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	Title	Quarter	Description
05000461/FIN-2003002-01	Failure to Provide Complete and Accurate Information to the NRC Which Impacted a Licensing Decision	2003Q1	Clinton Station management personnel informed NRC Region III by letter dated September 24, 2002, that two operators who had been examined for their operator licenses in August 2002 had long standing medical conditions that warranted reporting to the NRC for review. Both operators were issued a license by the NRC on August 30, 2002. The licensee originally sent NRC Form 396s for both operators to Region III on June 26, 2002, without including their medical records and did not recommend any license restrictions. One operator had a history of myocardial infarction and the other had a history of coronary heart disease. The medical conditions described above are considered potentially disqualifying in accordance with American Nuclear Standards Institute/American Nuclear Society (ANSI/ANS) 3.4, 1983, and should have been reported to the NRC with a request for issuance of a license with a "no solo" restriction. When the licensee informed the NRC on September 24, 2002, of the medical conditions of the two operators there still was no request for an amended "no solo" license for either operator Because the issue affected the NRC's ability to perform its regulatory function, it was evaluated with the traditional enforcement process. The finding was determined to be of low safety significance because the operators had not acted in a solo capacity prior to having their license's amended. However, the regulatory significance was important because the incorrect information was provided under sworn statement to the NRC and impacted a licensing decision for the two individuals. The issue was preliminarily determined to be an apparent violation of 10 CFR 50.9.
05000461/FIN-2005006-01	Evaluation of Fire Induced Circuit Failures in HPCS System Control Logic	2005Q2	The team identified an Unresolved Item (URI) associated with potential fire-induced electrical circuit failures in the HPCS system. The team postulated a fire in the Division III switchgear room, located in Fire Zone CB-5a, which could result in fire-induced electrical circuit faults in the control cables and control logic of the HPCS pump and discharge valve. Such faults could potentially impair the capability to shut off the pump and stop it from continually injecting into the core. The team reviewed the methodology used by the licensee during the performance of Clintons post-fire safe shutdown circuit analysis to determine if it was consistent with NRC Regulatory Issue Summary (RIS) 2004-003, Revision 1, Risk- Informed Approach for Post-Fire Safe-Shutdown Circuit Inspections, issued on December 29, 2004. The team attempted to determine, based on available safe shutdown circuit analysis documentation (calculations, design drawings) used to perform the circuit analyses, if the licensee considered in their analysis circuit configuration failure scenarios such as multiple concurrent spurious component actuations due to fire induced cable shorts. The licensee stated that the fire induced cable failure mechanism was considered within the CPS Appendix R analysis, and therefore exceeded the RIS cable failure considerations. The team performed a sample review of post-fire safe shutdown circuit analysis, using the guidance and criteria provided in the RIS. The licensee documented in calculation IP-0532, 10 CFR Part 50, Appendix R, Compliance Assessment, that any and all spurious operations or failures shall be evaluated and that the spurious actuations or failures are not required at the time to be evaluated simultaneously except for high/low pressure interface components. However, the licensee stated that they did consider the potential for concurrent/simultaneous spurious actuations or failures in the Appendix R analysis for the ECCS system automatic initiation instrumentation logic network as well as the high/low pressure interface components. The team noted that no documentation was available for review to demonstrate that the licensee had evaluated the potential fire induced electrical circuit failures scenarios, postulated by the team, in the HPCS logic control system. The team evaluated fire induced circuit failures in the HPCS system that could potentially impact safe shutdown. The team selected HPCS pump 1E22-C001 and pump discharge valve 1E22-F004 logic circuitry and associated control cables for evaluation. The team reviewed licensing and design basis documents and related operating, emergency and shutdown procedures. The team performed a circuit analysis and evaluation using the following design drawings to determine CPSs compliance with their licensing basis and the approved fire protection program: E02-1HP99, Sheet 110, Schematic Diagram, High Pressure Core Spray (HP) HPCS Power Supply System (1E22-1070), Revision H; E02-1HP99, Sheet 501, Schematic Diagram, High Pressure Core Spray (HP) HPCS Suction Valve (1E22-F001) and HPCS Suct. Disc. Valve 1E22-F004, Revision J; E02-1AP03, Electrical Loading Diagram, Revision AA; M05-1074, P&ID High Pressure Core Spray (HP), Revision AG; CPS-SSD-LOG-217, Sheet 1, Division 3 Diesel Generator & Electrical Distribution Safe Shutdown Logic Diagram, Revision 2; and CPS-SSD-LOG-101, Sheet 1, High Pressure Core Spray Safe Shutdown Logic Diagram, Revision 2. The team conducted an evaluation of the impact of fire induced faults on HPCS system operation. The team postulated the following fire induced electrical faults, using guidance provided in the RIS, which could result in the HPCS discharge valve opening and the HPCS pump continually running and injecting water into the Reactor: HPCS Discharge Valve 1E22-F004 (Control Cable 1HP11C (12/c)): One hot short in the opening control logic circuitry of the valve, and one short to ground in the closing control logic circuitry of the valve. HPCS Pump 1E22-C001 (Control Cable 1HP08C (15/c)): One hot short in the breaker closing control logic circuitry of the HPCS pump which will close the pump breaker and start the pump, and two shorts to ground in the tripping circuitry of the pump control logic which will result in a blown fuse, and prevent tripping of the pump breaker. (Note that if the hot short stays in for 20 minutes then there is no need to postulate the faults in the tripping circuitry). The team determined that no documented evidence was available to indicate that the licensee considered the potential hot shorts, shorts to ground and open circuits, postulated by the team, in the multi-conductor control cables used in the control system of HPCS pump 1E22-C001 (15/c) and pump discharge valve 1E22-F004 (12/c). On June 8, 2005, the licensee, RIII, and NRR fire protection staff members conducted a conference call to further discuss the concerns raised by the team. The NRC requested that the licensee evaluate the postulated scenarios provided by the team and determine if CPS can achieve and maintain safe shutdown in Fire-Zone CB-5a if HPCS injection cannot be stopped and if CPS is within their licensing basis considering the electrical faults and fire induced actuations of HPCS components. The licensee provided their response to the NRC on June 20, 2005. The licensee entered this issue in their corrective action program under CR 00343489, dated June 13, 2005. This issue is considered an unresolved item (URI) pending NRC review of the licensees response to the issues raised by the team
05000461/FIN-2006011-01	Potential Inoperability of the HPCS Pump Due to Air Entrainment	2006Q4	During an NRC inspection completed on November 17, 2006, a violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed below: Title 10 Part 50, Appendix B, Criteria III states, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. It further states that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Title 10, Part 50.2 states, in part, that design bases means that information which identifies the specific functions to be performed by a structure, system, or component of a facility, and the specific values or ranges of values chosen for controlling parameters as reference bounds for design. These values may be (1) restraints derived from generally accepted state of the art practices for achieving functional goals, or (2) requirements derived from analysis (based on calculation and/or experiments) of the effects of a postulated accident for which a structure, system, or component must meet its functional goals. Contrary to the above, prior to August 12, 2006, the licensee had not ensured the adequacy of design of the high pressure core spray (HPCS) system by performance of design reviews or by use of alternate or simplified calculational methods. Specifically, the initiation of suction swap-over from the reactor core isolation cooling tank to the suppression pool, a controlling parameter to ensure continued function of the HPCS pump, was required to occur at 740.19 feet as derived by calculation IP-M-384, Revisions 0, 1, and 1B. However, this calculated value did not prevent significant air entrainment in the suction of the HPCS pump and subsequent loss of function of the HPCS pump. This violation is associated with a White SDP finding.
05000461/FIN-2007003-01	Licensee-Identified Violation	2007Q2	Section F of Clinton Power Stations operating license NPF-62, states that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the USAR. The USAR required that the fire protection program follow the requirements of Branch Technical Position APCSB 9.5-1, Appendix A, Plants Under Construction and Operating Plants. Branch Technical Position APCSB 9.5-1, Appendix A, requires that floors, walls and ceilings enclosing separate fire areas be sealed or closed to provide a fire resistance rating at least equal to the fire barrier itself. On November 2, 2006, the licensee identified two open, unsealed, 12\" x 12\" penetrations in the floor of the Division 3 switchgear room. The penetrations were under the main feed and reserve feed breakers to the 4kV switchgear for Division 3 . The inspectors determined that the failure to seal two penetrations between separate fire zones was a performance deficiency warranting a significance determination. The inspectors performed a Phase 2 evaluation using IMC 0609, Appendix F, Fire Protection Significance Determination Process. The inspectors determined that a credible fire scenario existed in that an energetic fault in the 4 kV Division 3 switchgear located directly above the open penetrations could ignite a non-safety related cable tray located directly below the open penetrations. A fire could then propagate horizontally along the non-safety related cable tray and then involve a Division 1 cable tray. The inspectors conservatively assumed that only Division 2 equipment would be available in such a scenario. Based on four vertical cabinet sections as being potential ignition sources, a 30 minute fire propagation time to reach the Division 1 cable tray, and remaining mitigating Division 2 equipment available, the inspectors determined that the issue was of very low safety significance.
