use of operator manual actions in lieu of protection. Contrary to the above requirements, during walk downs on March 22, 2012, the licensee identified that power and control cables for 1-SW-P-10A and 1-SW-P-10B, redundant trains of charging pump service water pumps, were routed through the turbine building (FA-31) in close proximity to each other and they did not meet the fire protection requirements of 10 CFR Part 50, Appendix R, Section III.G.2. This violation was determined to be of very low safety significance based on the results of the Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance Determination Process, Phase 2 quantitative screening evaluation performed by a regional fire protection engineer and a senior reactor analyst. The significance determination process screening evaluation resulted in a delta core damage frequency (ACDF) of < 1E-6. Therefore, this finding was determined to be of very low safety significance (Green). This issue was identified in the licensees corrective action program as Condition Report CR 467396.
05000395/FIN-2012007-03	2012Q3	Summer	Failure to Maintain One Train of Safe Shutdown Systems in Accordance with Appendix R Section III.G.a/III.G.3	The licensee identified a noncompliance with VCSNS Operating License Condition 2.C(18), Fire Protection System, for the failure to provide alternative shutdown capability for fires in certain areas where protection of SSCs did not satisfy the requirements of the FPP. Specifically, the licensee discovered that they did not meet the FPP requirement to ensure that alternative shutdown equipment remained operable and available. Description: During circuit analysis review in support of the NFPA 805 transition from the 10 CFR 50.48(b) licensing basis, the licensee discovered that a fire in the Control Building 412 North Chase (FA CB-4), Cable Spreading Room (FA CB-15), or Main Control Room (FA CB-17) could cause a hot short that could actuate a relay and result in the isolation of the B-train essential electrical bus (XSW1DB). Additionally, the licensee also discovered that a fire in FA CB-15 or FA CB-17 could cause a hot short that could result in the inability to start the B EDG using local controls. Per the licensees analyses, SSD for fires in these areas would be achieved by alternative shutdown methods. The licensees original circuit analysis and re-analysis considered the possibility of a fire induced open circuit in a current transformer (CT) circuit that connects a set of sensing CTs in XSW1DB to an ammeter in the MCR. However, the licensees circuit analyses failed to consider hot shorts to ground. As a part of the NFPA 805 transition review, this failure mode was considered. The licensee discovered that hot shorts to ground in this circuit could result in spurious actuation of Relay 51BN-1DB. This relay actuates another relay, which trips and locks out all incoming breakers to the 1DB switchgear, and the incoming main breakers for the 480V busses. The lockout relay also prevents the B EDG breaker from closing and powering XSW1DB. This ultimately results in a complete loss of power on XSW1DB. This condition has existed since initial plant startup. Additionally, the licensee discovered that a hot short in an EDG emergency start circuit could result in the unavailability of the B EDG. In 1985, a modification was performed to provide a de-energize to actuate feature in the B EDG start circuit. This feature would allow the diesel generator to start in the case of a fire-induced circuit fault to an EDG control circuit. A subsequent modification performed in 1992 inadvertently defeated the de-energize to actuate feature in the starting circuit, and created the possibility of a fireinduced hot short to this circuit that could result in the failure of the B EDG to automatically start. This hot short could also result in a blown fuse in the EDG start circuit, which would prevent the B EDG from being started locally. This condition has existed since September 1992, when the modification was implemented which inadvertently defeated the de-energize to actuate feature. Both of these scenarios could result in a loss of power on the B ESF bus. For alternative shutdown, the licensees FEPs utilize a self-induced station blackout (SISBO) methodology, where the A ESF bus is disabled, the B ESF bus is credited with being available to provide power to safely shutdown the plant. Therefore, hot shorts described in these scenarios would render the credited power source unavailable to provide power to multiple components credited for alternative SSD. The licensee determined that these conditions were caused by human error during the original circuit analyses, and a less than adequate design change/configuration management process. Upon discovery, the licensee implemented compensatory measures, including posting roving fire watches in FAs of concern, installing temporary jumpers, and revising FEPs. The licensee also committed to restoring compliance by implementing design changes, as a part of the NFPA 805 transition process.
05000395/FIN-2012007-02	2012Q3	Summer	Missing Cold Shutdown Repair Equipment	An NRC identified non-cited violation of License Condition 2.C (18), Fire Protection System, was identified for the licensees failure to provide readily available equipment to support the implementation of cold shutdown fire emergency procedures (FEPs). Specifically, the licensee failed to ensure that cold shutdown equipment will be readily available to implement Cold Shutdown Procedures FEP- 4.1 and EMP-100.002. The licensee documented the deficiencies in Condition Reports 12-01975, 12-01948 and 12-01939. The licensee took immediate corrective action to replace all the missing equipment and performed an extent of condition to verify all other equipment identified in procedure FEP-4.1 was available and included on appropriate inventory lists. The licensees failure to ensure that cold shutdown equipment was readily available to implement cold shutdown Procedures FEP-4.1 and EMP-100.002 as written was a performance deficiency. The performance deficiency was more than minor because it was associated with the configuration control 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 (fire) to prevent undesirable consequences. The finding was evaluated for safety significance using NRC Inspection Manual Chapter 0609, Appendix F. Since the finding was related to the ability to achieve and maintain cold shutdown, the finding had very low safety significance (Green) from the Phase 1 evaluation. This performance deficiency had a cross-cutting aspect in the area of human performance associated with resources because the licensee did not have adequate and available facilities and equipment to ensure nuclear safety. Specifically, personnel did not have required equipment to implement the cold shut down procedures readily available in the designated areas
05000395/FIN-2012007-01	2012Q3	Summer	Duties of the Shift Engineer During OFF-NORMAL Fire Events	An NRC identified non-cited violation of V.C. Summer Technical Specification 6.8.1.e., Procedures and Programs Emergency Plan, was identified related to the emergency plan procedural duties of the Shift Engineer (SE)/Shift Technical Advisor (STA) during off-normal events. Specifically, fire emergency procedures (FEPs) 1.0, 2.0, 3.0, and 4.0 assigned actions that would be performed by the SE during fire events which conflicted with the V.C. Summer Emergency Plan Procedure EP-100 requirement that the SE perform the duties of the STA of assessing and advising the Shift Supervisor during off-normal events. The licensee entered this issue in their corrective action program as Condition Report 12-02035 and implemented fire watch compensatory measures in the fire areas/fire zones where the FEPs assigned actions to be performed by the SE that were outside the main control room. The licensees failure to comply with Technical Specification 6.8.1.e. was a performance deficiency. The finding was more than minor because it negatively impacted the Emergency Response Organization (ERO) Readiness Attribute of the Emergency Preparedness cornerstone objective to ensure 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. This finding was determined to be of very low safety significance (Green) using NRC Inspection Manual Chapter 0609, Appendix B, Emergency Preparedness Significance Determination Process (Section 5.2, Table 5.2.1), because there were no actual instances of entry into the FEPs in which shortages of the emergency plan minimum staffing occurred. The inspectors determined that there was no cross-cutting aspect associated with this finding because the licensees decision to use the SE/STA to perform safe shutdown actions occurred before the 1985 revision of the Fire Protection Evaluation Report (FPER) and was not reflective of current licensee performance.

Semantic search

Query log

Navigation menu