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	Q	Significance	CCA	Identified by	Title	Description
05000249/FIN-2008006-01	2008Q1	Green		NRC identified	Failure to Perform Periodic Trip Tests on Thermal Overload Heaters	The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control. Specifically, the licensee failed to identify and periodically perform the necessary testing on safety-related thermal overload relays/heaters (TOLs), installed in 1993, in the alternate power feed to isolation condenser reactor inlet valves 2-1301-4 (Unit 2) and 3-1301-4 (Unit 3). Periodic testing of the TOLs is required to ensure the valves can perform their Appendix R safe shutdown functions, when required. Upon discovery, the licensee entered the issue into its corrective action program, initiated predefine parameters (PMID) and created surveillance work orders to test the TOLs at the next opportunity. There was not a cross-cutting aspect to this violation. This issue was more than minor in accordance with IMC 0612, Appendix B, Issue Disposition Screening, because the finding was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The finding was of very low safety significance because the finding did not represent an actual loss of functionality of the isolation condenser system containment isolation valves
05000327/FIN-2001007-01	2000Q4	Severity level IV		NRC identified	N/A	10 CFR 50.7 prohibits, in part, discrimination by a Commission licensee or a contractor of a Commission licensee against an employee for engaging in certain protected activities. Discrimination includes discharge or other actions relating to the compensation, terms, conditions, and privileges of employment Contrary to the above, on April 19, 2000, the licensee discriminated against a contract security officer as a result of his engaging in protected activity. Specifically, the officers protected activity involved his objection to being instructed not to follow Physical Security Instruction PHYSI-32, Security Instructions for Members of the Security Force, Revision 24, which was part of his assigned responsibilities. The licensee made statements which resulted in the employees belief that his employment was being threatened if he followed certain procedural steps. Subsequently, the contract security officer deliberately did not implement some personal search requirements when a metal detector alarmed during a senior licensee officials entry into the protected area. The intimidation represented a discriminatory action related to the compensation, terms, conditions, and privileges of the contract security officers employment.
05000327/FIN-2001007-02	2000Q4	Severity level IV		NRC identified	Failure to Search an Individual Prior to Granting Access to the Protected Area in Accordance With Access Control Procedures	Sequoyah Physical Security Plan, paragraph 5.3.1, Personal Searches, establishes personal search requirements for individuals entering the protected area. The licensee implements personal search requirements through Sequoyah Nuclear Plant Physical Security Instruction PHYSI-32, Security Instructions for Members of the Security Force PHYSI-32, Rev. 24, Step 3.3.C, required that individuals entering the protected area shall be subjected to a personal search, including processing through the metal detector. If an alarm is received on the metal detector, the individual who caused the alarm shall be asked to ensure that all metal is removed (including shoes) and to process through the metal detector again. Should the individual alarm the detector again, the member of the security force shall physically search the individual. Contrary to the above, on April 19, 2000, the licensee deliberately failed to follow PHYSI-32 during the personal search of an individual entering the protected area. Specifically, a senior licensee official received an alarm from the metal detector while entering into the protected area, and a security officer did not ask him to ensure that all metal, including his shoes, was removed. The contract security officer physically searched the official instead of requesting that he remove his shoes and process through the metal detector again.
05000327/FIN-2004002-02	2004Q1	Green		NRC identified	Inappropriate Change to the Approved Fire Protection Program	A non-cited Severity Level IV violation of 10 CFR 50.48(a) and the Unit 1 and 2 Operating License Conditions was identified for the licensee making an inappropriate change to the approved fire protection program. This change removed the requirement to implement fire watches for impaired fire protection systems and features. This finding is more than minor because the lack of a posted fire watch could adversely affect the ability to achieve and maintain safe shutdown in the event of a severe fire in the affected area. This was based on recognition that the ability of the fire watch was not limited to fire identification, but also included mitigating actions taken in the event of fires, such as the ability to close doors limiting fire exposure to adjacent areas and providing more timely fire detection capability in certain cases. This finding is of very low safety significance because, based on an assessment of the impacts of the identified fire protection features removed from service, the licensee's overall safe shutdown capabilities and related fire protection features remained adequate to achieve and maintain safe shutdown conditions. Therefore, this finding is characterized as Green.
05000327/FIN-2005011-01	2005Q4			NRC identified	Reliance on 20-foot Separation Zones for Fire Protection in Unit 1 480V Board Room 1B	The team identified an unresolved item (URI) associated with reliance on 20-foot separation zones between redundant SSD equipment in Unit 1 480V Board Room 1B (Fire Area FAA-095). The 20-foot zones did not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2 and also appear not to meet the basis for NRC approval of Deviation #11 related to those requirements. This issue is unresolved pending further NRC review of the licensing basis and the potential for the condition to adversely affect SSD. The licensees SSA for Fire Area FAA-095 relied on three separate 20-foot separation zones between redundant SSD equipment in the room. Fire Area FAA-095 contained three Unit 1 480V motor control centers (MCCs), all three Unit 1 battery chargers (train A, train B, & spare), two of four channels of vital inverters for Unit 1, and two of four channels of vital inverters for Unit 2. The SSA relied on at least two of the three Unit 1 battery chargers and one of the two channels of Unit 1 and Unit 2 inverters in the room not being damaged by a fire in the room. One 20-foot separation zone was located on the north side of the room, separating the train A battery charger (located in the north end of the room) from the spare battery charger (located in the middle of the room). Another 20 foot separation zone was located on the south side of the room separating the train B battery charger (located in the south end of the room) from the spare battery charger. The third 20-foot separation zone was located in the middle of the room, between the vital inverters 1-I and 2-I (located in the north end of the room) and vital inverters 1-II and 2-II (located in the south end of the room). 10 CFR 50, Appendix R, Section III.G.2 stated that redundant SSD cables and equipment could be separated by 20 feet, with no intervening combustibles or fire hazards, and with detection and automatic suppression installed in the area. Deviation #11 applied to the auxiliary building in general. It allowed 20-foot separation zones in this building with intervening combustibles in the form of cable trays provided that: 1) the cables had fuse and breaker coordination to minimize the potential for fires initiating from cable faults and 2) extra sprinklers were installed to compensate for cable trays partially blocking any sprinklers. The team noted that the licensee had not identified in FAA-095 or in engineering documents exactly where the 20-foot separation zones were located. The team estimated the areas of the three 20-foot separation zones in FAA-095 and observed that each one did not meet the requirements of 10 CFR 50, Appendix R, Section III.G.2 and also appeared not to meet the basis for Deviation #11. In addition to intervening cable trays, each of the 20-foot separation zones included intervening ignition sources in the form of 480V MCCs and inverters. Also, two inverters located in the south end of the room, in the 20-foot separation zone between the Train A battery charger and the spare battery charger, did not have sprinklers installed above them. Licensee personnel stated that the lack of sprinklers in the south end of the room had been approved by Deviation #4. Deviation #4 applied to the Appendix R, Section III.G.2 requirement that fire detection and automatic suppression be provided in areas containing redundant SSD equipment that is separated by less than a three-hour fire rated construction. Deviation #4 allowed the licensee to omit sprinklers at the south end of FAA-095 on the basis that inadvertent operation of a sprinkler system would cause unacceptable damage to the inverters and battery chargers. Also, fire loading in FAA- 095 was considered to be low. However, the team observed that the battery charger and inverters at the north end of FAA-095 had sprinklers installed above them and that fire loading in FAA-095 was not low. The team found that, after Deviation #4 had been approved by the NRC, licensee engineers had recalculated the fire loading in FAA-095 and found it to be high. Apparently the original calculation of fire loading had failed to include the cable insulation inside of the 480V MCCs, inverters, and battery chargers. Licensee engineers determined the increased fire loading did not adversely affect SSD and and thus was acceptable without further review by the NRC. The team concluded that the licensee had inappropriately applied two separate NRC approved Deviations to the south end of FAA-095. More importantly, the team was concerned that the three 480V MCCs that intervened in the three 20-foot separation zones represented significant fire hazards. They occupied most of the length of FAA-095, from the north end to the south end of the room. They included a total of 42 vertical sections, with each vertical section being a potential ignition source. Each vertical section had stacks of open cable trays directly above it, so that a fire that initiated in a vertical section could readily spread up to seven or more cable trays. NUREG-1805 fire models demonstrated that such a fire could cause a hot gas layer throughout the room which could damage the cables (all had non-qualified thermoplastic insulation) and the SSD equipment located in FAA-095, should the automatic sprinkler system fail. The team noted that the sprinkler system for FAA-095 had a higher likelihood of failure because it was a cross-zone preaction-type of system. The sprinkler piping in FAA-095 was normally dry. To put fire water into the piping, at least two smoke detectors from different zones in the room would have to activate and automatically open a valve. If the cross-zone detector circuit failed or the valve failed to automatically open, all of the sprinklers in FAA-095 would fail to deliver water. Sequoyah\'s license condition for fire protection allowed changes to the fire protection program provided that the changes did not adversely affect SSD. The licensee\'s evaluation determined that the existing 20-foot separation zones were acceptable. Licensee personnel concluded that the existing 20-foot separation zones did not adversely affect SSD and were acceptable with no further review by the NRC, because there were sprinklers above the cable trays and MCCs. This issue is considered an unresolved item pending further NRC review of the licensing basis and the potential for the condition to adversely affect SSD. This issue is identified as URI 05000327,328/2005011-01, Reliance on 20-foot separation zones for Fire Protection in Unit 1 480V Board Room 1B.