05000461/FIN-2007004-04	Shipment Total Quantity RE-CHARACTERIZED After Shipping	2007Q3	A shipment of phase separator resins was shipped from Clinton Power Station September 30, 2005, and delivered to a vendor on October 1, 2005. The total curie quantity in the shipment was in excess of the vendors Agreement State license limits. The vendor communicated this discrepancy to shipping personnel at Clinton Power Station on October 3, 2005. The shipper then re-characterized the total quantity of the shipment by reviewing dose rate survey data and applying a dose to curie methodology. Contrary to Clinton procedure, the re-characterization was not reviewed by other Clinton personnel and new paperwork for the shipment, including a new NRC Form 541 was generated and transferred to the recipient. This event remains under review by the NRC and is categorized as an Unresolved Item (URI
05000461/FIN-2008002-01	Failure to Follow Approved Fire Protection Program Procedures Concerning Control of Transient Combustible Material	2008Q1	The inspectors identified a performance deficiency involving a NCV of Clinton Power Station Operating License NPF-62, Section 2.F for failure to implement the fire protection program in accordance with program requirements. The inspectors identified multiple instances of the licensees failure to follow approved fire protection program procedures concerning control of transient combustible material. Corrective actions for this issue included removing the unattended combustible material, initiating transient combustible permits, and/or initiating compensatory measures. The inspectors determined that this issue was more than minor because the identified transient combustibles were in a combustible free zone required for separation of redundant trains. This finding was of very low safety significance because the transient combustible materials identified by the inspectors were not combustibles of significance. The inspectors determined that this finding was cross-cutting in the area of Problem Identification and Resolution. Specifically, the licensee implements a corrective action program with a low threshold for identifying issues. The licensee identifies such issues completely, accurately, and in a timely manner commensurate with their safety significance (P.1(a
05000461/FIN-2008002-02	the Licensee Discovered That the Wrong Component Was Installed in the B Turbine Driven Reactor Feed Pump Oil Pressure Sensing Logic	2008Q1	A finding of very low safety significance was self-revealed by the automatic runback of the turbine driven reactor feed pump during post-outage power ascension. The licensee discovered that the wrong component was installed in the B turbine driven reactor feed pump oil pressure sensing logic. The inspectors determined that the licensee failed to perform an adequate post-maintenance test in accordance with procedures. This issue resulted in an unexpected power change from 54 percent power to 46 percent power. The licensee entered the issue into the corrective action program, performed tailgate discussions with technicians and work planners on the oil pressure switch configurations, and ensured that vendor purchase specifications for pressure switches were up-to-date in the materials and work management computer system. The inspectors determined this issue was more than minor because it was associated with the Human Performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the frequency of those events that upset plant stability. Specifically, the failure to perform adequate post-maintenance testing of pressure switch 1PS-FW135 permitted the wrong component to be installed and placed in service. This deficiency ultimately resulted in an unplanned plant transient. The finding was of very low safety significance because this issue did not increase the likelihood that mitigation equipment or functions would not be available. The inspectors also concluded that the failure of the technician to properly follow calibration procedure 8801.01 during the initial calibration of this switch represented a cross-cutting issue in the area of Human Performance, Work Practices (H.4(b)), because licensee personnel failed to follow procedures in regard to pressure switch calibration
05000461/FIN-2008002-03	During the Performance of NRC Final Drywell Closeout, the Inspectors Noted That Foreign Material/Housekeeping Sock Had Not Been Removed from the Drywell Floor Drains	2008Q1	The inspectors identified a finding and an associated NCV of 10 CFR Part 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, having very low safety significance during drywell closeout inspections. Specifically, during the performance of the NRC final drywell closeout, the inspectors noted that foreign material/housekeeping socks had not been removed from the drywell floor drains. This issue could have resulted in the drywell leak detection system being inoperable following a reactor event. The licensee procedures for drywell closeout directed licensee staff to remove all loose material and devices associated with the licensee material condition and housekeeping program. The licensees corrective actions for this issue included removing the floor drain socks and incorporating a work activities item for sock removal in the outage schedule template. The inspectors determined that this issue was more than minor because, if left uncorrected, it could result in a more significant safety concern. Failure to remove drain socks from drywell floor drains could result in the inability to readily detect and track unidentified leakage following a reactor event. The finding was of very low safety significance because this finding did not result in exceeding the Technical Specification limit for reactor coolant system (RCS) leakage nor did it affect other mitigating systems resulting in a total loss of their safety function. The inspectors also concluded that this issue was a result of no work item in the outage schedule to remove the socks, and therefore represented a cross-cutting issue in the area of Human Performance, Work Control (H.3.(b))
05000461/FIN-2008002-04	AS-FOUND Leakage Through Shutdown Service (Sx) Valve 1SX014A	2008Q1	The inspectors reviewed the results of CPS 9861.09D008, Leakage Test on Valve 1SX014A. This procedure provides direction for performing leak rate testing for the shutdown service water (SX) to normal service water system isolation valves to assist in the operability determination of the ultimate heat sink and the SX system. The procedure is performed every 24 months per Appendix V of the licensees Inservice Inspection Manual. The SX014A valve failed as-found testing due to excessive leakage following closure of the valve. During the test, the licensee was unable the quantify leakage past 1SX014A due to system test alignment and test connection limitations. On January 22, 2008, operators identified a significant leak on the 1SX014A valve after the valve was closed. The valve was taken to the closed position by operators to perform a leakage test on the valve per CPS 9861.09D008, Leakage Test on Valve 1SX014A. Valve 1SX014A is the shutdown service water to normal plant service water isolation valve. During normal operation, the valve is open. The valve closes automatically when the shutdown service water pump starts. This valve was installed to ensure the shutdown service water system remains capable of performing its design purpose without being compromised by the less stringent design requirements of the normal plant service water system. The valve is a 20-inch motor-operated butterfly valve. As required by step 8.2.1.2 of CPS 9861.09D008, the operators attempted to drain the test volume by opening the SX Division I supply header low point drain valve (1SX078A) and the two three-inch drain lines off the shutdown service water strainer basket (1SX171A and 1SX013A). The operators could not obtain a drained system. With the valves open, pressure on the discharge side of the strainer dropped to 13 psi. Using the valve position indications, the 1SX014A valve was verified shut locally, however the flow noise at 1SX014A continued and the differential pressure reading at the strainer indicated that 1SX014A was leaking by significantly. Despite not being able to get the system drained, operators re-established the leak test alignment (closed 1SX171A and 1SX013A) and attempted to perform a leak test. This attempt was made using the test connection at 1SX078A and a 55 gallon graduated barrel. The operators stated that with approximately two turns open on 1SX078A, the barrel filled in a few seconds (~ six seconds). The in-field operator recalled that following this test, control room staff stated system pressure was approximately 8 psi based on control room pressure indicator 1SXPI028. The licensee documented the test results in AR 725079. However, when the inspectors requested copies of the actual data sheet used during the leak test, the licensee was unable to provide copies of the surveillance test results. According to the licensees equipment apparent cause report, the valve was leaking by the seat. The failure mechanism was general corrosion of the valve body due to prolonged exposure to raw service water and possibly some contribution from microbiologically induced corrosion (MIC). The licensee investigation also concluded that galvanic effects might have played a role due to the interaction between the 316 stainless steel valve disc and the carbon steel valve body. Valve inspection revealed that the valve body had corroded such that the disc was not in full contact with the valve seat allowing the valve to leak by the seat (majority of seal ring detached). The valve body was made of carbon steel. The mechanical properties of carbon steel are greatly susceptible to corrosion damage, especially when there is a continuous flow of water. In addition, the licensees investigation determined the preventative maintenance frequency was incorrect, because the component category was incorrectly classified. The valve was classified as a Category 4 (no required inspection interval) component based on a designation of CriticalYES / Duty Cycle-LOW / Service Condition-MILD. The licensees review of the Performance Centered Maintenance Template and the application of this valve in raw water conditions led to the conclusion that the Service Condition should be SEVERE based on the corrosive conditions to which the valve is exposed. This would result in a classification of Category 2, which would require valve internal inspections every eight years. Therefore, the apparent cause of the failure was the incorrect application of the Performance Centered Maintenance (PCM) Template for this valve that resulted in an inappropriate PM interval for valve inspection. Prior to this failure, the licensee replaced this valve in 1997. Preventive maintenance activities for 1SX014A were reviewed and compared against the PCM Template recommendations. Preventive maintenance and frequency for 1SX014A were consistent with the Category 4 designation, with no required interval for inspection, and with a note that the inspection frequency should be based on site-specific experience and through the use on non-intrusive testing. For a Category 2 designation, the PCM Template would require valve inspections every eight years. During the review of the licensees equipment apparent cause evaluation (EACE) and the issue report documenting the valve failed leak test, inspectors noted that the licensee failed to address past operability. The inspectors were concerned because the design basis of the shutdown service water system is to remove heat from equipment necessary to safely shutdown the plant and maintain a safe plant shutdown. Updated Safety Analysis Report Table 9.2.3, Ultimate Heat Sink Auxiliary Loads from the Ultimate Heat Sink, provides a list of equipment and the heat loads cooled by the SX system. Licensee calculation IP-M-486, Shutdown Service Water System Hydraulic Network Analysis Model and Flow Balance, outlines the procedures and assumptions used in the creation of a hydraulic network analysis model to predict the performance of the SX system during design and accident conditions. This analysis assumes a system leakage value of 300 gpm. This calculation also assumes a minimum of SX system flow to validate heat load removal capability for each auxiliary load based on SX system flow. Leakage through 1SX014A represents a diversion of a portion of the SX system flow back to the Ultimate Heat Sink without serving the required heat loads. Additionally, licensee calculation IP-M-563 establishes allowable leakage (administrative limits) from the ultimate heat sink following a postulated design basis accident and loss of the main dam. In response to the inspectors concern, the licensee performed an evaluation to determine the amount of leakage past 1SX014A. The licensee evaluation determined that during the leak test 1SX014A had a leak rate of approximately 636 gpm. The licensees evaluation was based on a calculation showing the amount of flow through a fully opened 1SX078A valve at 8 psi. The licensee assumed 8 psi in the calculation based on control room staff information. Lastly, the licensee concluded that based on the past performance of the Division 1 shutdown service water pump the SX system would have been operable during the last refueling cycle. Upon review of the detailed evaluation performed by the licensee, the inspectors noted the following concerns: 1. The licensee used a calculated leak rate through 1SX078A as equivalent to leakage from 1SX014A. In NRC inspection report 2006-02, the inspectors documented NCV 05000461/2006-02-02 for inadequate test control. In this inspection report, the inspectors noted that Table 1, on Page 14 of calculation IP -563, Determination of Allowable Leak Rates and Loss of UHS Volume from the SX Boundary Valves, stated that the operability limit for leakage past an UHS boundary valve should normally be considered 100 gpm. However, since the test connection (1SX078A) is a 2.5-inch valve, approximately 55 gpm can be measured without interference from the test equipment. The inspectors concluded that based on restricted flow at the entrance test connection (30 inch discharge piping and 2 34-inch low-pressure drain line), observations of greater than 100 gpm leakage would be unreliable. Additionally, the inspectors concluded that, due to the test arrangement during the performance of the surveillance test, additional valve flow may be unaccounted for in other portions of the SX system. 2. The licensees use of eight psig as the limiting pressure for the evaluation. The inspectors noted that this pressure, as indicated on 1PI-SX028 (SX strainer outlet pressure indicator), may not be conservative in determining the movement of flow through the system. According to Sargent and Lundy instrument data sheet EI-601, 1PI-SX028 has an accuracy of +/- 2 percent of the scale range (+/- 4 psi). The scale range of 1PI-SX028 is 0-200 psi. Using this information, the inspectors determined that a conservative approach to evaluating system leakage would be to evaluate the leakage at 8 psi +/- 4 psi. Given that the instrument tap for the transmitter (1PT-SX028) was at the top of the pipe and the centerline of the 30 inch pipe was at plant elevation 702 ft. 6 inches, this issue could have a substantial effect on the licensees evaluation, in that, at 9.7 psi of static head the height of the water column is such that some of the leakage could have been lost through SX branch line 1SX02AA-30. Shutdown service water line 1SX02AA-30 is a 30-inch branch line off the main supply that enters the fuel building at plant elevation 726 ft. 5 inches (centerline). The highest water column height at a static head of 12 psi would be approximately plant elevation of 731 ft. 4 inches. At this height, the inspector concluded that flow through 1SX02AA-30 would not represent a closed system as assumed in the licensee detailed evaluation. Additional information has been requested of the licensee regarding specific details of past surveillance test results, complete system alignment during SX boundary valve tests, detailed piping isometrics, and the results of detailed interviews with plant operations and maintenance staff. The licensee entered this issue into its corrective action program as Action Request 00756099. Pending further review of this issue by NRC staff to determine whether the licensees evaluation accurately bounded 1SX014A leakage, this issue is being considered an Unresolved Item (URI 05000461/2008002-04)
05000461/FIN-2008002-05	Changes to ERO ON-SHIFT and Augmentation Staffing Levels and Position Titles	2008Q1	The inspectors reviewed changes to the Clinton Power Station Emergency Plan Annex and the Exelon Nuclear Standardized Radiological Emergency Plan on-shift ERO minimum staffing and augmentation requirements. In 1998, the licensee increased the minimum on-shift ERO staffing from 10 to 15 positions. Between 1998 and 2008, changes to position titles or expertise may have decreased the capabilities of several specific functions. In response to problems identified during a declared Alert on February 13, 1998, the licensee added five positions to its ten required on-shift ERO staffing positions, removed the eleven 30-minute ERO augmentation positions, and added six positions to the seventeen 60-minute ERO augmentation positions. The inspectors identified that several position titles had also changed since 1998. Specifically, in 1998 four radiation protection technicians were identified in ERO positions. Two of the four technicians were to provide on-shift radiological accident assessment and operational accident assessment support, including in-plant surveys during a radiological emergency. The other two technicians were designated to provide protective actions during an emergency including access control, health physics coverage for repair, corrective actions, search and rescue, first aid, and firefighting, as well as personnel monitoring and dosimetry. The current revision of Clinton emergency plan annex, Section 2.1, On-Shift Emergency Response Organization Assignments, Table B-1, Minimum Staffing Requirements for the On-Shift Clinton Station ERO, has replaced two of the radiation protection technician positions with non-licensed operators. Additional information has been requested of the licensee regarding specific position titles, functions, and additional revisions of the emergency plan minimum staffing requirements. The licensee entered this issue into its corrective action program as Issue Report 00752769. Pending further review of this issue by NRC staff to determine whether changes to position titles, functions, and responsibilities decreased the effectiveness of the emergency plan, this issue is being considered as an Unresolved Item (URI 05000461/2008002-05)
05000461/FIN-2008002-06	Failure to Evaluate Hydraulic Power Unit Piping for Impact with Containment Atmosphere Monitoring Line	2008Q1	The inspectors identified a finding and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, having very low safety significance, in that, in evaluating whether the reactor recirculation flow control valve A hydraulic power unit (HPU) piping was adequately supported in response to concerns raised in two condition reports, the licensee did not adequately address that the as-built support configuration had not been properly verified from a design standpoint. In particular, the licensee did not consider the safety-related classification of nearby containment/drywell atmosphere monitoring tubing and that this tubing could be impacted if the HPU piping failed during a postulated design basis seismic event. Hence, the licensee did not implement the additional evaluation/calculations required to demonstrate the HPU piping met more stringent design requirements and was adequately supported. The primary cause of the violation was related to the cross-cutting component of Human Performance, Resources (H.2(c)) because the licensee failed to maintain complete, accurate, and up-to-date design documentation. Subsequently, the licensee performed evaluations/calculations demonstrating that the HPU piping will not adversely impact the safety-related containment monitoring tubing during a design basis seismic event. The licensee entered the finding in the corrective action program as Action Request 723620. The finding was more than minor because it was associated with the Barrier Integrity Cornerstone and affected the cornerstone objective of maintaining functionality of containment due to the potential impact on the safety-related containment atmosphere monitoring system which was needed to monitor and to take actions to mitigate challenges to containment integrity. The finding was of very low safety significance because the licensees preliminary results based on conservative calculations indicated that the design basis requirements were met, and hence field modifications were not necessary
05000461/FIN-2008002-07	Failure to Barricade and Lock a Locked High Radiation Area	2008Q1	The inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification 5.7.2 for failure to barricade, lock, or continuously guard a high radiation area with dose rates greater than 1000 millirem per hour. On January 24, 2008, licensee staff failed to properly barricade and lock or guard three entrances to the under vessel area of the drywell. As corrective actions, the licensee suspended access to the Radiologically Controlled Area (RCA) for the personnel involved and initiated a prompt investigation, including assessment of the extent of condition plant-wide. The licensee entered the issued into the corrective action program as Issue Report (IR) 726499. The finding was more than minor because it was associated with the Program/Process attribute of the Occupational Radiation Safety Cornerstone and affected the cornerstone objective to ensure worker health and safety from exposure to radiation, in that, failure to follow procedures for control of locked high radiation areas could result in unplanned exposure. The finding was determined to be of very low safety significance because the finding did not involve As-Low-As-Is-Reasonably-Achievable (ALARA) planning, collective dose was not a factor, it did not involve an overexposure, there was not a substantial potential for a worker overexposure, and the licensee=s ability to assess worker dose was not compromised. Additionally, this finding has a cross-cutting aspect in the area of Human Performance because radiation protection staff did not appropriately follow procedures (H.4(b)) which governed control of access into locked high radiation areas
05000461/FIN-2008003-01	Licensee-Identified Violation	2008Q2	Failure to Survey Title 10 CFR 20.1501 requires that each licensee make or cause to be made surveys that may be necessary for the licensee to comply with the regulations in 10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials, and the potential radiological hazards that could be present. Contrary to the above, on March 26, 2008, the licensee did not make surveys to assure compliance with 10 CFR 20.1902, which requires the licensee to post each high radiation area with a conspicuous sign or signs bearing the radiation symbol and the words CAUTION, HIGH RADIATION AREA or DANGER, HIGH RADIATION AREA. Specifically, dose rates greater than 100 mR/hour were identified in the cask wash down pit in the fuel handling building after the area was downposted from a high radiation area. This was identified in the licensees corrective action program as AR 755161 and corrective actions included restoring proper high radiation area postings and controls. The finding was determined to be of very low safety significance because it was not an ALARA planning issue, there was no overexposure nor potential for overexposure, and the licensees ability to assess dose was not compromised
05000461/FIN-2008004-01	Failure to Perform Adequate Post-Maintenance Testing Resulted in High Reactor Vessel Water Level (Level 8) Scram	2008Q3	The inspectors identified a finding of very low safety significance associated with a self-revealed event that resulted in a Unit 1 reactor scram. The licensee failed to perform adequate post-maintenance testing following replacement of the feedwater level control system dynamic compensator card during the Cycle 10 refueling outage that concluded in February 2006. This resulted in an ineffective response from the feedwater level control system and a subsequent reactor scram following the unexpected loss of a reactor recirculation pump. The ineffective feedwater level control system response has not been corrected; however, the licensee entered this issue into its corrective action program for evaluation. No violation of regulatory requirements was identified. The finding was of more than minor significance because this issue was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, inadequate post-maintenance testing resulted in ineffective response from the feedwater level control system during a loss of a reactor recirculation pump transient and caused a reactor scram. The finding was of very low safety significance because the issue: (1) did not contribute to the likelihood of a primary or secondary system loss-of-coolantaccident initiator, (2) did not contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions would not be available, and (3) did not increase the likelihood of a fire or internal/external flooding event. The inspectors did not identify a cross-cutting area component related to this finding. (Section 1R12.b.1)