05000327/FIN-2005011-02	2005Q4			NRC identified	Unprotected Power Cables to Vital Inverters in Unit 1 480V Board Room 1B	The team identified an URI associated with unprotected alternating current (AC) power cables to Unit 1 vital inverter 1-II and Unit 2 vital inverter 2-II. The cables were routed through the north end of the Unit 1 480V Board Room 1B (Fire Area FAA- 095) without protection or separation from fire damage (as required by Appendix R, Section III.G.2). The licensees SSA for SSD of Unit 1 and Unit 2 relied on the cables not being damaged by a severe fire in that area. To compensate for the unprotected cables, licensee personnel added a local manual operator action to the fire response procedures. This issue is unresolved pending further NRC review of the licensing basis. The licensees SSA for FAA-095 divided the fire area into three fire zones identified by column lines A3-A4, A4-A6, and A6-A8. Based on these fire zone descriptions the licensee analyzed what electrical equipment would be impacted by a fire in the affected zone. The licensees electric circuit analysis for a fire occurring between column lines A3 and A4 in FAA-095 (the north end of the room) concluded that vital inverters 1-II and 2-II, which were located in the south end of the room, would be available to support SSD. The analysis concluded that only vital inverters 1-I and 2-I, which were located in the north end of the room, would be lost for a fire in this zone. However, the 480V AC power cables to vital inverters 1-II and 2-II were routed through the north end of the Unit 1 480V Board Room 1B without protection or separation from fire damage (as required by Appendix R, Section III.G.2). The cables were approximately 11 feet from the 120V AC vital inverter 1-I and there were intervening 480V MCCs and cable trays in that 11 feet. Consequently, a fire in the north end of fire area FAA-095, between column lines A3 and A4, could result in loss of the 480V AC normal power supply cables to the 120V AC vital inverters 1-II and 2-II. Loss of the 480V AC power supply cable from fire damage would cause the vital inverters 1-II and 2-II to use their direct current (DC) power supply. Because the load of the inverters on the DC power supply would exceed the capacity of the battery charger, it could result in the complete discharge of the 125V DC battery and cause the inverters and other loads on the DC bus to be lost. The licensees analysis of record indicated that the battery charger and battery could maintain power to the 125V DC Vital Battery Board II and 120V AC Vital Instrument Power Board 1-II and 2-II loads for least four hours without the 480V AC power to the inverters. The licensee entered this issue into their corrective action program in Problem Evaluation Report (PER) 91841. In addition, the licensee took prompt corrective action to revise the fire procedure to add local manual operator actions to energize the spare Inverter 0-II, transfer the 120V AC Vital Instrument Power Board 1-II to its alternate supply, and de-energize inverter 1-II, all within four hours. The licensee stated that walkdown data showed that the actual loading on the battery/charger combination would be low enough such that the loads could be maintained for more than 8 hours. The team reviewed Design Change Notice (DCN) D-20071, Rev. a, which installed new vital inverters 1-II and 2-II and associated AC power cables (1PL4915B and 2PL4910A) in 2001. The DCN involved the installation of eight new inverters on the Unit 1 and Unit 2 vital power systems. The DCN was approved for implementation on September 2, 1999, and the plant modifications were completed in 2001. The new inverters were physically located in the same rooms as the old inverters. The Nuclear Safety Assessment for Fire Protection in the DCN stated that the new and existing cables routed (or rerouted) for this modification have been evaluated and found to be acceptable in accordance with the SQN Fire Hazards Analysis, see Mini-Calculation SQN-26-D054EPMABBIMPFHA6. It also stated the following: A fire in some areas along the route requires manual actions as a result of new 480V feeders to the replacement 120V AC vital inverters. In each case, the spare inverter is to be energized, the 120V AC vital distribution panel is to be transferred to its alternate supply (spare inverter) and the Unit 1 inverter deenergized. The actions are to be completed within 4 hours. Based on the above, the team concluded that the original design change had concluded that failure of the cable between columns A3 and A4 in FAA-095 was likely due to fire damage and that local manual operator actions would be necessary to mitigate the cable failure. However, after the modifications were completed, the required operator actions had not been added to the post-fire SSD procedure. The team also had a concern that the design change was not consistent with the licensing basis for the plant (i.e.,10 CFR 50, Appendix R , Section III.G.2) in that local manual operator actions were being used in lieu of separation or protection of the cables. The use of manual actions in lieu of separation or protection may require NRC approval prior to implementation if it affects SSD. The design change analysis referenced NRC approved Deviation #11 to Section III.G.2.b of Appendix R to support acceptability of the DCN. Deviation #11 allowed intervening combustibles in the form of open ladder type cable trays, with sprinklers, to be installed between redundant cables which were separated by more than 20 feet. However, Deviation #11 did not allow redundant cables to be separated by only 11 feet, with intervening 480V MCCs and cable trays. This issue is considered an unresolved item pending further NRC review of the licensing basis and is identified as URI 05000327,328/2005011-02, Unprotected Power Cables to Vital Inverters in Unit 1 480V Board Room 1B.
05000327/FIN-2005011-03	2005Q4			NRC identified	Sprinklers Apparently Too Far Below Ceiling in Cable Spreading Room	The team identified an URI related to the design of the sprinkler system in the cable spreading room, in that, the sprinklers were apparently installed too far below the ceiling. This issue is unresolved pending further NRC review of the licensing basis and the suppression capability of the installed sprinkler system. The team observed that all of the installed sprinklers in the cable spreading room were 30 inches or more below the ceiling. However, the NFPA code requires that sprinklers be installed within 18 inches of the ceiling. Positioning the sprinklers farther below the ceiling results in a delayed sprinkler response and allows a fire to grow larger in size. The Sequoyah FPP stated that sprinkler systems comply with the NFPA Code for installation of sprinkler systems. The SQN Fire Protection Report, Part VII - Deviations and Evaluations, paragraph 5.1.1, stated that sprinkler systems comply with NFPA 13- 1975, with certain exceptions. The list of exceptions did not include any sprinklers being installed farther below the ceiling than allowed by the NFPA code. NFPA 13-1975, Section 4-3.1, requires that for smooth ceiling construction, deflectors of sprinklers in bays shall be located 1 inch to 12 inches below noncombustible ceilings. For panel construction, the code allows sprinklers to be as much as 18 inches below the ceiling; however, in no case does the code allow sprinklers to be 30 inches below the ceiling. In a Safety Evaluation Report (SER), (NUREG-011, Supplement 1), the NRC approved the licensees sprinkler system design for the cable spreading room, including the use of an upper level near the ceiling and an intermediate level approximately halfway between the floor and the ceiling. However, the NRC SER did not specifically recognize that the upper level of sprinklers was more than 18 inches below the ceiling. The team concluded that the SER did not appear to approve a deviation from the NFPA code. In Generic Letter (GL) 86-10, the NRC stated a staff position that licensees may deviate from NFPA code requirements with an evaluation approved by a fire protection engineer. GL 86-10 stated that such deviations from the NFPA code should be identified in the FSAR or FHA. However, GL 86-10 also stated an NRC staff position that sprinkler heads should be located at the ceiling. The team observed that the cable spreading room contained cables for both units and was very large in volume (approximately 219 feet long by 42 feet wide and 25 feet high). Rows of intermediate sprinklers were located between rows of upper sprinklers such that most fires that could start near the floor would generate a wide heat plume that would impact at least one upper or intermediate level sprinkler. The sprinklers had metal heat collectors installed above them; however, NRC Information Notice 2002-024 describes potential problems with such heat collectors. Also, sprinklers that were not directly in the heat plume of a fire could potentially have a significantly delayed response to the fire. This issue remains open for further NRC review of the licensing basis and the suppression capability of the installed sprinkler system. The issue is identified as URI 05000327,328/2005011-03, Sprinklers Apparently Too Far Below Ceiling in Cable Spreading Room.
05000327/FIN-2005011-04	2005Q4			NRC identified	Appendix R Operator Action to Throttle AFW in Main Steam Valve Vault Room	The team identified an URI related to a potentially non-feasible local manual operator action that was relied upon for SSD during a large fire in each of the three fire areas that were the focus of this inspection. The local manual action was to throttle AFW in the main steam valve vault room with or without lights. This issue is unresolved pending further NRC review of the licensing basis. During plant walkdowns of local manual operator actions that would be needed to mitigate a severe fire in FAC-17, FAA-070, or FAA-095, the team identified a potentially non-feasible local manual operator action. The local manual action was for an auxiliary unit operator (AUO) to throttle AFW flow to two steam generators in the Unit 1 main steam valve vault room and another AUO to perform a similar action in the Unit 2 main steam valve vault room. The action was required by AOP-N.08, Appendix G and AOP-C.04, Appendix J. During the walkdowns, the team observed that the Unit 2 main steam valve vault room was completely dark. All of the normal lights were extinguised and the installed Appendix R emergency lights were off. Licensee investigation determined there was no lighting because all of the normal light bulbs were burned out. The emergency lights were designed to come on only when electrical power to the normal lights was lost. Because electrical power had not been lost, no lighting was illuminated in the room. The lack of normal lighting had not been recognized because plant safety rules did not allow operators to go into the main steam valve vault rooms alone due to heat stress concerns, and there was no plant requirements to routinely enter the rooms during plant operation to check on the conditions in the rooms. As a result of the licensee not maintaining the normal lighting, had a severe (Appendix R) fire occurred in FAA-070, FAA-095, FAC-017, or any of many other fire areas, an AUO may have had to locally control AFW flow in the Unit 2 main steam valve vault room in the dark. The team walked down the operator action in the dark Unit 2 main steam valve vault room with an operator (using flashlights), and judged that the action was not feasible. The action was found to be too difficult and had a high likelihood of failure. Difficulty factors included: complete darkness except for a flashlight, heat stress, climbing ladders in the dark while holding a flashlight and avoiding hot pipes and head-knocking steel supports, loud noise from steam generator relief valves that would be lifting nearby, no local indications for throttling the valves, poor communications (the AUO would need to climb down a ladder and exit the valve room repeatedly to talk on the radio to the main or auxiliary control room), throttling with a gate valve (which would provide very uneven flow control), the action was time critical (to be performed within 30 minutes), and one AUO would have to perform the action alone. Licensee personnel stated that one AUO could be assigned to perform this action because plant safety rules related to heat stress did not apply during emergencies such as Appendix R fires. The team noted that if both units were affected by an Appendix R fire, then all available on-shift AUOs would be needed to perform SSD actions. There would be no extra AUOs available to send more than one to a main steam valve vault room. After the walkdowns, licensee personnel documented that they considered the action to be feasible for one AUO to perform even without lighting. The licensee promptly replaced the normal light bulbs in the Unit 2 main steam valve vault room and the team verified that the lights were on. The team noted that the licensee had installed backup air supply bottles (located outside the main steam valve vault rooms) that could enable the control room to operate the AFW air-operated flow control valves if the normal instrument air was lost; however, that backup air supply was not used in the Appendix R SSD procedures. In lieu of protecting cables to the AFW flow control valves from fire damage, the licensee was relying on the local manual actions in the main steam valve vault rooms. The team reviewed standards related to maintaining normal lighting for Appendix R SSD actions. Where the approved fire protection program allows certain local manual operator actions, those actions are expected to be capable of being reliably performed under the anticipated circumstances. Where licensees are relying on unapproved local manual actions, the actions can be considered adequate temporary compensatory measures if they are feasible. Feasibility and capability of being reliably performed involve adequate lighting. 10 CFR 50, Appendix R requires that operators be able to safely shut down the plant with or without offsite power (i.e., with or without normal lighting). Appendix R, Section III.J, Emergency Lighting, requires that emergency lighting be provided in all areas needed for operation of SSD equipment and for access and egress thereto. The statements of consideration (SOC) for Appendix R, Section III.J indicate that the basis for the emergency lighting assumed that normal lighting would also be available. The SOC stated: ...operators involved in safe plant shutdown should not also have to be concerned with lighting in the area, and it is prudent to provide 8-hour emergency lighting capability to allow sufficient time for normal lighting to be restored with a margin for unanticipated events. The acceptability of the local manual operator action to throttle AFW flow in the main steam valve vault room, with or without lighting, is unresolved pending further NRC review of the licensing basis for the action. This issue is identified as URI 05000327,328/2005011-04, Appendix R Operator Action to Throttle AFW in Main Steam Valve Vault Room.