05000461/FIN-2008004-02	Failure to Evaluate an Unexpected and Unknown Cause for Stray Voltage in the End-of-Cycle Recirculation Pump Trip Circuit During Post Modification Testing Resulted in a Reactor Recirculation Pump Trip	2008Q3	The inspectors identified a finding of very low safety significance associated with a self-revealed event that resulted in the unexpected loss of a reactor recirculation pump. The licensee failed to evaluate an unexpected and unknown cause for stray voltage in the End-of-Cycle Recirculation Pump Trip (EOC-RPT) circuit during post-modification testing during the Cycle 11 refueling outage that concluded in February 2008. This resulted in the unexpected loss of a reactor recirculation pump and the subsequent plant transient that led to a reactor scram. As an immediate and interim corrective action, the licensee implemented a design change to the EOC-RPT circuitry that should prevent inadvertent relay actuation causing recirculation pump trips due to the stray voltage problem. No violation of regulatory requirements was identified. The finding was of more than minor significance because this issue was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to evaluate an unexpected and unknown cause for stray voltage in the EOC-RPT circuit during post modification testing resulted in the unexpected loss of a reactor recirculation pump and the subsequent plant transient that led to a reactor scram. The finding was of very low safety significance because the issue: (1) did not contribute to the likelihood of a primary or secondary system loss-of-coolant-accident initiator, (2) did not contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions would not be available, and (3) did not increase the likelihood of a fire or internal/external flooding event. The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, the licensee failed to appropriately incorporate risk insights in investigating and resolving an unexplained source of voltage in a circuit that had a high risk consequence (i.e., reactor recirculation pump trip). (IMC 0305 H.3(a)) (Section 1R12.b.2)
05000461/FIN-2008004-03	Failure to Perform Adequate Preventative Maintenance on Shutdown Service Water Valve 1SX014A Resulted in Significant Degradation and Gross Seat Leakage	2008Q3	A finding of very low safety significance with an associated NCV of Technical Specification (TS) 5.4.1.a was self-revealed. The licensee failed to perform adequate preventive maintenance on shutdown service water system valve 1SX014A. This resulted in significant degradation of the valve body by corrosion due to prolonged exposure to raw service water that went undetected until gross seat leakage was discovered while attempting to establish conditions for surveillance testing. The licensee replaced the valve and established a preventive maintenance schedule for internal valve inspections. The finding would become a more significant safety concern if left uncorrected and was therefore more than a minor concern. Specifically, the failure to adequately perform preventive maintenance could reasonably result in significantly degraded or inoperable safety-related equipment. Because the shutdown service water system was primarily associated with long term decay heat removal following certain design basis accidents, the inspectors concluded that this issue was associated with the Mitigating Systems Cornerstone. The finding was of very low safety significance because the issue: (1) was not a design or qualification deficiency; (2) did not represent an actual loss of safety function of a system; (3) did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time; (4) did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk significant; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, the licensees investigation determined that internal valve inspections were not performed because the component category was incorrectly classified. (IMC 0305 H.3(b)) (Section 1R12.b.3)
05000461/FIN-2008004-04	Failure to Recognize the Safety-Related System Function of the 1B Residual Heat Removal Pump Seal Cooler When Evaluating Past operability of the Pump	2008Q3	The inspectors identified a finding of very low safety significance associated with the licensees failure to recognize the safety-related system function of the 1B residual heat removal pump seal cooler when initially evaluating the past operability of the pump after unacceptable results were obtained during shutdown service water system flow balance testing. No analysis was performed to ensure that the pumps safety function would be fulfilled with less than minimum design flow to the cooler until the inspectors challenged the licensees original conclusion. The licensee re-performed the past operability evaluation and determined that sufficient margin existed such that the pump would have been able to fulfill its safety function with significantly less than design flow to the seal cooler as measured during the test. Corrective actions for the initial unacceptable results involved re-balancing shutdown service water system flow. No violation of regulatory requirements was identified. The finding would become a more significant safety concern if left uncorrected and was therefore more than a minor concern. Specifically, the failure to correctly recognize the safety-related functions of systems or components when performing operability or past operability evaluations could reasonably result in an unrecognized condition of a system failing to fulfill its safety-related function. In addition, based on review of examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, evaluation errors resulting in a reasonable doubt about the operability of a system or component are generally not considered to be of minor significance. Because the residual heat removal system was primarily associated with long term decay heat removal following certain design basis accidents, the inspectors concluded that this issue was associated with the Mitigating Systems Cornerstone. The finding was of very low safety significance because the issue: (1) was not a design or qualification deficiency; (2) did not represent an actual loss of safety function of a system; (3) did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time; (4) did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk significant; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. Subsequent evaluation was able to determine that sufficient margin in flow existed for the time period in question. The inspectors did not identify a cross-cutting area component related to this finding. (Section 1R15.b.1)
05000461/FIN-2008005-01	Failure to Control Transient Combustible Materials in Accordance with Fire Protection Program	2008Q4	The inspectors identified a finding of very low safety significance with an associated NCV of the Clinton Power Station Unit 1 Operating License (NPF-62, Section 2.F). The licensee failed to implement the Fire Protection Program in accordance with program requirements by failing to follow approved Fire Protection Program procedures for the control of transient combustible materials. The licensee promptly removed transient combustible materials found by the inspectors and subsequently completed a detailed walk down of the plants transient combustible free zones to identify and remove any additional transient combustible materials. The inspectors concluded that this finding could be reasonably viewed as a precursor to a significant event (i.e., a fire affecting more than one train of safe shutdown equipment). Specifically, the presence of transient combustible materials in a combustible free zone could reasonably result in degradation of the fire protection defense-in-depth elements in place to prevent fires from starting and mitigate the consequences of fires. In addition, based on review of Example 4k in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the issue would not be considered to be of minor significance because the identified transient combustibles were found in a combustible free zone required for separation of redundant trains. The finding was of very low safety significance because the items found in the combustible free zone would not be considered transient combustibles of significance as defined in IMC 0609, Appendix F, Fire Protection SDP, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, and therefore the issue was assigned a low degradation rating. The inspectors concluded that this finding affected the cross-cutting area of problem identification and resolution. Specifically, the licensee missed an opportunity to identify and remove the transient combustible materials while implementing corrective actions for previous inspector identified findings involving the control of transient combustible materials. (IMC 0305 P.1(a)) (Section 1R05.1
05000461/FIN-2008005-02	Maintenance Rule Scoping Question for Liquid Effluent Process Radiation Monitors	2008Q4	The inspectors reviewed equipment performance issues associated with radiation monitoring system instrumentation and found that Maintenance Rule evaluations were not being performed for liquid effluent process radiation monitor failures. The inspectors noted that liquid effluent process radiation monitors had not been included within the scope of the licensee s Maintenance Rule Monitoring Program and sufficient information or justification was not provided in the licensee s scoping determination documents to support the conclusion that was reached. The inspectors noted that in accordance with 10 CFR 50.65(b)(2)(i), non-safety-related SSCs that are used in plant Emergency Operating Procedures (EOPs) are required to be included in the scope of the licensee s Maintenance Rule Monitoring Program. The inspectors reviewed the plant s EOPs and discovered that the entry condition for EOP-9, Radioactivity Release Control, was any offsite liquid or gaseous release rate above the licensee s Emergency Plan Radiological Effluent Alert level. The inspectors reviewed EP-AA-1003, Exelon Nuclear Radiological Emergency Plan Annex for Clinton Station, Revision 13, and found that one of the three Emergency Action Level threshold values under the Emergency Plan Radiological Effluent Alert level was a valid reading on any effluent monitor > 200 times the high alarm setpoint established by a current radioactivity discharge permit for Y 15 minutes. The inspectors discussed this criterion with two licensed senior reactor operators at the plant (the Shift Operations Superintendent and a Shift Manager) to understand which liquid effluent monitors would be used by operators to evaluate this criterion since no specific monitors were listed in the Emergency Action Level Matrix. The following liquid effluent radiation monitors were identified: 0RIX-PR040 C Liquid Radwaste Discharge Process Radiation Monitor (currently not an active discharge pathway) 1RIX-PR036 C Plant Service Water Effluent Process Radiation Monitor 1RIX-PR037 C Component Cooling Water Process Radiation Monitor 1RIX-PR038 C Division 1 Shutdown Service Water Effluent Process Radiation Monitor 1RIX-PR039 C Division 2 Shutdown Service Water Effluent Process Radiation Monitor 1RIX-PR004 C Train A Fuel Pool Heat Exchanger Service Water Radiation Monitor 1RIX-PR005 C Train B Fuel Pool Heat Exchanger Service Water Radiation Monitor The licensee wrote AR 00854497 to address questions raised by the inspectors regarding scoping of these liquid effluent process radiation monitors within its Maintenance Rule Monitoring Program. This issue is considered to be an Unresolved Item (URI 05000461/2008005-02) pending additional review
05000461/FIN-2008201-01	Security	2008Q4
05000461/FIN-2008201-02	Security	2008Q4
05000461/FIN-2008201-03	Security	2008Q4
05000461/FIN-2008403-01	Security	2008Q4	The attached report documents a finding that has the potential for significance of greater than very low security significance (i.e., greater than Green as determined by the Physical Protection Significance Determination Process). The final resolution of this finding will convey the increment in the importance to safety by assigning the corresponding color. The deficiencies were promptly corrected or compensated for, and the plant was in compliance with applicable physical protection and security requirements within the scope of this inspection before the inspectors left the site. The finding had a cross-cutting aspect in the area of Human Performance, Resources, (H.2(c)) because the licensee failed to maintain complete, accurate, and up-to-date procedures.
05000461/FIN-2009003-01	Failure to Evaluate Safety Function of Suppression Pool Makeup System	2009Q2	The inspectors identified a finding of very low safety significance associated with the licensees failure to recognize a potential loss of safety function for the suppression pool makeup system following the loss of upper containment pool inventory when spent fuel pool cooling system flow control valve 1FC004A failed closed. No evaluation was performed to ensure that the suppression pool makeup systems safety function would be fulfilled with less than Technical Specification (TS) minimum containment upper pool level. The licensee subsequently performed an evaluation and determined that sufficient margin existed such that the system would have been able to fulfill its safety function with limited margin. Corrective actions to address the inadequate reportability review included training for licensed senior reactor operators and development of a formal operability/reportability review process template. No violation of regulatory requirements was identified. The finding would become a more significant safety concern if left uncorrected and was therefore, more than a minor concern. Specifically, the failure to correctly recognize and evaluate a potential loss of a safety function of systems, structures, and components when performing operability or past operability evaluations could reasonably result in an unrecognized condition of a system failing to fulfill its safety-related function. Because the suppression pool makeup system was primarily associated with long-term decay heat removal following certain design basis accidents, the inspectors concluded that this issue was associated with the Mitigating Systems Cornerstone. The finding was of very low safety significance because the issue: (1) was not a design or qualification deficiency; (2) did not represent an actual loss of safety function of a system; (3) did not represent an actual loss of safety function of a single train for greater than its TS allowed outage time; (4) did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk significant; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors concluded that this finding affected the cross-cutting area of human performance because the licensee did not have a formal process in place with adequate guidance and training to enable licensed senior reactor operators, whose responsibility it was to evaluate a potential loss of safety function, to correctly do so. As a result, senior reactor operators did not adequately review the TS Bases to understand and evaluate whether the system was able to fulfill its safety function. (IMC 0305 H.1(a)
05000461/FIN-2009003-02	Review of Excess Flow Check Valve Operability Evaluation In Lieu of Testing	2009Q2	The licensee identified that nine excess flow check valves were incorrectly removed from its Inservice Testing Program in 2002. The valves have a safety function to re-open following a design basis accident to provide instrumentation assumed to be available post-accident. The valves have not been tested since the licensees refueling outage in 2000. This issue is discussed in greater detail in Section 4OA2.3.b.(2) of this inspection report. The inspectors reviewed the licensees operability evaluation for the excess flow check valves and have discussed the evaluation with the licensees staff. At the end of this inspection period, open questions remained with the operability evaluation. This issue is considered to be an Unresolved Item (URI 05000461/2009003-02) pending additional review and resolution of open questions
05000461/FIN-2009003-03	Failure to Perform Surveillance Testing on the Division 3 Shutdown Service Water Pump With Adequate Measuring and Test Equipment	2009Q2	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria XII, Control of Measuring and Test Equipment, and 10 CFR 50, Appendix B, Criteria XI, Test Control. The licensee failed to perform surveillance testing on the Division 3 shutdown service water pump with a lake level gage that was properly controlled and adjusted to ensure that it was readable within the range it was used. The licensee subsequently replaced the unreadable lake level gage section with one that was readable and implemented additional corrective actions to address a lapse in operations standards. The inspectors concluded that this finding would become a more significant safety concern if left uncorrected and it was therefore more than a minor concern. Specifically, the failure to perform surveillance testing with properly controlled and accurate measuring and test equipment could reasonably result in the failure to identify degraded or inoperable safety-related components. Because the shutdown service water system was primarily associated with long term decay heat removal following certain design basis accidents, the inspectors concluded that this issue was associated with the Mitigating Systems Cornerstone. The finding was of very low safety significance because the issue was a design or qualification deficiency confirmed not to result in loss of operability or availability. The inspectors concluded that this finding affected the cross-cutting area of problem identification and resolution because the licensee was not properly maintaining the lake level gage to ensure that it would remain usable and did not correct the degraded condition in a timely manner after it was identified. As a result, operators accepted the degraded level gage for continued use. (IMC 0305 P.1(d)
05000461/FIN-2009003-04	Review of Applicability of TSSR 3.0.3 to Mulitple Missed Surveillance Intervals for Excess Flow Check Valves	2009Q2	The inspectors noted that the licensee utilized the relief afforded by TSSR 3.0.3 for a missed surveillance to allow up to the limit of the specified frequency to perform missed surveillances and questioned whether doing so was appropriate for testing that had been discontinued many years before and therefore not performed for multiple test frequency periods. This issue is considered an Unresolved Item pending additional review by the NRC staff. The licensee identified that nine excess flow check valves were incorrectly removed from its Inservice Testing Program in 2002. The valves have a safety function to re-open following a design basis accident to provide instrumentation assumed to be available post accident. The ASME/ANSI Operations and Maintenance Code (OMa 1988, Part 10) would require a position verification test for these valves once every two years and an opening test once every three months, with exceptions allowed for refueling cycle frequency. The valves have not been tested since 2000. The licensee discovered this problem during its extent of condition review of another inservice testing issue. Previously, the licensee had identified that multiple spent fuel pool cooling system components (i.e., pumps and valves) were also incorrectly removed from its Inservice Testing Program in 2002. The licensee subsequently reestablished the appropriate inservice testing frequency for the spent fuel pool cooling system components and has completed the required testing. The licensees extent of condition review identified additional examples where plant components were incorrectly removed from its Inservice Testing Program, or where the applicable testing requirements were not correctly implemented in 2002. These examples included nine excess flow check valves (1CM002A, 1CM002B, 1CM003A, 1E22-F330, 1E22-F332, 1E51-F377A, 1E51-F377B, 1SM008 and 1SM009), the Division 3 shutdown service water pump discharge check valve (1SX001C), and the diesel fuel oil transfer pump discharge relief valves (1DO005A, 1DO005B, and 1DO005C). Upon discovery of the above testing issues, the licensee utilized the relief afforded by TSSR 3.0.3 for a missed surveillance to allow up to the limit of the specified frequency to perform missed surveillances. During review of the excess flow check valve testing issue, the inspectors questioned the licensee whether it was appropriate to utilize the relief allowed by TSSR 3.0.3 because these did not appear to be cases of a single missed surveillance. Recently, the NRC staff concluded in Task Interface Agreement (TIA) 2008-004, Evaluation of Application of Technical Specification (TS) 4.0.3, Surveillance Requirement Applicability, at Pilgrim; that a missed surveillance (i.e., inadvertently exceeded surveillance) is not equivalent to a never-performed surveillance for which TSSR 3.0.3 would not apply. The basis for the relief allowed by TSSR 3.0.3 is that the past surveillance testing history provides a level of confidence that the component or system is most likely operable. A surveillance that has never been performed does not have this basis for a presumption of operability. The NRC staff is currently working with the industry-sponsored Technical Specifications Task Force to develop a framework for the treatment of surveillances that have never been performed. Consistent with the level of confidence argument that was provided in TIA 2008-004, the inspectors questioned whether it would be correct for the licensee to apply TSSR 3.0.3 for the excess flow check valves. After all, the licensee removed the valves from its Inservice Testing Program and discontinued testing, now exceeding four previously defined test frequency periods without testing the valves. Therefore, the basis for a presumption of operability may not exist because the licensee was not demonstrating operability by performing the required testing of the excess flow check valves all along. An Unresolved Item (URI 05000461/2009003-04) will track the NRC staffs review of this issue to determine if additional NRC guidance is necessary to specify whether TSSR 3.0.3 applies in the case where more than one surveillance interval is exceeded. The licensee successfully completed testing one of the check valves that could be tested with the unit on line, has completed a risk evaluation, and has scheduled the performance of the other eight missed surveillance tests in the next refueling outage. The licensee has concluded that testing of the remaining eight valves would require cold shutdown conditions. The inspectors used the level of confidence argument provided in TIA 2008-004 as the basis to question the operability of the valves. Subsequently, the licensee revised the calculation defining the design basis function for the excess flow check valves to remove the active safety function of five of the check valves. Of the remaining four check valves that have an active safety function (1CM002B, 1E22-F332, 1E51-F377B, and 1SM008), one check valve (1E22-F332) was tested satisfactorily. In response to the inspectors questions, the licensee then performed an operability evaluation for the remaining three check valves. The inspectors review of this operability evaluation and resolution of questions was pending at the completion of this inspection period. An additional URI will track the NRC staffs review of the excess flow check valve operability evaluation as discussed in Section 1R15.b.(2) of this report
05000461/FIN-2009003-05	Licensee-Identified Violation	2009Q2	10 CFR 20.2001, (a)(1) requires that a licensee dispose of licensed material only by transfer to an authorized recipient as provided in 10 CFR 20.2006. Contrary to the above, on September 30, 2005, the licensee made a shipment of phase separator resin (Shipment Number W05-023), totaling 614 curies to a waste processor who was not authorized by Agreement State license to receive more than 400 curies. Specifically, the licensees authorized shipper failed to completely read the receivers license limitations during the process of preparing the shipment, and the processor personnel did not identify the error when confirming that they were ready to receive the shipment. The recipient was authorized to receive radioactive material in this form and had an occupational safety program in place to protect personnel. This was identified in the licensees corrective action program (AR 567081). The finding was determined to be of very low safety significance (Green) because it did not involve radioactive material control, effluent release, environmental monitoring, transportation, or Part 61
05000461/FIN-2009003-06	Licensee-Identified Violation	2009Q2	10 CFR 50.9 requires, in part, that information required by the Commission to be maintained by a licensee shall be complete and accurate in all material respects. 10 CFR 20.2108 requires, in part, that each licensee maintain records of disposal of licensed material made under 10 CFR 61 until the Commission terminates the license. Contrary to the above, on October 5, 2005, information required by the Commission to be maintained by the licensee was not accurate in all material respects. Specifically, the completed copy of NRC Form 540 for Shipment Number W05-023 on September 30, 2005, was not accurate, in that, the shipment quantity was modified and the form was deliberately backdated to the original date of shipment (September 30, 2005). The licensee used the NRC Form 540 to meet the requirements of 10 CFR 20.2108. Based on an Office of Investigations investigation (OI Case No. 3-2007-026), the NRC staff concluded that the authorized shippers backdating of NRC Form 540 was a deliberate violation. However, because the violation had limited actual radiological significance and low potential significance, the violation involved the acts of a low-level individual resulting from an isolated action without management involvement, there was no economic or other advantage gained as a result of the violation, and adequate remedial action was taken, the violation was categorized at Severity Level IV. Because the violation is of very low safety significance, it meets the additional criteria in Section VI.A.1 of the NRC Enforcement Policy and because it has been entered into the corrective action system (AR 567081) it is being treated, after consultation with the Director, Office of Enforcement, as a Non-Cited Violation