05000327/FIN-2005011-05	2005Q4			NRC identified	Reliance on Local Manual Operator Actions for Appendix R Fires	The team identified an URI related to licensee reliance on many local manual operator actions for mitigation of Appendix R, Section III.G.2 fires, where operators would be shuting down the plant from the main control room. This issue is unresolved pending further NRC review of the licensing basis. The team noted that the licensees procedure AOP-N.08, Appendix R Fire SSD, relied on many local manual operator actions to mitigate a fire in FAA-070 or FAA- 095 in lieu of protecting or separating cables per Appendix R, Section III.G.2. The licensee had no approved NRC deviations from the requirements of Appendix R, Section III.G.2 for these manual actions. However, licensee personnel believed that some of the actions had been specifically reviewed and accepted by the NRC, as documented in Inspection Report 05000327,328/88-24, which was referenced by NRC SER (NUREG-1232). The licensee also stated that the NRC had approved a general reliance on local manual operator actions instead of protecting or separating cables per Appendix R, Section III.G.2. The licensee had reviewed and walked down each action, and considered each action to be feasible. With the exception of the action to locally control motor driven AFW pump flow (described above), the team found these actions to be feasible. This issued is unresolved pending further NRC review of the licensing basis. This issue is identified as URI 05000327,328/2005011-05, Reliance on Local Manual Operator Actions for Appendix R Fires.
05000327/FIN-2005011-06	2005Q4			NRC identified	Potential for Fire Damage to Spuriously Open a Containment Sump Isolation Valve	The team identified an URI associated with potential fire-induced electrical circuit failures in the containment sump flow isolation valve 1-FCV-63-73 control circuit. Postulated fires in FAA-095 and FAA-070 could result in electrical circuit faults in the control cables and control logic of the isolation valve. These fire-induced faults could cause the valve to spuriously open and drain the refueling water storage tank (RWST) to the containment sump. This issue is unresolved pending further NRC review of the licensing basis. The team reviewed cable routing information for both containment sump flow isolation valves 1-FCV-63-72 and -73, and determined that containment sump isolation valve 1-FCV-63-73 had two control cables that were routed in fire areas FAA- 070 and FAA-095. These multiconductor control cables were identified as 1V3141B and 1V3142B, and were 9 and 12 conductor cables with thermoplastic jackets, respectively. In reviewing the electrical schematics, block diagrams, and the Appendix R Hot Short Analysis, the inspectors concluded that two intra-cable hot shorts in either cable could cause the valve to spuriously open and drain the RWST to the containment sump. For example, concurrent hot shorts between conductors 13A5 and 13A6 and between 13A3 and 13A08 in cable 1V3141B could spuriously open the valve. Spurious opening of the valve would drain the RWST to the containment sump and adversely affect SSD by removing the suction source for the charging pumps. The licensees hot short analysis assumed that only one hot short was credible. The licensee had previously modified the design of the control circuit to prevent spurious operation with only one hot short. The licensee stated that its licensing basis required a design assuming only one hot short. However, the team could not confirm this statement. The team noted that NRC Regulatory Information Summary (RIS) 2004-03, Rev. 1, states in part that: For any individual multiconductor cable (thermoset or thermoplastic), failure that may result from intra-cable shorting, of any possible combination of conductors within the cable may be postulated to occur concurrently regardless of number. This issue is unresolved pending further NRC review of the licensing basis related to intra-cable hot shorts. The issue is identified as URI 05000327,328/2005011-06, Potential for Fire Damage to Spuriously Open a Containment Sump Isolation Valve.
05000327/FIN-2005011-07	2005Q4			NRC identified	Potential for Fire Damage to Spuriously Close the Charging Header Flow Control Valve	The team identified an URI associated with potential fire-induced electrical circuit failures in the charging header flow control valve control circuit. A postulated fire in fire area FAA-070 could result in fire-induced electrical circuit faults in the control cables and control logic of the charging flow control valve causing the valve to close and shut off cooling flow to the reactor coolant pump (RCP) seals. This issue is unresolved pending further NRC review of whether the licensee is required to design against such a failure mode. The team reviewed cable routing information for charging header flow control valve 1-FCV-62-093 and determined that two cables in the control logic for the valve were routed in fire area FAA-070 without appropriate separation or protection. These cables were identified as 1PM108 and 1PM110. Both cables provided a 10-50 milliamp signal for control of the charging pump discharge air operated valve (AOV). A cable-to-cable hot short of 50 milliamps in either cable could spuriously close the AOV and stop all RCP seal injection flow. The team determined that both cables were routed in trays with other signal cables of 10-50 milliamps so that a cable-to-cable hot short of this type could potentially occur. However, because the cables were shielded twisted pairs with drain wires, it is not likely a failure of this type could occur without the cables shorting to each other or to ground. This item is unresolved pending further NRC review to determine whether the licensee is required to design against such a failure mode. This issue is identified as URI 05000327,328/2005011-07, Potential for Fire Damage to Spuriously Close the Charging Header Flow Control Valve.
05000327/FIN-2006005-02	2006Q4			NRC identified	Inability to Perform Required Actions of AOP-N.08, Appendix R Fire Safe Shutdown (Section 1R15)	On October 28, 2005, a procedure change to AOP-N.08, Appendix R Fire Safe Shutdown, was implemented. This change incorporated updated guidance provided by a Westinghouse technical bulletin (TB -04-022) concerning RCP seal performance during Appendix R fires and a loss of all pump seal cooling. This change reduced the time available to perform manual actions and restore RCP seal flow from 24 minutes to 13 minutes. In the event of an Appendix R fire resulting in a spurious safety injection signal, plant procedures required that all RCS injection sources be stopped to prevent filling the pressurizer solid. The vendor guidance stated that actions taken to prevent this condition and restore RCP seal flow should be completed within 13 minutes to prevent seal damage. The actions outlined by AOP-N.08 required an auxiliary unit operator (AUO) to manipulate several valves in the appropriate Charging Pump room and then a CCP restarted to restore seal flow. Specifically, the AUO was to open a dedicated flow path to the RCP seals using manual valve 62-526 (A-train), or 62-534 (Btrain) and close the associated CCP manual discharge valve, 62-527 (A-train) or 62-533 (B-train) to the CCP Injection Tank (CCPIT). To support the procedure change, these manipulations were subjected to a manual action validation that consisted of a table top review of the necessary steps. The licensee determined that the CCP manual discharge valves to the CCPIT could be closed by an individual AUO in 5 minutes and 20 seconds. Prior to the procedure being approved, PER 91383 was written on October 24, 2005. The PER addressed concerns by at least one plant AUO that the manual actions required by the change to procedure AOP-N.08 may not be able to be completed within the time required. PER 91383 requested the need to further evaluate the time necessary to perform the manual actions by actual valve manipulations, or whether additional procedure changes were needed to provide more margin to the required time. The corrective action planned was to perform a timed valve stroke of CCP discharge valve 2-62-527 to validate procedural change assumptions. Work Order (WO) 06- 771729-000 was written to implement and track this action during an appropriate CCP maintenance period. PER 91383 was closed as completed on February 24, 2006 based on the WO being written. On November 9, 2006, during a self-assessment, the licensee determined that the WO had not been completed and was not scheduled for performance until January 22, 2007. PER 114455 was written to document the incomplete corrective action. Upon review of PER 114455, the inspectors questioned the licensee on the valves history, the status of corrective actions, and whether a valid safety concern existed if the valve could not be operated within the prescribed time. Prior to resolution by the licensee, on November 27, 2006, during Unit 2 refueling outage activities, operators closed valve 2-62-527 to support maintenance. The operators reported that the valve was very difficult to operate and required approximately 30 minutes for two AUOs to shut the valve. This observation was documented in in PER 115490 and supported the initial concern expressed in PER 91383. This information prompted the license to evaluate the consequences of the additional time needed to operate valve 2-62-527 with plant Appendix R
05000327/FIN-2007005-02	2007Q4			NRC identified	Improper Information Provided for MSPI	The inspectors reviewed the importance weighting ratios for both the unavailability and unreliability portions of the five different MSPI indicators as delineated in the MSPI basis document. The inspectors noted that, for Emergency AC Power, a separate ratio was specified for each EDG on each unit so that when calculating MSPI for Unit 1 there was one ratio for EDG 1A, one ratio for EDG 1B, one ratio for EDG 2A, and one ratio for EDG 2B. The importance of the Unit 1 EDGs was higher for the Unit 1 indicator than the Unit 2 EDGs with each Unit 2 EDG having an identical importance for Unit 1. The opposite was true for Unit 2. The Unit 2 EDGs were more important. However, when reviewing the derivation reports for the Emergency AC Power indicator, the inspectors noted that the same importance ratios were used on each EDG for each unit so that each EDG was equally important to each unit. The inspectors determined that the basis document was correct but the importance ratios had been improperly entered into the CDE database that calculated the Emergency AC Power MSPI. In addition, while reviewing the indicator as part of addressing inspector questions, engineering personnel determined that three previous failures not had not been classified properly. The licensee had originally classified a failure of EDG 2A on October 3, 2005, which involved a broken sight glass on one of the generator bearings, as a demand failure based on the inability of the EDG to complete its function. After reviewing it further the licensee realized that the EDG would have started but would not have been able to complete its mission because the bearing would have failed due to loss of oil. Therefore they reclassified the failure of October 3, 2005, as a failure to run. The licensee also determined that two previous failures on July 20, 2006 and August 7, 2007, were not actually failures because the affected equipment was outside the boundary of the system. The as-reported numbers for the Emergency AC Power MSPI for the quarter ending September 2007 were -5.3E-7 for Unit 1 and -5.3E-7 for Unit 2. The effect of the improper use of the importance measures was to change the unreliability portion of the indicator from a negative to positive number while the total indicator remained negative. After adjusting for importance measures the numbers would have been -2.0E-7 for Unit 1 and -7.0E-8 for Unit 2. With the additional classification changes to the failure data the numbers became -1.12E-6 for Unit 1 and -1.17E-6 for Unit 2. While these numbers remained in the green band, the changes also affected earlier time periods. In two previous quarters, June 2006 and March 2007, the Unit 2 indicator was 1.04E-6. Because this information involved licensee failure to provide complete and accurate information concerning a ROP performance indicator, the inspectors determined that it had the potential to impact NRC ability to perform its regulatory function. Enforcement: 10 CFR 50.9 requires that information provided to the NRC be complete and accurate in all material respects. Contrary to this, from July 1, 2006 until December 31, 2007, the licensee provided information regarding the Emergency AC Power MSPI indicator that was inaccurate. Specifically, the importance ratios for both the unavailability and unreliability portions of the indicator were improperly entered into the calculation for determining the indicator resulting in inaccurate reporting of the MSPI for Emergency AC Power. However, this item will remain unresolved pending NRC review of the previous data for the indicator and is identified as URI 05000327,328/2007005-02, Improper Information Provided for MSPI. This item has been entered into the licensees corrective action program as PER 135288.