05000461/FIN-2009003-07	Licensee-Identified Violation	2009Q2	10 CFR 50.55a, Paragraph (f)(4)(ii) requires, in part, Inservice tests to verify operational readiness of pumps and valves, whose function is required for safety . . . must comply with the requirements of the latest edition and addenda of the Code incorporated by reference in paragraph (b) of this section. . . . 10 CFR 50.55a, Paragraph (f)(5)(iii) requires, in part, If the licensee has determined that conformance with certain code requirements is impractical for its facility, the licensee shall notify the Commission and submit . . . information to support the determination. 10 CFR 50.55a, Paragraph (f)(6)(i) requires, in part, The Commission will evaluate determinations under paragraph (f)(5) of this section that code requirements are impractical. The Commission may grant relief and may impose alternative requirements as it determines is authorized by law . . . . Contrary to the above, the licensee failed to fully implement the Commission granted relief and alternative requirements contained in Relief Request 4212, Revision 1, during the Cycle 11 refueling outage. Specifically, the licensee failed to perform a pressure decay test on the instrument air lines and accumulators supplying both feedwater containment outboard isolation check valves (1B21-F032A and 1B21-F032B) each refueling outage in lieu of the VT-2 visual examination required by the ASME Code, Section XI, Paragraphs IWC-2500 and IWD-2500. The licensee entered this violation into its CAP as AR 00766213. The finding was determined to be of very low safety significance (Green) because the finding was a design or qualification deficiency confirmed not to result in loss of operability or availability
05000461/FIN-2009004-01	Interconnecting Floor Drains Between the Residual Heat Removal A Pump Room and Radwaste Pipe Tunnel	2009Q3	The inspectors identified that floor drains in the RHR A Pump Room and the Radwaste Pipe Tunnel were apparently interconnected, which would potentially result in an unanalyzed condition. This issue is considered to be an Unresolved Item pending additional review by the licensee and the inspectors. During review of plant drawings for floor drain system piping in the Emergency Core Cooling System (ECCS) and Reactor Core Isolation Cooling Pump Rooms on the 7070 elevation of the Auxiliary Building, the inspectors identified that floor drains in the RHR A Pump Room appeared to be connected via permanent 4 pipe embedded in the floor to floor drains in the Radwaste Pipe Tunnel, which is located along the western wall of the (adjacent) Control Building at the 7200 elevation. The inspectors noted that each of the separate pump rooms was supposedly designed to be isolated from other areas of the plant and not susceptible to flooding from sources external to the pump rooms. The inspectors discussed this floor drain configuration with the licensee and questioned the adequacy of the design with respect to the potential for flooding. First, if the Radwaste Pipe Tunnel were to flood, would the floodwater in the Tunnel communicate with and cause flooding in the RHR A Pump Room? This could potentially affect operability of the RHR A pump. Second, if the RHR A Pump Room were to flood because of a postulated pump suction line break, would the suppression pool flood water escape the RHR A Pump Room and flow into the radwaste system via the Radwaste Pipe Tunnel? The inspectors noted that Section 3.8.4.1.1 of the UFSAR stated that the ECCS Pump Rooms are in flood protection compartments with watertight doors. In the event of a pipe rupture, the flooding in one compartment will not result in the flooding of any other compartment, and the failure of a pump suction line will not drain the suppression pool. Section D3.6.4 of the UFSAR stated that a postulated failure of any of the non-isolable portions of the ECCS pump suction lines to the suppression pool could result in flooding of a single ECCS cubicle to the high water level in the suppression pool (7315 elevation). If the floor drain piping exists as described by plant drawings and flooding in the RHR A Pump Room (from the suppression pool) were to occur, then the potential exists that cross-flooding could occur between the RHR A Pump Room and the Radwaste Pipe Tunnel. Flooding could potentially continue until the suppression pool level was below the Control Building floor drain level (7206 elevation). This would be below the suppression pool high water level assumed in Section D3.6.4. At the end of the inspection period, the licensee had just begun investigating the inspectors questions and evaluating the condition. Inspection of the Radwaste Pipe Tunnel found that the floor drains in question were not plugged. No logbook entries were found in the Floor Drain Plug Log to indicate that the drains had been plugged at anytime in the past. The vertical piping which connects the floor drains from the Radwaste Pipe Tunnel to the RHR A Pump Room travels through the Low Pressure Core Spray Pump Room. This pipe was located as mapped on drawing A26-1000-03A at plant coordinates V-124 and the pipe was intact. No historical design change documents were posted against the plant drawings to indicate that the configuration was altered from the original plant design. Original engineering calculation (3C10-0485-001) and the 1990 Flood Analysis did not specifically discuss the potential for flood water entering (or leaving) the RHR A Pump Room via this drain line, although a statement was included which identified that flood water flow through 4 floor drain lines could be estimated at 100 gallons-per-minute (0.22 cubic feet-per-second). During review, the licensee also discovered that a similar arrangement existed with floor drains on the west side of the Auxiliary Building in that the RHR C Pump Room floor drain piping communicates with the floor drains in the Auxiliary Building Floor Drain Tank Room and Pump Room. Those rooms are located south of the RHR C Pump Room on the other side of the watertight door, at the 7120 elevation. To address the potential immediate operability concern, the licensee plugged the two floor drains in the Radwaste Pipe Tunnel to prevent communication with the floor drain system in the RHR A Pump Room per an engineering design change. This issue is considered to be an Unresolved Item (URI 05000461/2009004-01) pending additional review and resolution of open questions
05000461/FIN-2009004-02	Ineffective Corrective Actions for Vibration Induced Stem/Disc Separation of Fuel Pool Cooling System Train A Flow Control Valve 1FC004A	2009Q3	A finding of very low safety significance was self-revealed on May 27, 2009, when fuel pool cooling system flow control valve 1FC004A failed closed. The licensee failed to implement effective corrective actions in response to the same failure mode for the valve that occurred on November 21, 2005. This resulted in the failure of 1FC004A once again and the subsequent loss of inventory from the containment upper pool and inoperability of the suppression pool makeup system. The licensee entered this issue into its corrective action program (CAP) to investigate the cause and to identify appropriate corrective actions. No violation of regulatory requirements was identified. The finding was of more than minor significance because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and directly affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the May 2009 valve failure resulted in a loss of inventory from the containment upper pool and inoperability of the suppression pool makeup system, therefore impacting its availability for certain initiating events. The finding was of very low safety significance because the issue: (1) was not a design or qualification deficiency; (2) did not represent an actual loss of safety function of a system; (3) did not represent an actual loss of safety function of a single train for greater than its Technical Specification (TS) allowed outage time; (4) did not represent an actual loss of safety function of one or more non-TS trains of equipment designated as risk significant; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors did not identify a cross-cutting area component related to this finding
05000461/FIN-2009004-03	Failure to Update the Final Safety Analysis Report	2009Q3	The inspectors identified a Non-Cited Violation of 10 CFR 50.71, Maintenance of Records, Making of Reports, associated with the licensees failure to correctly update the Updated Final Safety Analysis Report (UFSAR) when modifying TS requirements for the Control Room ventilation system during implementation of Improved Standard Technical Specifications. Specifically, the licensee failed to change the specified safety function description for the system to maintain positive pressure within the Control Room envelope with respect to adjacent areas during all operating modes, except when the system is in the recirculation mode or when the system is in the maximum outside air purge mode. This directly contributed to the licensees failure to correctly evaluate the operability of Control Room ventilation system Train B when the system was unable to maintain the Control Room envelope at a positive pressure relative to adjacent areas while operating in the normal mode. Subsequent evaluation by the inspectors determined that the safety function description in the UFSAR was inaccurate and the system was operable with the degraded/ nonconforming condition. The licensee entered this violation into its CAP to investigate the cause and to identify appropriate corrective actions. Because the issue affected the NRCs ability to perform its regulatory function, the violation was reviewed under the traditional enforcement process. In addition, the underlying technical issue was evaluated using the Significance Determination Process. The finding was determined to be a Severity Level IV violation because it was similar to a Severity Level IV violation example in the NRC Enforcement Policy, Supplement I--Reactor Operations. The finding would become a more significant safety concern if left uncorrected and was therefore more than a minor concern. Specifically, the failure to correctly evaluate a degraded/nonconforming condition potentially affecting the operability of a system, structure, or component (SSC) required to be operable by TS could reasonably result in an unrecognized condition of an SSC failing to fulfill a safety-related function. Because the Control Room ventilation system supports the radiological barrier function to protect operators inside the Control Room following certain design basis accidents, the inspectors concluded that this issue was associated with the Barrier Integrity Cornerstone. The finding was of very low safety significance because it involved only a degradation of the radiological barrier function provided for the Control Room. The inspectors did not identify a cross-cutting aspect related to this finding