05000327/FIN-2007006-01	2007Q3			NRC identified	Failure to Use Appropriate Assumptions in Design Calculations	The team identified a violation of 10 CFR 50, Appendix B, Criterion III, Design Control, associated with TVAs failure to use appropriate assumptions in design calculations at the Sequoyah Nuclear Plant. TVAs failure to use appropriate assumptions in design calculations resulted in a significant increase in the calculated maximum room temperatures for the Emergency Core Cooling System pump rooms as well as the TDAFW pump room. This increase in the calculated maximum room temperatures led to a reasonable doubt about the operability of components in the affected rooms. Description. Design Criteria Document SQN-DC-V-13.9.3, Auxiliary Building Ventilation and Cooling, Table T1.34 established the design temperatures for the TDAFW pump room for normal and abnormal conditions. This document established a maximum room temperature of 110 F for an abnormal operational event. TVA calculation SQN-31CD053- EPM-RG-060987, Revision 2 was developed, in part, to determine if the capacity of the installed direct current (DC) fan equipment for the TDAFW pump was adequate to maintain the maximum design temperature of 110 F specified in the design criteria document. The calculation determined the air temperature needed to maintain the abnormal design temperature based on the heat input load calculated in SQN-31CD053- EPM-DLM01-030887, HVAC Cooling Load Calculation: Aux. Bldg. TDAFW pump, Revision 2 and determined an inlet air temperature of 80 F. Based on a preliminary calculation, the installed fan would maintain the TDAFW pump room at 131 F instead of 110 F. This issue was entered into the CAP as PER 126928. A review of the environmental qualification (EQ) list of equipment inside that room indicated that the equipment is qualified to at an ambient temperature of 215 F which is higher than the 110F specified in the design criteria document. Another design calculation with inappropriate assumptions was Engineered Safety Features (EFS) room cooler calculation, 30-DO53-EPM-BVC-052788, Emergency Raw Cooling Water (ERCW) River Water Temperatures Effect on ESF Coolers, Rev. 7. The incorrect assumption was the use of input cooler air flow rates that were higher than the minimum design flow rate. In this case, the non conservative nominal value of 4933 cubic feet per minute (CFM) was used as opposed to the minimum design airflow rate of 4439 CFM in order to calculate maximum accident room temperature. Deficient assumptions included using an ERCW supply temperature and flow rate that were not worst case for the calculations. As a result of the use of non conservative input values in the ESF maximum room temperature calculations, the installed room coolers were not capable of maintaining the analyzed temperatures for the ESF rooms. The licensee performed a preliminary calculation which showed a significant reduction in margin between the calculated maximum room temperatures and design limits. In the case of the 1B-B Centrifugal Charging Pump (CCP) room, the design temperature limit was exceeded by .6 degrees. The team determined the 1B-B CCP to be operable because of additional margin available with respect to environmental qualification. Analysis. The TVA\'s failure to use appropriate assumptions for ESF and TDAFW pump maximum room temperature calculations is a performance deficiency associated with the Mitigating Systems cornerstone. This finding is more than minor because if left uncorrected problems in Design Control could lead to a more serious safety concern as many other safety-related design calculations rely upon these design outputs. This finding was reviewed for cross-cutting aspects and none were identified.
05000327/FIN-2007006-02	2007Q3			NRC identified	No Procedure for Inspection/Replacement of DG Local Electrical Panel Filters	The team identified a violation of Technical Specification 6.8.1 associated with TVA\'s failure to develop a procedure that will provide periodic inspection and replacement of the EDG room electrical panel ventilation air filters at the Sequoyah Nuclear Plant. This resulted in a fourteen year period between 1993 and present, for which the filters were not inspected and replaced for all four diesel generator rooms. Description. The diesel generator room ventilation system consists of one air supply fan, one air duct that splits to provide ventilation air to the generator and the electrical panels, and one air filter located in the ductwork before the electrical panels. The purpose of the filter is to provide a clean supply of air in order to prevent debris accumulation in the panel, which could affect various electrical components. In the event the filter becomes clogged, due to long-term use, internal temperature limits for various electrical components associated with generator excitation controls could be impacted. This would affect the long-term reliability of the EDG to provide adequate voltage and power to its associated bus during its mission time. Analysis. TVA\'s failure to develop a procedure that will provide periodic inspection and replacement of the EDG room electrical panel ventilation air filter is a performance deficiency associated with the Mitigating Systems cornerstone. The finding is greater than minor because it is associated with the Mitigating Systems cornerstone attribute of procedure quality and affects the cornerstones objective of ensuring the availability, reliability, and operability of the emergency diesel generators to perform their safety function during an initiating event, such as, a loss of offsite power. This finding was reviewed for cross-cutting aspects and none were identified.
05000327/FIN-2007006-03	2007Q3			NRC identified	Inadequate Procedure for Reduced INVENTORY/MID-LOOP Operation	The team identified a violation of TS 6.8.1, related to the failure to establish an adequate procedure for reactor coolant system reduced inventory/mid-loop operations. Specifically, procedure 0-GO-13, Reactor Coolant System Drain and Fill Operations, Rev. 57, was not adequate in that it did not establish adequate actions to maintain continuous RCS level indication during all possible plant conditions while in the reduced inventory/mid-loop configuration, specifically loss of off site power (LOSP). Additionally, the procedure did not establish contingency actions to recover power to the Mansell level indication systems or provide guidance for alignment of an alternate RCS level indication mechanism within the 30 minutes for which power was available from Description: Procedure 0-GO-13, Reactor Coolant System Drain and Fill Operations, Rev. 57, implements the licensees commitment to GL 88-17, Loss of Decay Heat Removal (non power operations) and related FSAR section 5.6 requirements state that at least two independent continuous RCS level monitoring indications will be maintained during mid-loop operations. Per this procedure, two channels of the Mansell System provide the two continuous independent level monitoring systems required for reduced inventory/mid-loop operations. The instruments are powered from 120 VAC wall receptacles in the main control room which are powered by the auxiliary building lighting boards (LC-132 and LC-232, powered from Units 1 and 2 respectively). On a loss of off-site power the lighting boards would be de-energized and are not re-energized when the EDGs restore on-site vital power. Each Mansell unit has an uninterruptible power supply (UPS) battery to maintain the system for approximately 30 minutes. This was verified by on-site testing performed during the inspection. No procedure contingency plan exists for maintaining/restoring Mansell indication once the UPS is depleted. Analysis: The failure to establish an adequate procedure for reactor coolant system reduced inventory/mid-loop operations is a performance deficiency associated with the initiating events cornerstone. This finding is more than minor because it impacts the Cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown and is associated with the cornerstone attribute of procedure quality. This finding was reviewed for cross-cutting aspects and none were identified
05000327/FIN-2007006-04	2007Q3			NRC identified	Inadequate Abnormal Operating Procedure for RHR System Malfuctions During Mode 4 Conditions	The team identified a violation of TS 6.8.1, related to the failure to establish an adequate abnormal operating procedure for RHR system malfunctions during shutdown conditions. Procedure AOP-R.03, RHR System Malfunction, Rev. 17, was not adequate in that it did not establish adequate actions to restore RHR cooling following isolation of an RHR leak during hot shutdown (Mode 4) operations. The instruction provided in the procedure could result in a total loss of RHR cooling capability during mode 4 conditions if an RHR leak occurred. Description: Procedure AOP-R.03, RHR System Malfunction, Rev. 17, provided instruction for protection of the reactor core during shutdown (non power) conditions (Modes 4,5 and 6) in the event of a loss of RHR cooling, RHR system leak, or a loss of RHR level. Section 2.4 provides instruction for mitigation of an RHR system leak. Step 2 of section 2.4 stated: if the magnitude of a leak requires rapid isolation, secure RHR pumps and close hot leg and individual RHR pump suction valves (valves 74-1, 74-2, 74-3, and 74-21). (Note: magnitude of leak was not defined) Steps 3 through 9 involved identifying and isolating the RHR leak. Step 10 directed the operator to place the unaffected RHR loop in service using procedure 0-SO-74-1, System Operating Procedure for RHR System. Entry points into this procedure would be at section 5.5.2, Placing RHR in Service for Normal Shutdown Cooling or section 8.2, Swapping RHR Pumps with RCS in Mid-Loop Conditions. Section 5.5.2, directed the loop suction valves (74-1 and 74-2) to be opened; however, there was no direction to open or verify open the individual pump suction valves (74-3 and 74-21) before the direction to start the pumps nor did section 8.2. The team concluded the pumps could be started without a suction flow path, resulting in pump damage in a relatively short period (minutes), while running on mini flow with the pump suction valves closed due to a lack of NPSHA. Analysis: The failure to establish an adequate abnormal operating procedure for RHR system malfunctions during shutdown conditions is a performance deficiency associated with the Initiating Events Cornerstone. This finding is more than minor because it impacts the Cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown in that the loss of RHR pumps would increase the likelihood of a loss of RHR cooling. This finding was reviewed for cross-cutting aspects and none were identified
05000327/FIN-2008002-01	2008Q1	Green	H.7	Self-revealing	Inadequate Tagging Procedure (Section 1R05)	A self-revealing NCV was identified for an inadequate tagging procedure that resulted in a failure to properly isolate a fire hydrant before maintenance. Because of the failure, the hydrant was forced off the associated fire protection system header, depressurized the system, and rendered it inoperable. The licensee entered the problem into their corrective action program and initiated actions to prevent recurrence. This finding was more than minor because it affected the mitigating system cornerstone objective of availability of systems, i.e. Fire Protection System, and was associated with the protection against fire, an external hazards attribute. While the finding caused the fire protection system to be inoperable, the inspectors determined that the degradation rating used for the significance determination process was low. Therefore, the finding was considered to be of very low safety significance. The cause of the finding was associated with the accurate and up-to-date procedures and work packages aspect of the human performance cross-cutting area. The clearance procedure and Work Order (WO) were not sufficient to ensure continued fire protection system operability during hydrant maintenance
05000327/FIN-2008002-02	2008Q1	Green	H.12	Self-revealing	Failure to Follow Calibration Procedure (Section 1R22)	A self-revealing NCV was identified for failure to properly follow procedure when calibrating Loop 3 Steam Pressure Channel 1 on Unit 1. Because of failure to follow procedure, automatic steam generator level control rapidly reduced feedwater flow to the point where programmed level could not be maintained and caused the operators to manually trip the reactor. The licensee entered the problem into their corrective action program and initiated actions to prevent recurrence. The finding was more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and resulted in an upset in plant stability by causing a reactor trip. While the finding resulted in an actual trip, the finding was determined to be of very low safety significance, because it did not contribute to the likelihood of a loss of coolant accident, contribute to a loss of mitigation equipment functions, or increase the likelihood of a fire or flood. The cause of the finding was associated with the human error prevention techniques aspect of the human performance cross-cutting area, because the involved instrument technicians failed to follow proper placekeeping practices and failed to verify and validate the proper starting place in the procedure after taking a break. (Section 1R22)
05000327/FIN-2008002-03	2008Q1	Green		Licensee-identified	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion XI, requires the licensee establish a test program to assure that all testing required to demonstrate that components will perform satisfactorily in service is identified and performed. Procedure SPP-6.3, Pre/Post-Maintenance Testing, Revision 2, implemented the required testing program and stated that postmaintenance testing was to assure that a new deficiency was not created by maintenance. Contrary to this, packing adjustments made to valve 2-VLV-62-527 in 2004 physically bound the valve, and post-maintenance testing did not verify that it would operate within the time required by licensee Procedure AOP-N.08, Appendix R Fire Safe Shutdown. This finding was determined to be of very low safety significance (Green) because of the very low frequency of fires which would result in a spurious safety injection and disable operation of both pressurizer Power-Operated Relief Valves or block valves.