05000461/FIN-2009004-04	RPV Head Strongback, Dryer/Separator Strongback and RPV Head Lifting Lugs Did Not Demonstrate Single Failure Proof Requirements of NUREG 0612, Control of Heavy Loads at Nuclear Power Plants, Section 5.1.6	2009Q3	The inspectors identified an Unresolved Item concerning whether the design of the RPV head strongback, dryer/separator strongback and RPV head lifting lugs was in conformance with the licensing and design basis for single failure proof requirements of NUREG 0612, Section 5.1.6. Specifically, the RPV head strongback, dryer/separator strongback and RPV head lifting lugs did not meet design factors of safety versus yield and ultimate strengths consistent with the guidelines of NUREG 0612, Section 5.1.6. The inspectors reviewed the following licensee submittals: 1. Illinois Power Letter U-0249 L30-81 (06-19)-L to NRC, Subject: December 22, 1980, letter on Control of Heavy Loads, June 22, 1981; 2. Illinois Power Letter U-0294 L30-81 (09-25)-L to NRC, Subject: Clinton Power Station Units 1 and 2 Docket Nos. 50-461 and 50-462, September 25, 1981; 23 Enclosure 3. Illinois Power Letter U-06850982-L L30-83 (12-21)-L to NRC, Subject: Clinton Power Station Unit 1 Control of Heavy Loads (NUREG-0612), December 21, 1983; and 4. Illinois Power Letter U-0800 L30-85(02-21)-6 B48-85(02-21)-6 1A.120 to NRC, Subject: Clinton Power Station Unit 1 Control of Heavy Loads (NUREG-0612), February 21, 1985. As a result of this review, the inspectors identified several assurances from the licensee that the RPV head strongback, dryer/separator strongback and RPV head lifting lugs were in conformance with the single failure proof requirements of NUREG 0612, Section 5.1.6. The letter dated June 22, 1981, identified the RPV head strongback and dryer/separator strongback as carrying heavy loads such as the RPV head, drywell head, steam dryer and steam separator over safety-related equipment. The licensee had evaluated the hazard of either of the RPV head strongback or dryer separator being dropped as a heavy load over safe shutdown equipment and determined the likelihood of handling system failure for this load is extremely small (i.e., Section 5.1.6 NUREG 0612 satisfied). The letter dated September 25, 1981, responded to an NRC request to provide an evaluation of the lifting devices for each single-failure-proof handling system with respect to the guidelines of NUREG 0612, Section 5.1.6. The licensees response was that the two lifting devices are currently anticipated to be used to accomplish lifts with the polar crane over the refueling floor. Both are supplied by General Electric. They are the steam separator/dryer strongback and the RPV head carousel strongback. Each strongback is provided with four lift points to the load. General Electric states that two of the four attachments are capable of supporting the load. A single failure is considered as the loss of one lift point only. The strongbacks are attached to the polar crane redundant sister hook through the use of a hook box on top of the strongbacks and through two six-inch-diameter link pins. General Electric terms the strongbacks single-failure proof. The letter dated September 25, 1981, responded to an NRC request to provide an evaluation of the interfacing lift points with respect to the guidelines of NUREG 0612, Section 5.1.6. The licensees response was that the four lifting lugs are used on the RPV head. After failing two lugs, each of the remaining two lugs would have to support 63,100 pounds. These two remaining lugs are assumed to be opposed on the head so that the head would remain level. Based on a tensile strength of 80,000 psi and a cross-sectional analysis on the lug only 18 inches squared, the remaining two lugs in cross-section have a design margin of approximately 22. The cross-sectional area above also applies to the steam separator and the steam dryer lugs. The letter dated December 21, 1983, responded to an NRC request, which stated that the dryer/separator strongbacks load test does not meet the formal requirements of a 150 percent test. The 125 percent load test may be acceptable, however, more information should be provided. Basically, if the device is Single-Failure-Proof, a description of the device and the meaning of the load test is needed. If the device isnt Single-Failure-Proof, the device description should be accompanied by a discussion of potential load drop consequences. The licensees response was that the strongback will be upgraded to a factor of safety of ten in compliance with Section 5.1.6(1a), Single Failure Proof Handling Systems, of NUREG-0612. The letter dated February 21, 1985, responded to an NRC request to confirm the actual number of special lifting devices. Verify that each meets American National Standards Institute (ANSI) N14.6-1978 and all are designed for static plus maximum dynamic loads. The licensees response was two special lifting devices will be used at Clinton, the RPV head strongback and the RPV dryer/separator strongback, both of which have been designed and supplied by General Electric to accomplish their intended reactor vessel servicing and refueling functions. Both strongbacks are designed to be single failure proof and should adequately comply with NUREG 0612, Paragraph 5.1.1(4). The inspectors were concerned that the RPV head strongback, dryer/separator strongback and RPV head lifting lugs did not meet design factors of safety versus yield and ultimate strengths consistent with the guidelines of NUREG 0612, Section 5.1.6. In order to meet the intent of NUREG 0612, Section 5.1.6, the following design factors were satisfied: (a) Provide redundancy or duality such that a single lift point failure will not result in uncontrolled lowering of the load; lift points should have a design safety factor with respect to ultimate strength of five times the maximum combined concurrent static and dynamic load after taking the single lift point failure. Additionally, the device should have a design safety factor with respect to yield strength of three after taking the single lift point failure; or (b) a non-redundant or non-dual lift point system should have a design safety factor of ten times the maximum combined concurrent static and dynamic load. Additionally, the device should have a design safety factor with respect to yield strength of six. If the design factors were not satisfied, these guidelines require that entire heavy load path be analyzed for a heavy load drop and the results show that dropping a heavy load such as the RPV head, drywell head, steam dryer and steam separator did not create an unacceptable risk. The intent was to ensure safe handling of heavy loads in areas where a load drop could impact fuel in the reactor core, or equipment that may be required to achieve safe shutdown or permit continued decay heat removal. In response to the concern, the licensee initiated AR 00938280 on July 2, 2009. This issue is considered an Unresolved Item (URI 05000461/2009004-04) pending additional inspector discussion with the Office of Nuclear Reactor Regulation staff to determine licensing basis requirements for Clinton Power Station, specifically whether these lifting devices needed to meet NUREG 0612 Section 5.1.6
05000461/FIN-2009004-05	Failure the Adequately Implement Requirements of the Leakage Reduction and Monitoring Program	2009Q3	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, regarding the licensees failure to adequately implement periodic visual inspection requirements per procedure CPS 1019.07, Leakage Reduction and Monitoring Program, to monitor and minimize leakage from piping systems connecting to the reactor coolant system. The inspectors also identified that the procedure itself was inappropriate to the circumstances because it did not provide for adequate and consistent performance of the piping system visual inspections and did not provide for sufficient objective quality evidence to demonstrate that the program requirements were met. The licensee entered this violation into its CAP to investigate the cause and to identify appropriate corrective actions. The finding would become a more significant safety concern if left uncorrected and was therefore more than a minor concern. Specifically, the failure to adequately implement required leakage reduction and monitoring program controls to minimize leakage from reactor coolant sources outside of containment that could contain highly radioactive fluids during a serious transient or accident could reasonably result in higher doses to plant workers and higher potential offsite release levels. Because the leakage reduction and monitoring program is intended to contain highly radioactive fluids within piping systems outside containment, which supports the radiological barrier functions to protect plant workers and the public following serious transients or accidents, the inspectors concluded that this issue was associated with the Barrier Integrity Cornerstone. The finding was of very low safety significance because it involved only a degradation of the radiological barrier function provided for the Auxiliary Building. The inspectors concluded that this finding affected the cross-cutting area of human performance because the licensee did not provide adequate procedural guidance and training to enable operators to correctly perform and document piping system visual inspections to implement its leakage reduction and monitoring program. As a result, the licensee did not have appropriate objective quality evidence to demonstrate that the program requirements were met. (IMC 0305 H.2(c)
05000461/FIN-2009004-06	Licensee-Identified Violation	2009Q3	10 CFR 50.55a, Paragraph (f)(4)(ii) requires, in part, Inservice tests to verify operational readiness of pumps and valves, whose function is required for safety . . . must comply with the requirements of the latest edition and addenda of the Code incorporated by reference in paragraph (b) of this section. . . . The applicable Code for the current Clinton Power Station Inservice Test Program interval for testing valves is the 1989 Edition of American Society of Mechanical Engineers (ASME) Section XI, Subsection IWV, Inservice Testing of Valves in Nuclear Power Plants, which references the ASME/ANSI Operations and Maintenance Code (OMa 1988, Part 10). OMa 1988, Part 10, Paragraph 4.1 requires, in part, that valves with remote position indicators shall be observed locally at least once every 2 years to verify that the valve operation is accurately indicated. In addition, OMa 1988, Part 10, Paragraph 4.3.2.2 requires, in part, that each check valve shall be exercised or examined in a manner which verifies obturator travel to the closed, full-open or partially open position required to fulfill its function. Contrary to the above, the licensee incorrectly removed nine excess flow check valves (1CM002A, 1CM002B, 1CM003A, 1E22-F330, 1E22-F332, 1E51-F377A, 1E51-F377B, 1SM008 and 1SM009) from its Inservice Testing Program in 2002 and subsequently failed to perform testing required by the Code. The licensee entered this violation into its CAP as AR 00846540. The finding was determined to be of very low safety significance (Green) because the finding was a design or qualification deficiency determined not to result in loss of operability or availability
05000461/FIN-2009005-01	Failure to Control Transient Combustible Materials in Accordance with Fire Protection Program	2009Q4	The inspectors identified that the licensee failed to implement its Fire Protection Program in accordance with program requirements by failing to follow approved Fire Protection Program procedures for the control of transient combustible materials. This issue is considered to be an Unresolved Item pending additional review by the inspectors to determine whether the performance deficiency is of more than minor safety significance. On September 29, 2009, with Unit 1 operating in Mode 1, the inspectors identified unattended transient combustible items (a plastic container with about one quart of Mobil DTE 26 motor oil, a plastic container with about one pint of Syn-Air lubricating oil, an empty collapsible plastic container, a plastic bottle half-filled with what appeared to be a soap-bubble and water solution used for leak detection on pipe fittings, two paper towels, and other assorted small debris items) underneath two air receiver tanks in the Division 1 Diesel Generator Ventilation Fan Room on the Diesel Generator Building 762 elevation. The area in which these transient combustible items were found contained highly visible red striped paint on the floor and markings indicating the area to be a Combustible Free Zone as described in the Clinton Power Station Fire Protection Evaluation Report (Updated Final Safety Analysis Report (UFSAR), Appendix E) or; alternatively, a Transient Combustible Free Zone (TCFZ) as described in OP-AA-201-009, Control of Transient Combustible Material, Attachment 5, Clinton Station Specific Information, Revision 9. As stipulated in Attachment 5 of OP-AA-201-009, the placement of transient combustible materials in these areas without prior approval in the form of a Transient Combustible Permit and Plant Barrier Impairment and additional compensatory measures is prohibited in Modes 1, 2, and 3. Neither a Transient Combustible Permit nor a Plant Barrier Impairment was approved for these transient combustible items and no compensatory measures had been established. The procedure further stated that the TCFZs at Clinton Power Station are provided for the purpose of separating redundant safe shutdown equipment. According to the Fire Protection Evaluation Report, redundant safe shutdown equipment of concern for the Division 1 Diesel Generator Ventilation Fan Room included equipment to support operation of the Division 1 DG and main power feed cables for the Division 2 DG. Consequently, a fire in the room could result in the loss of power from both the Division 1 and Division 2 DGs. Upon discovery, the inspectors promptly notified the licensee and the items were removed. The items discovered were determined to be Class A and Class B materials as defined in OP-AA-201-009. It is unknown when these items were placed underneath the air receivers. The inspectors reviewed the licensees condition evaluation of this issue. The licensee concluded that the items had likely been under the air receiver tanks for several years based on the layer of dust covering them, but not until sometime after mid-2001 based on the style of the labels found on the containers. The licensee attributed the cause to the difficulty in finding the items without extra effort to look into areas not normally used for storage of materials. The inspectors previously documented findings during the fourth quarter of 2007, first quarter of 2008, and fourth quarter of 2008 involving the licensees failure to follow approved Fire Protection Program procedures for the control of transient combustible materials. Those findings were attributed to poor worker behaviors with storing or staging work materials in TCFZs and inadequate walk downs of the plants TCFZs. The licensee noted in its evaluation that corrective actions for these findings included several walk downs of the plants TCFZs to identify and remove materials as an extent of condition investigation; however, these walk downs were not sufficient to identify and remove all transient combustible materials since items were found after each walk down. The inspectors noted that the unattended transient combustible items were readily visible by dropping to one knee and looking under the air receiver tanks with a flashlight. The licensees immediate corrective action for this issue was to remove the combustible items from the TCFZ. The licensee has subsequently changed its UFSAR and plant procedures to allow some negligible quantities of combustible materials inadvertently or accidently left within the TCFZs based upon an engineering evaluation. The inspectors have requested assistance from a regional fire protection specialist to review the licensees engineering evaluation and UFSAR changes. This issue is considered to be an Unresolved Item (URI 05000461/2009005-01) pending additional review to determine whether the performance deficiency is of more than minor safety significance. The licensee entered this issue into its corrective action program as Action Request (AR) 00972704