05000327/FIN-2008002-04	2008Q1	Green		Licensee-identified	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion XI, requires the licensee establish a test program to assure that all testing required to demonstrate that components will perform satisfactorily in service is identified and performed. Procedure SPP-6.3, Pre/Post Maintenance Testing, Revision 2 implemented the required testing program for components returned to service after maintenance. Contrary to this, on February 11, 2008, the licensee returned the 2B 480V Board Room Chiller, and associated air handling unit, to service without completing the designated post-maintenance testing. When the testing was later performed, the air handling unit failed to meet acceptance criteria. The licensee restored the air handling unit and entered the issue into the corrective action program as PER 138145. This finding was determined to be of very low safety significance (Green) because the safety-related 480V board room chillers were not contained in the TS and not considered risk significant for the maintenance rule.
05000327/FIN-2008003-01	2008Q2	Green		NRC identified	Gland Seal Steam Header Isolation Valves Not Scoped in Maintenance Rule	The inspectors identified a Green, non-cited violation of 10 CFR 50.65(b)(2)(i) for the licensees failure to include the gland seal steam supply and supply bypass isolation valves in the scope of their maintenance rule program. These valves are used in the emergency operating procedures to mitigate a steam generator tube rupture if a main steam isolation valve were to fail. The licensee entered the issue into their corrective action program. The finding was more than minor because it was associated with the mitigating systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter IMC 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) because it did not represent an actual loss of a safety function of one or more non-Technical Specification trains of equipment designated as risk-significant per 10 CFR 50.65 (Section 1R12)
05000327/FIN-2008003-02	2008Q2			NRC identified	Procedure 0-MA-REM-001.0, Extended Station Blackout, Does Not Close Hydrogen Igniter Breakers	The licensee modified their Extended Station Blackout procedure to support the additional function and clarified its intent regarding power to the hydrogen igniters. While preparing to discuss restoration of power to the igniters with the inspector, the licensee identified a deficiency with the Extended Station Blackout procedure. Appendix R of this procedure provided guidance on restoring power to the 480V C and A Vent Boards, which energize the igniters; however, it left all the individual load breakers (including the breakers for the hydrogen igniters) in the OPEN position. Guidance for reclosing the hydrogen igniter breaker was omitted when the igniters were addressed in Revision 3 of the procedure. The licensee revised the procedure and generated a problem report to address this issue (PER 144301). This issue is being considered an Unresolved Item pending further inspection and review: URI 05000327, 328/2008003-02, Procedure 0-MA-REM-000-001.0, Extended Station Blackout, Did Not Close Hydrogen Igniter Breakers
05000327/FIN-2008003-03	2008Q2	Green		Licensee-identified	Licensee-Identified Violation	10 CFR 50.65(a)(4) requires the licensee to assess and manage increases in risk resulting from maintenance. Procedure SPP-7.2, Outage Management, Revision 10, implemented risk management reviews during outage periods and required that a risk assessment should be reperformed when emergent conditions exist which could change the conditions of a previously performed risk assessment. Contrary to this, on May 8, 2008, a shear pin failed on the fuel transfer tube wafer valve 2-VLV-78- 610, which prevented achieving containment closure had it been required. This emergent condition resulted in an escalation in risk from a Yellow threshold to an Orange threshold; however, a risk assessment was not reperformed. The risk condition change was not recognized prior to the licensee performing maintenance, specifically detensioning the reactor vessel head and entering Mode 6. The licensee replaced the failed shear pin and reestablished containment closure capability. Following repairs, the licensee realized that an elevated risk condition resulted from the shear pin failure, and this had not been reevaluated as required. The issue was entered into the corrective action program as PER 144542. This finding was determined to be of very low safety significance (Green) because of the short duration of the condition and the number and nature of risk management actions already in place
05000327/FIN-2008003-04	2008Q2	Green		Licensee-identified	Licensee-Identified Violation	10 CFR 50, Appendix B, Criterion XVI requires, in part, that Measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to the above, the licensee failed to identify the presence of, and subsequently repair, axial outside diameter stress corrosion cracking (ODSCC) in the free-span region of steam generator 3 tube R4C3 during the previous refueling cycle. The licensee entered this issue into the Corrective Action Program (CAP) as PER 145579. This finding is of very low safety significance because NRC Inspection Manual, Manual Chapter 0609, Appendix J, Table 1 provides guidance stating that one or more tubes that should have been repaired as a result of a previous inspection is preliminarily Green. Additionally, the indication in tube R4C3 was in-situ pressure tested and withstood 3xAPNO with no detected leakage
05000327/FIN-2008004-01	2008Q3			NRC identified	Notice of Enforcement Discretion 08-2-001 For Both Control Room Air Conditioning System Trains Inoperable	On September 26, 2008, TVA requested the NRC exercise discretion to not enforce compliance with the actions required in Sequoyah Nuclear Plant, Units 1 and 2, TS LCO 3.0.5. The NRC granted the request to exercise discretion. On September 25, 2008, at 10:55 p.m., a failure of the motor for the B train MCR air handling unit (AHU) caused the B train of control room air conditioning system (CRACS) to be inoperable. TS LCO 3.7.15 required two independent CRACS trains to be operable. Due to scheduled maintenance on the 1A EDG, the A train of CRACS was also inoperable at this time solely due to its emergency backup power supply being inoperable. Under these conditions, TS LCO 3.0.5 required that action be initiated within 2 hours to place both Units 1 and 2 in hot standby within the next 6 hours. On September 26, 2008, at 4:04 a.m., the NRC verbally granted the request to extend the 6 hour time requirement to be in hot standby by an additional 36 hours, based in part on the 1A EDG being in a functional condition pending the verification of the parameters required for TS operability. At 2:00 p.m. on September 26, 2008, the 1A EDG was declared operable, and the NOED was exited. In response to this issue, the inspectors verified that the licensee protected equipment, as discussed with the NRC, and that the functional determination of the 1A EDG was valid. The licensee entered this condition into their corrective action program as PER 153304. Pending the licensees completion of the apparent cause evaluation, LER submittal, and the NRCs review of the circumstances and the evaluation, this issue is considered as Unresolved Item (URI) 05000327,328/2008004-01, Notice of Enforcement Discretion 08-2-001 for Both Control Room Air Conditioning System Trains Inoperable
05000327/FIN-2008004-02	2008Q3	Green		Licensee-identified	Licensee-Identified Violation	Technical Specification 3.0.4.a required that when an LCO is not met, entry into a Mode or other specified condition in the applicability shall only be made when the associated actions to be entered permit continued operation in the Mode to be entered for an unlimited period of time. Contrary to this, from initial power operations until August 2008, the licensee had entered Modes 2 and 1 with one main feedwater pump trip channel for the AFW automatic start function inoperable when the associated actions of TS 3.3.2 did not permit operation for an unlimited period of time in this condition. The licensee entered this issue into their corrective action program as PER 150982. The licensee subsequently requested and received a license amendment that revised the applicability of TS 3.3.2. This finding is of very low safety significance because it did not represent an actual loss of safety function since other initiation signals remained available to automatically start the AFW pumps if needed
05000327/FIN-2008005-01	2008Q4	Severity level IV		NRC identified	Failure to Notify the Commission Within 30 Days After a Licensed Operator Was Diagnosed With a Permanent Physical Medical Condition	The NRC identified a non-cited violation (NCV) of 10 CFR 55.25 and 50.74 for failure to notify the Commission within 30 days after a licensed operator developed a permanent change in his physical condition. The licensee entered this finding into their corrective action program as problem evaluation report 158614. This finding was evaluated using the traditional enforcement process because the licensees failure to report the changes in medical condition impacted the Commissions ability to perform its regulatory function associated with operator licensing. Using Supplement I, Reactor Operations, of the NRC Enforcement Policy, this finding was determined to be a Severity Level IV violation because the change in the operators physical condition did not impact his ability to perform licensed duties. The cause of the finding was the licensee failed to understand that all permanent conditions, disabilities, and incapacities must be reported to the NRC for evaluation, regardless of whether the operator had exceeded the specific minimum requirement or the related disqualifying condition threshold in ANSI/ANS-3.4, Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants. (Section 1R11.1
05000327/FIN-2008005-02	2008Q4			NRC identified	Acceptability of Proceduralized Departures from TS Requirements Without NRC Approval in AOP-M.09	An unresolved item (URI) was identified for NRC review of whether the licensees preplanned and proceduralized departures from TS requirements, without obtaining NRC approval, constituted a non-compliance with NRC regulations. The licensee implemented a new abnormal operating procedure, (AOP)- M.09, Loss of Charging, Rev. 0, to address the loss of one or both centrifugal charging pumps (CCPs) in Modes 1-4. This procedure replaced a portion of the guidance in Annunciator Response Procedure 1,2-AR-M6-C Window D-3 (Charging Line Flow Abnormal alarm). The licensee determined that a loss of both CCPs would result in the loss of RCS boration and RCS makeup (charging) capability. AOP-M.09 contains contingency actions for reducing RCS pressure and using a Safety Injection (SI) pump to inject to the RCS to borate and maintain pressurizer level. At Mode 4, AOP-M.09 requires an evaluation of 50.54(x) criteria and further directs use of the SI pumps. Injection using the SI pumps in Mode 4 would violate the requirements of TS LCO 3.4.12, Low Temperature Overpressure Protection System, which requires that the SI pumps be incapable of injection. Summary: This issue will remain open for NRC review of whether the licensees preplanned and proceduralized departures from TS requirements, without obtaining NRC approval, constitute a non-compliance with NRC regulations. It will be identified as URI 05000327,328/2008005-02: Acceptability of Proceduralized Departures from TS Requirements Without NRC Approval in AOP-M.09
05000327/FIN-2008005-03	2008Q4	Severity level Enforcement Discretion		NRC identified	Technical Specification for the Containment Gaseous Radiation Monitors	The inspectors identified a violation of Unit 1 and 2 TS 3.4.6.1, Leakage Detection Instrumentation, for the licensees failure to maintain the gaseous lower containment atmosphere radioactivity monitor of the RCS leakage detection instrumentation operable. The Unit 1 and 2 monitors were inoperable since June 1987 as a result of not being able to perform their safety function of detecting a reactor coolant pressure boundary leak of 1 gallon per minute in one hour due to improvements in reactor fuel quality. The NRC is exercising enforcement discretion not to issue enforcement action for this violation in accordance with Enforcement Guidance Memorandum (EGM) 09-001, Dispositioning Violations of NRC Requirements for Operability of Gaseous Monitors for Reactor Coolant System Leakage Detection. Description: On November 6, 2008, the inspectors, after consultation with the Office of Nuclear Reactor Regulation (NRR), informed the licensee that the gaseous lower containment atmosphere radioactivity monitor on both Units 1 and 2 were not operable. The licensee initiated PER 156667, declared the equipment inoperable, complied with the applicable actions of TS 3.4.6.1 which allowed up to 30 days of continued operation with compensatory actions in place, and submitted a license amendment request to change the TS. The TS amendment was issued on December 4, 2008, which removed the requirement to maintain the gaseous channel of the containment atmosphere radiation monitors as a method of RCS leakage detection. NRR determined that the technical bases for the gaseous lower containment atmosphere radioactivity monitor to be operable included sufficient sensitivity to detect a reactor coolant pressure boundary leak of 1 gallon per minute (gpm) in one hour. This sensitivity was consistent with the information provided in Information Notice (IN) 2005- 024, Nonconservatism in Leak Detection Sensitivity. This IN informed licensees that the 0.1-percent failed fuel assumption (original source term for sensitivity calculations) introduced a nonconservatism into the TS. However, the licensing bases for Sequoyah Units 1 and 2 were not clear, in that, the licensing basis documents acknowledged that, for fuel with little or no defects, this sensitivity would not be expected. NRR considered that this circumstance would only occur immediately after initial plant startup. However, the licensee mistakenly concluded that these monitors would likewise be considered operable any time that fuel with little or no defects was again in use, e. g., due to improved fuel quality. In June 1987, calculation APS3-055, Reactor Coolant Pressure Boundary Leakage Detection with the Containment Lower Compartment Air Radiation Monitor, concluded that, for realistic RCS activity levels, the gaseous channel would not be capable of meeting the 1 gpm in one hour sensitivity. As discussed above, the licensee failed to recognize that not meeting the required sensitivity resulted in the gaseous lower containment atmosphere radioactivity monitors being inoperable.
05000327/FIN-2008006-01	2008Q2	Green		NRC identified	Fire Detectors in 480 V Shutdown Board Room 2B2 Not Installed According to NFPA Code	A Green NCV of Unit 2 License Condition 13, Fire Protection, was identified since fire detectors in the Unit 2 480 Volt shutdown board room 2B2 were not installed according to the applicable National Fire Protection Association code. Specifically, two detectors were located near forced ventilation fresh air inlets. The licensee entered this issue into their corrective action program and promptly posted a continuous fire watch in the fire area. This finding is a performance deficiency because the licensee did not properly locate the smoke detector or the heating, ventilating and air conditioning (HVAC) system supply air inlet registers to adequately comply with the applicable industry code of record for the facility. As a result two of the four smoke detectors would not be effective in detecting fires. The finding 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 substantially affects the objective of ensuring reliability and capability of systems that respond to initiating events. Considering the degree of system degradation, the length of time the problem existed, the calculated fire frequency for the fire area and shutdown systems independent of the fire area the finding was of very low safety significance
05000327/FIN-2008006-02	2008Q2	Green		NRC identified	Sprinkler System in Room 690.0-A1 of the Auxiliary Building has NFPA Code Deviation	The team observed a number of water suppression sprinkler heads in the eastern portion of the Auxiliary Building Elev. 690 (Room 690.0-A1, Fire Area FAA-029) that were located approximately six feet below the ceiling. These sprinkler heads are part of an NFPA 13 preaction sprinkler system which requires that the sprinkler heads in this area be no more than 12 inches below the ceiling. The sprinkler system in this area would not be effective in a response to a fire since the time delay to fuse any particular sprinkler head could be significant due to the location of the sprinkler heads. This portion of the sprinkler system does not meet the requirements of NFPA 13 and the licensee could not produce an evaluation or analysis that demonstrated the capability of this system to adequately control a potential fire in this area. However, the licensee claimed that the installation had been previously approved by the NRC; therefore, considered the system non-degraded. They did, however, initiate a Problem Evaluation Report (PER) to evaluate the condition. In order to determine all the facts concerning the licensing basis of the system and to review the potential acceptability of the as-built system with its code deviation an URI was established: URI 05000327, 328/2008006-02, Sprinkler System in Room 690.0-A1 of the Auxiliary Building has NFPA Code Deviation
05000327/FIN-2008006-03	2008Q2	Green		NRC identified	Sprinklers too far below Ceiling in Cable Spreading Room	A green NCV of Unit 1 License Condition 16 and Unit 2 License Condition 13, Fire Protection, was identified for failure to install the automatic suppression system (sprinkler system) in the cable spreading room according to the applicable National Fire Protection Association standard with regard to the ceiling to sprinkler head dimension. As a result, the fusible link type sprinkler heads may be significantly slower than originally intended after fire ignition. The licensee entered this problem into their corrective action program. This finding is a performance deficiency because the licensee did not locate the sprinkler heads according to the applicable industry code of record for the facility. The finding 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 substantially affects the objective of ensuring reliability and capability of systems that respond to initiating events. The finding was determined to be of very low safety significance when the likelihood of fires, the transients that could be initiated by fires and the probability of failure of mitigating systems for those transients were evaluated
05000327/FIN-2009002-01	2009Q1	Green	H.11 H.12	Self-revealing	Pressurizer Pressure Transient due to Inadequate Maintenance Procedure	A Green self-revealing non-cited violation of Unit 2 Technical Specification 6.8.1 was identified for the licensees failure to have an adequate procedure to ensure replacement of the pressurizer pressure master controller would not adversely impact plant stability. Specifically, on January 7, 2009, operators placed a pressurizer spray valve controller in automatic while the master controller was in manual with a large demand output signal present. This resulted in the spray valve fully opening and an associated reactor coolant system pressure transient. Operators immediately restored pressure to its normal value, and the finding was entered into the licensees corrective action program as Problem Evaluation Report (PER) 160504. The finding was greater than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Significance Determination Process, Attachment 4, the finding was determined to have very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. The cause of this finding was determined to be in the cross-cutting area of human performance associated with work practices and the aspect of human error prevention, in that, during the pre-job brief, the operators discussed minimizing the master controller demand signal but failed to self and peer check to ensure that the procedural steps were consistent with the appropriate actions (H.4(a)) (Section 1R19)
05000327/FIN-2009002-02	2009Q1	Green		NRC identified	Procedure 0-MA-REM-000-001.0, Extended Station Blackout, Did Not Close Hydrogen Igniter Breakers	An NRC inspector identified a Green finding for the licensees failure to implement a docketed commitment made to the NRC. Specifically, the licensee did not adequately revise procedures in accordance with a self-imposed standard to provide backup power to at least one train of hydrogen igniters in response to Generic Safety Issue 189 Susceptibility of Ice Condenser and Mark III Containments to Early Failure from Hydrogen Combustion During a Severe Accident. The revised procedures failed to close the supply breaker to the hydrogen igniter. The licensee entered this issue into their corrective action program as Problem Evaluation Report 144301. The finding is more than minor because it is associated with the Procedure Quality attribute of the Reactor Safety/Barrier Integrity Cornerstone. The inadequate procedure affects the cornerstone objective to provide reasonable assurance that physical design barriers, specifically maintaining the functionality of containment, protect the public from radio nuclide releases caused by accidents or events. For this finding, the accident sequences are associated with station blackouts. A Phase 3 Significance Determination Process evaluation was required to ascertain the safety significance. A regional senior reactor analyst performed a Phase 3 evaluation and determined that this performance deficiency was of very low safety significance (Green) (Section 4OA5.5)
05000327/FIN-2009003-01	2009Q2			NRC identified	Containment Equipement Hatch Closure Capability during Fuel Handling Accident	The inspectors identified an unresolved item (URI) involving the licensees implementation of a commitment concerning closure of the containment equipment hatch in the case of a fuel handling accident in the containment building. This issue is unresolved pending further NRC inspection and review of additional information to be provided by the licensee. On April 1, 2009, during a refueling outage of Unit 1, the inspectors performed a routine inspection of the licensees ability to close the containment equipment hatch should residual heat removal (RHR) cooling be lost while the reactor coolant system (RCS) is open to the containment atmosphere. The inspectors noted that the licensee had performed an analysis of containment environmental conditions, following the loss of RHR, to determine how much time was available to close the hatch prior to conditions within the containment becoming so harsh as to potentially prohibit hatch closure. The licensee conducted a drill to ensure that personnel could be mobilized and the hatch could be closed within analyzed time limits. Upon review of the analysis, the inspectors noted that it covered only the condition of loss of RHR. Further inspection revealed that the licensee also intended to leave the equipment hatch open during fuel movement in the containment building, and that the plant Technical Specification (TS) Bases specified that a method to promptly close the containment equipment hatch during movement of irradiated fuel assemblies will be in place. This commitment was introduced into the plants licensing basis as part of a license amendment issued on October 28, 2003, which was TS change 02-08, Partial Scope Implementation of the Alternate Source Term and Revision of Requirements for Closure of the Containment Building Equipment Door During Movement of Irradiated Fuel. This TS change revised LCO 3.9.4 to remove the requirement for the containment equipment hatch to be closed during movement of fuel within the containment, unless the fuel had been irradiated (i.e. part of a critical core) within the previous 100-hour period. The change included a commitment to establish the capability to close the equipment hatch in the event of a fuel handling accident. This commitment was reflected in the revision to the TS Bases, as noted above, and was implemented through a revision to the licensees procedure AOP-M.04, Refueling Malfunctions, revision 6, on October 25, 2004. The inspectors requested that the licensee provide a copy of the analysis which determined that the environmental conditions which would be present within the containment following the design basis fuel handling accident would not prohibit plant personnel from closing the hatch in accordance with the commitment reflected in the TS Bases. The licensee was unable to provide such an analysis. The inspectors noted that licensee design basis document SQN-DC-V-21.0, Sequoyah Nuclear Plant Environmental Design, revision 20, identified that a fuel handling accident is among those design basis accidents that could result in plant personnel approaching GDC-19 dose limits, and requires that a post accident mission dose analysis shall be performed where plant personnel are required to enter vital areas of the plant via a preplanned procedure to maintain the plant design basis following a fuel handling accident. The inspectors also noted that plant procedure EPM-7-1, EOI Administrative Controls, revision 8, required that the mission dose estimate be evaluated, prior to implementing new manual operator actions in EOPs or AOPs, for all activities required to be performed outside the control room in the event of a design basis accident as identified by SQNDC- V-21.0. The inspectors requested the mission dose calculation for hatch closure following a design basis fuel handling accident. The licensee was unable to provide such a calculation. It was identified that this evaluation had not been performed in conjunction with revision 6 to AOP-M.04. These issues were entered into the licensees corrective action program as PERs 167420 and 167428. Pending additional information from the licensees evaluation of their ability to close the equipment hatch following a fuel handling accident, this item is identified as URI 050000327,328/2009003-01, Containment Equipment Hatch Closure Capability During Fuel Handling Accident
05000327/FIN-2009003-02	2009Q2	Green		Self-revealing	Reactor Trip Due to Inadequate Plant Operating Procedures	A self-revealing NCV of Unit 1 Technical Specification 6.8, Procedures & Programs, was identified for the licensees failure to maintain adequate procedures for plant startup and power operation to support an as designed plant response following a turbine trip. This resulted in an automatic isolation of intermediate pressure feedwater heaters, which caused a loss of condensate flow and a reactor trip. This issue was entered into the licensees corrective action program as Problem Evaluation Report (PER) 169976. The licensee revised the applicable procedures to address the inadequacies. The finding was greater than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be applicable to a Phase 2 analysis since the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. Using IMC 0609 Appendix A, Determining the Significance of Reactor Inspection Findings for At- Power Situations, a Phase 2 analysis was performed using the pre-solved table derived from the site specific risk-informed inspection notebook. Based on the results of the Phase 2 analysis, the finding was determined to have very low safety significance (Green). No cross-cutting aspect was identified since the issue was not reflective of current licensee performance, in that the failure to maintain plant operating procedures to appropriately address heater drain operations occurred following the identification of the issue in 1998, and the procedure inadequacies were promptly identified and corrected by the licensee following the April 2009 event
05000327/FIN-2009004-01	2009Q3	Green	H.9 H.2(b)	Self-revealing	Failure to Follow Emergency Diesel Generator Operating Procedure	A self-revealing non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to follow plant procedures for performing independent verifications of procedural steps. Emergency Diesel Generator (EDG) 1B-B was declared operable when it was unable to perform its required safety function due to 11 of 32 cylinder test plugs not being positioned as required following pre-start rolling, which subsequently resulted in EDG damage during testing. This issue was entered into the licensees corrective action program as Problem Evaluation Report (PER) 201282. The licensee performed corrective maintenance and returned the emergency diesel generator to service. The finding was determined to be greater than minor because it was associated with the configuration control attribute of the mitigating system cornerstone and affected the cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences, in that operator error and damage to the 1B-B EDG rendered the EDG unavailable to perform its safety function. Using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because the it did not represent a loss of safety function, a loss of single train of safety equipment for greater than the TS allowed outage time, a loss of significant maintenance rule equipment for greater than 24 hours, or screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The cause of this finding was determined to have a cross-cutting aspect in the area of human performance associated with the resources component. It was directly related to the training of personnel (H.2(b)). Specifically, the operator that performed the independent verification of the vent valves positions did not receive training on the operation of the new design of EDG cylinder vent valves. (Section 1R15)
05000327/FIN-2009004-02	2009Q3	Green	H.7	Self-revealing	Feedwater Regulating Valve Failure due to Inadequate Maintenance Procedure	A self-revealing finding was identified for an inadequate maintenance procedure which was used to perform a rebuild of the Unit 1, Loop 1, main feedwater regulating valve (FRV) actuator. The failure to specify an applicable torque requirement associated with the installation of the control air diaphragm resulted in a failure of the diaphragm and a reactor trip due to a loss of main feedwater to the Loop 1 steam generator. The event was reported to the NRC as event notification (EN) 45045 and documented in the licensee corrective action program as PER 170598. The finding was determined to be greater than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability, in that the FRV actuator failure caused a reactor trip and loss of main feedwater to the Loop 1 steam generator. Using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. The cause of this finding was determined to have a cross-cutting aspect in the area of human performance associated with the resources component. It was directly related to the availability of resources necessary for complete accurate and up-to-date work packages. (H.2(c)) Specifically, the licensees vendor manual for the affected component was not maintained up-to-date to contain the most current information and requirements from the vendor applicable to the maintenance activities conducted (Section 4OA3.2)
05000327/FIN-2009004-03	2009Q3	Green	H.14	NRC identified	Failure to Perform a 10 CFR 50.59 Evaluation for Abnormal Operating Procedure M.09, Loss of Charging	The inspectors identified a Severity Level IV NCV of 10 CFR 50.59 for the licensees failure to perform a 10 CFR 50.59 evaluation for a new station Abnormal Operating Procedure (AOP) - M.09, Loss of Charging, Rev. 0, that included a preplanned, proceduralized 10 CFR 50.54(x) action that was a deviation from the Technical Specifications (TS). The licensee entered this issue into their corrective action program as PER 158739, and completed the corrective actions to remove the NRC unapproved operator actions from the procedure. This finding was assessed using traditional enforcement. The finding was more than minor because the change requiring 10 CFR 50.59 evaluation would have required NRC review and approval prior to implementation. A regional senior risk analyst performed a Phase 3 Significance Determination and characterized the performance deficiency as very low safety significance (Green) based on risk. The inspectors concluded that the finding reflected current licensee performance and involved the cross-cutting aspect of non-conservative assumptions of the decision-making component of the cross-cutting area of Human Performance (H.1(b))
05000327/FIN-2009005-01	2009Q4	Green		NRC identified	Failure to Evaluate Mission Dose for Manual Operator Actions Required by Plant Procedures	The inspectors identified a non-cited violation (NCV) of Units 1 and 2 Technical Specification 6.8, Procedures & Programs, for the licensees failure to follow procedures involving the review and approval of revisions to a plant abnormal operating procedure (AOP). The incorporation of manual operator actions regarding closure of the containment equipment hatch in the event of a fuel handling accident into a plant AOP without performing a mission dose evaluation resulted in the likelihood that personnel involved with the activity would receive a dose in excess of regulatory limits for occupational exposure. The licensee entered this issue into their corrective action program as PERs 167420 and 167428. The finding was determined to be greater than minor because it was associated with the program and process attribute of the occupational radiation safety cornerstone and affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The cornerstone objective was affected since adequate worker protection from exposure to radiation was not ensured through the AOP revision process. Using Inspection IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and Appendix C, Occupational Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance (Green) because it did not affect the licensees ability to assess dose, did not involve an overexposure or substantial potential for overexposure, and was not related to ALARA planning. No cross-cutting aspect was identified since the issue was not reflective of current licensee performance, in that the performance deficiency occurred in 2004
05000327/FIN-2009005-02	2009Q4	Green		Self-revealing	Reactor Trip due to Inadequate Transformer Bus Duct Maintenance Procedure	A self-revealing finding was identified for an inadequate maintenance procedure which was used to perform a periodic maintenance activity to clean and inspect the bus duct associated with the D common station service transformer (CSST). This resulted in the bus duct being left in a condition that allowed for water intrusion to occur, which led to a fault that caused a loss of one offsite power supply and an automatic reactor trip of both units with main feedwater unavailability. The licensee entered this issue into the corrective action program (CAP) as PER 166884. The finding was determined to be greater than minor because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Specifically, the use of an inadequate procedure directly contributed to the loss of one offsite power supply and an automatic reactor trip of both units with main feedwater unavailability. Using Inspection IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be applicable to a Phase 2 analysis since the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. Using IMC 0609 Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, a Phase 2 analysis was performed using the site specific risk-informed inspection notebook. The finding was assumed to affect the initiating event likelihood (IEL) of a Transient With Loss of Power Conversion System (TPCS), since power availability to the unit boards affects reactor coolant pump function as well as main condenser availability. A regional Senior Reactor Analyst performed a Phase 3 Significance Determination Process evaluation. The evaluation concluded the finding was of very low safety significance (Green) based on an assumed unavailability of the CSST B fast transfer function of 0.11/yr. No cross-cutting aspect was identified since the issue was not reflective of current licensee performance, in that the inadequate maintenance procedure was implemented in December 2006
05000327/FIN-2009006-01	2009Q3	Green	P.3	NRC identified	Failure to Promptly Correct a Condition Adverse to Quality Associated with Out-of-Train Maintenance Controls	The NRC identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the licensees failure to promptly correct a condition adverse to quality by failing to implement corrective actions to address deficient out-of-train maintenance controls during opposite train work weeks. This contributed to entry into a short term shutdown action statement and a Notice of Enforcement Discretion (NOED). The failure to implement corrective action to provide guidance for controlling out-of-train maintenance was entered into the licensees corrective action program as PER 177665. This finding was determined to be greater than minor because it was associated with the Barrier Integrity Cornerstone attribute of barrier performance, and on September 25, 2008, adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers such as the control room protect plant operators and plant controls. The finding was evaluated using Phase 1 of the At- Power Significance Determination Process, and was determined to be of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function provided for the control room. The finding was assigned a cross-cutting aspect in the corrective action program component of the problem identification and resolution area because, although the licensee had identified deficient controls for out-of-train maintenance, corrective actions were not taken to address the issue in an adequate and timely manner, commensurate with safety significance and complexity. (P.1(d)). (Section 4OA2.a.(3)
05000327/FIN-2009006-02	2009Q3			NRC identified	Inadequate Scopng of SSCs Used in EOPs into the Maintenance Rule Program	On April 11, 2008, PER 142050 was initiated by the licensee to address an NRC identified Non-Cited Violation (NCV) 05000327, 328/2008003-001, Gland Seal Steam Header Isolation Valve not scoped in Maintenance Rule. One of the corrective actions for this PER was to develop a position paper detailing the basis, background, analysis, and recommendations for adding the Main Steam Isolation Valve (MSIV) backup function into the MR program. As part of this position paper, the licensee performed an extent of condition review that stated, in part, ...for those SSCs previously excluded, the functions would need to be identified and classified... Based on a review of CAP documents the team concluded that there were no open corrective action items to ensure that those SSCs whose use was called out in EOPs were promptly identified and scoped into the MR program as appropriate. Additionally, based on a review of licensee MR program documents and EOPs, the team concluded that although the steam dumps were used in EOP-3 to cool down the Reactor Coolant System (RCS) during Steam Generator Tube Rupture (SGTR) event, no corresponding function for the steam dumps was found in TI-4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting 10 CFR 50.65. On July 24, 2009, as a result of the teams concern related to the scoping of EOP SSCs into the MR program, the licensee initiated PER 177211 to evaluate how SSCs that are used to mitigate accidents or transients listed in the EOPs, meet the scope requirements of 10 CFR 50.65. The team concluded that in order to properly evaluate and disposition this issue, additional inspection would be required to understand both the scope of the SSCs involved and the potential impact to the plant that may have occurred as a result of the failure to scope those SSCs into the MR program. The inspection team identified no immediate safety concern because, although there was evidence that the steam dumps were not scoped in the MR program as required, component performance was otherwise being maintained through the use of an established preventive maintenance program and there was no direct evidence that steam dump performance or material condition was being adversely impacted by the failure to scope the steam dumps within the MR program. This issue was identified as URI 05000327, 328/2009006-002, Inadequate Scoping of SSCs Used in EOPs into the Maintenance Rule Program
05000327/FIN-2009007-01	2008Q4	Severity level IV		NRC identified	Falsifying Data	During an NRC investigation conducted between February 20, 2008 and December 16, 2008, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: 10 CFR 50.9 (a) requires that information provided to the Commission by a licensee or information required by statute or by the Commissions regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects. Technical Specification 6.8.1 requires procedures described in Appendix A of RG 1.33, Revision 2 to be established, implemented, and maintained. Paragraph 10 of Appendix A of RG 1.33 requires, in part, that chemical control procedures be written to prescribe the limitations on concentrations of agents that may cause corrosive attack or fouling of heat transfer surfaces and specify laboratory instructions and calibration of laboratory equipment. Licensee procedure SPP-5.3, Chemistry Control, Revision 5, implemented this requirement for all TVA nuclear facilities. Step 3.1.3 of procedure SPP-5.3 required Chemistry licensee personnel, including Chemistry Supervisors, to implement chemistry quality assurance and quality control (QA/QC) programs. Appendix D of procedure SPP-5.3 described chemistry quality assurance, quality control and referenced procedure CHTP-109, Chemistry QA/QC, for the details. Step 4.2.3E of procedure CHTP-109 required that a known control standard check within the same concentration range as the instrument calibration range be performed along with each batch of samples and described a batch as less than or equal to 10 samples in a 12 hour period. Contrary to the above, on January 25, 2008, a Chemistry Shift Supervisor deliberately entered false data into the Chemistry Department internal laboratory statistics database. Specifically, on January 24, 2008, the licensee employee failed to perform the required QA/QC standard check for the evening shift, and the following day entered false data into the database. This information was material to the NRC in that the substance of the information is used to determine compliance with the Technical Specifications. The Chemistry Shift Supervisors deliberate entry of false data into the internal laboratory statistics database caused the licensee (TVA) to be in violation of 10 CFR 50.9 (a). This is a Severity Level IV violation. Pursuant to the provisions of 10 CFR 2.201, TVA is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation (Notice
05000327/FIN-2009405-01	2009Q4	Green		NRC identified	Security
05000327/FIN-2010002-01	2010Q1	Green	H.12	Self-revealing	Reactor Trip due to Inadequate Configuration Control	A self-revealing finding was identified for two examples of the licensees failure to follow station procedures. The licensee failed to follow work order instructions to ensure two valves associated with the main feedwater pump turbine seal steam supply standpipe level switch were placed in their required positions following maintenance. Additionally, the licensee subsequently failed to follow requirements for procedure use and adherence when implementing a system operating procedure step to ensure the main feedwater pump turbine gland steam supply drain valves were in their required positions. This resulted in a manual reactor trip of Unit 2 due to indications of a loss of main feedwater pump turbine condenser vacuum. The licensee entered this event into their corrective action program as PER 209482.The finding was determined to be greater than minor because it was associated with the configuration control attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using Inspection IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. The cause of this finding was determined to have a cross-cutting aspect in the area of human performance associated with the work practices component. The causes associated with the failures to follow procedures were directly related to inadequate implementation of human error prevention techniques such as self and peer checking, proper documentation of activities, and not proceeding in the face of uncertainty or unexpected circumstances
05000327/FIN-2010002-02	2010Q1	Green		Licensee-identified	Licensee-Identified Violation	The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements that meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV. Units 1 and 2 TS 5.6.1.1.c required that used fuel assemblies not be stored adjacent to new fuel assemblies in the spent fuel pool due to criticality concerns. Contrary to this, on October 1, 2009 and October 7, 2009, the licensee performed fuel moves that placed 4 used assemblies adjacent to new fuel. During a review on October 28, 2009, the licensee discovered the error and took action to verify and maintain adequate spent fuel boron concentration at or above the level required by TS LCO3.7.13 to ensure adequate margin to criticality existed until fuel moves were conducted to restore compliance on October 31, 2009. The licensee entered the issue into the corrective action program as PER 206113 and reported the event in LER 05000327, 328/2009-008-00 and 2009-008-01. Manual Chapter 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, was used since the Significance Determination Process guidance for at-power and shutdown conditions does not apply to spent fuel pool criticality control. This finding was determined to be of very low safety significance (Green) because the spent fuelpool configuration was determined, by analysis, to be bounded by the calculation ofrecord specified in the FSAR and TS bases.
05000327/FIN-2010004-01	2010Q3	Green	P.1 P.1(a)	NRC identified	Inadequate Inspection of Raw Water Side of Containment Spray Heat Exchangers	The inspectors identified a non-cited violation of 10 CFR 50 Appendix B Criterion V, Instructions, Procedures, and Drawings, for the failure to provide adequate documented instructions for inspection of the containment spray heat exchangers. Preventive maintenance (PM) procedures associated with these inspections failed to provide for an adequate inspection of the ERCW side (shell side) of these heat exchangers. Consequently, the heat transfer capability of these heat exchangers has not been periodically verified through either testing or adequate visual inspection. The licensee entered this issue into their corrective action program as PER 236318. Planned corrective actions include the development and implementation of a single-tube method for thermal performance testing of the heat exchangers in lieu of inspection. The finding was determined to be greater than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, since the heat transfer capability of these heat exchangers has not been periodically verified through either testing or adequate visual inspection. Using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) since the finding did not represent an actual loss of safety function. The cause of this finding was determined to have a cross-cutting aspect of Corrective Action Program Issue Identification in the area of Problem Identification and Resolution associated with the Corrective Action Program component, in that the evaluation of PERs in 2009 on the subject of CS heat exchanger inspection failed to identify the need to resolve the discrepancy between the scope of the program PMs and the implementing procedure requirement for CS heat exchanger shell side inspection. Thus, the licensee failed to completely and accurately identify issues in the corrective action program (P.1(a)). (Section 1R07
05000327/FIN-2010004-02	2010Q3	Green		NRC identified	Non-Conservative Design Calculation for RHR Suction Temperature Limit	The inspectors identified a Green non-cited violation of 10 CFR 50 Appendix B Criterion III, Design Control, for the failure to provide design control measures for verifying the adequacy of the design calculation used to establish the maximum RHR operating temperature limit for maintaining ECCS operability. A design calculation yielded a non-conservative temperature limit for use in plant operations procedures. This resulted in several occasions where ECCS operability was in question due to the fluid temperature in the RHR system suction piping. The licensee entered this issue into their corrective action program as PER 215434. Corrective actions included revising operations procedures to reflect the corrected temperature limit from a revised calculation. The finding was determined to be greater than minor because it was similar to example 3.j. of IMC 0612 Appendix E in that the non-conservatism in the calculation resulted in a condition where reasonable doubt existed as to the operability of the ECCS system. Additionally, it was associated with the procedure quality attribute of the mitigating systems cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, plant procedures for RHR system operation contained non-conservative temperature limits for ensuring TS operability, and actual system temperatures exceeded the revised appropriate limit on several occasions. Using IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to be of very low safety significance (Green) since the finding did not represent an actual loss of safety function. No cross-cutting aspect was identified since the issue was not reflective of current licensee performance, since the previous calculation in question was last revised and approved in 1996. (Section 4OA2.3

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