05000461/FIN-2009005-02	Standby Gas Treatment System Flow/Heater Operability Surveillance Test	2009Q4	The inspectors identified that the licensees monthly surveillance test procedure for demonstrating operability of the SGT system may not include appropriate quantitative or qualitative acceptance criteria for determining that the system was capable of performing its specified safety function. This issue is considered to be an Unresolved Item pending additional review by the inspectors to determine whether the surveillance test procedure was adequate to satisfy the surveillance testing requirement. The inspectors reviewed the licensees performance of surveillance testing that was accomplished in accordance with procedure CPS 9067.01, Standby Gas Treatment System Flow/Heater Operability, Revision 31a. This surveillance test procedure was performed to satisfy TS Surveillance Requirement (SR) 3.6.4.3.1, which required that each SGT subsystem (or train) be operated for Y 10 continuous hours with the heaters operating once every 31 days. As described in the UFSAR, the safety function of the SGT system is to minimize the offsite release of radioactive materials that leak from the primary containment into the secondary containment following a design basis accident to limit the offsite and control room dose to the guidelines of 10 CFR 50.67. According to the Bases for TS SR 3.6.4.3.1: Operating each SGT subsystem from the main control room for Y 10 hours ensures that both subsystems are operable and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on (automatic heater cycling to maintain temperature) for Y 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA (high efficiency particulate air) filters. During review of CPS 9067.01, the inspectors noted that the procedure did not have specific steps to ensure that flow blockage did not exist by verifying that each SGT subsystem provided sufficient air flow. The acceptance criteria specified in Step 9.1.1 of the procedure required only that the SGT train operates for Y 10 hours with flow through the train and the heater is operable. Although SGT subsystem inlet flow was recorded, there were no acceptance criteria in the procedure to evaluate whether each subsystem was capable of providing the minimum required air flow to meet its safety function. According to the UFSAR, the SGT system was designed with a flow control valve that maintains flow at 4000 cubic feet per minute (A 10%); however, there was no comparison of the recorded flow rates with the design flow rate to ensure that the fan and/or the flow control valve were operating properly or that there was no flow blockage. Although pre-filter and HEPA filter differential pressures were recorded, the acceptance criteria provided in Step 9.2.1 of CPS 9067.01 only established criteria for dirty filter replacements. The criteria were not used to evaluate whether each subsystem was capable of providing the minimum required air flow to meet its safety function. Although SGT subsystem inlet and outlet temperatures were recorded three times during the 10-hour run, there were no acceptance criteria in the procedure to evaluate whether the heater was capable of providing sufficient heat to eliminate moisture on the adsorbers and HEPA filters. There were also no specific steps in CPS 9067.01 to measure and evaluate fan and motor vibration levels or to locally assess the running subsystem for abnormalities. Local inspection of the subsystem during operation (e.g., checking rotating equipment for abnormal temperatures, odors, noise and/or vibration) would ensure that blockage, fan or motor failure, or excessive vibration could be detected for corrective action. The inspectors discussed these observations with the licensee and questioned whether simply verifying that the subsystem operates for Y 10 hours with the heater energized provided an adequate demonstration that each SGT subsystem was capable of performing its specified safety function to satisfy TS SR 3.6.4.3.1. This issue is considered to be an Unresolved Item (URI 05000461/2009005-02) pending additional review and resolution of open questions to determine whether the surveillanc
05000461/FIN-2009005-03	Failure to Correctly Torque Valve Packing Gland Nuts Resulted in Valve Packing Failure and Unplanned Plant Shutdown	2009Q4	A finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, was self-revealed on September 29, 2009, when a steam leak developed from the reactor core isolation cooling (RCIC) system inboard steam isolation valve (1E51F0063) stem packing. This resulted in a plant shutdown due to a greater than 2 gallons-per-minute increase in unidentified reactor coolant system (RCS) leakage within the previous 24 hours. Subsequent investigation revealed that maintenance craftsmen had failed to correctly tighten the valve packing gland nuts to the as-left torque value from original packing installation when performing scheduled maintenance to verify the as-found torque value in 2006. As corrective action, the licensee replaced the 1E51F0063 valve stem packing during the subsequent forced outage and tightened the gland nuts to the correct torque value. The finding was of more than minor significance because it was associated with the Equipment Performance 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 during shutdown as well as power operations. Specifically, the failure to correctly tighten the valve stem packing gland nuts resulted in stem packing failure and a subsequent plant shutdown due to exceeding the Technical Specification (TS) limit for an increase in unidentified RCS leakage. Although the finding resulted in exceeding the TS limit for RCS leakage, it was determined to be of very low safety significance during a Phase 2 Significance Determination Process review because there was no loss of mitigation capability for any safety system and therefore no resultant change in core damage frequency. Because the performance issue was associated with maintenance performed in February 2006, it did not necessarily reflect current licensee performance and no cross-cutting aspect was identified
05000461/FIN-2009005-04	Failure to Correctly Install Relays Inside of the Division 3 Diesel Generator Control Panel	2009Q4	A finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, was self-revealed on September 23, 2009, when the Division 3 diesel generator (DG) was found to have had two components installed incorrectly. Electrical maintenance technicians had incorrectly replaced time delay relays K-8A and K-32 on September 24, 2007, essentially swapping the locations of the two relays. This rendered the Division 3 DG inoperable for about two years and resulted in a loss of safety function for the Division 3 DG and high pressure core spray system under a certain sequence of initiating events. As immediate corrective action, the licensee restored the two time delay relays to the correct configuration and immediately verified that the remaining time delay relays inside the Division 3 DG Control Panel were in their proper locations. The finding was of more than minor significance because, if left uncorrected, it would potentially lead to a more significant safety concern (i.e., the inoperability of risk-significant plant safety systems). In addition, based on review of Example 5c in Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the issue would be considered to be of more than minor significance because the incorrect relays were installed in the control panel. Although the finding resulted in a loss of safety function for the Division 3 DG and high pressure core spray system, it was determined to be of very low safety significance during a Phase 2 Significance Determination Process review considering the very limited conditions (i.e., only for 45 seconds following shutdown of the engine concurrent with a design basis accident) when the Division 3 DG was incapable of performing its safety function. The resultant exposure time was estimated to be about 27 minutes during the 2-year period. The inspectors concluded that this finding affected the cross-cutting area of human performance because the licensee did not effectively communicate expectations regarding procedural compliance and; as a result, maintenance technicians did not follow their procedures by installing nonconforming components and restoring the safety system to service. (IMC 0305 H.4(b)
05000461/FIN-2009005-05	Changes to EAL HU6 Potentially Decrease the Effectiveness of the Plans without Prior NRC Approval	2009Q4	The inspectors reviewed changes implemented to the Clinton Station Radiological Emergency Plan Annex EALs and EAL Basis. In Revision 12, the licensee changed the basis of EAL HU6, Fire not extinguished within 15 minutes of detection within the protected area boundary by adding two statements. The two changes added to the EAL basis stated that if the alarm could not be verified by redundant control room or nearby fire panel indications, notification from the field that a fire exists starts the 15-minute classification and fire extinguishment clocks. The second change stated the 15-minute period to extinguish the fire does not start until either the fire alarm is verified to be valid by additional control room or nearby fire panel instrumentation, or upon notification of a fire from the field. These statements conflict with the previous Clinton Station Annex, Revision 11, basis statements and potentially decrease the effectiveness of the Plans. Clinton Station Radiological Emergency Plan Annex, Revision 11, EAL HU6 initiating condition stated, Fire not extinguished within 15 minutes of detection, or explosion, within the protected area boundary. The threshold values for HU6 were, in part: 1) Fire in any Table H2 area not extinguished within 15 minutes of Control Room notification or verification of a Control Room alarm, or 2) Fire outside any Table H2 area with the potential to damage safety systems in any Table H2 area not extinguished within 15 minutes of Control Room notification or verification of a Control Room alarm. Table H2, Vital Areas, were identified as containment, auxiliary building, fuel building, control building (excluding chemistry lab), diesel generator and HVAC building, and screenhouse. The basis defined fire as combustion characterized by heat and light. Sources of smoke such as slipping drive belts or overheated electrical equipment do not constitute fires. Observation of flame is preferred but is not required if large quantities of smoke and heat are observed. The basis for Revision 11, EAL HU6 thresholds 1 and 2 stated, in part, the purpose of this threshold is to address the magnitude and extent of fires that may be potentially significant precursors to damage to safety systems. As used here, notification is visual observation and report by plant personnel or sensor alarm indication. The 15-minute period begins with a credible notification that a fire is occurring or indication of a valid fire detection system alarm. A verified alarm is assumed to be an indication of a fire unless personnel dispatched to the scene disprove the alarm within the 15-minute period. The report, however, shall not be required to verify the alarm. The intent of the 15-minute period is to size the fire and discriminate against small fires that are readily extinguished (e.g., smoldering waste paper basket, etc.). Revision 12 of the Clinton Station Radiological Emergency Plan Annex, changed the threshold basis for EAL HU6 by adding the following two statements: 1) If the alarm cannot be verified by redundant control room or nearby fire panel indications, notification from the field that a fire exists starts the 15-minute classification and fire extinguishment clocks, and 2) The 15-minute period to extinguish the fire does not start until either the fire alarm is verified to be valid by utilization of additional control room or nearby fire panel instrumentation, or upon notification of a fire from the field. The two statements added to the basis in Revision 12 conflict with the Revision 11 threshold basis and initiating condition. The changed threshold basis in Revision 12 could add an indeterminate amount of time to declaring an actual emergency until a person responded to the area of the fire and made a notification to the control room of a fire in the event that redundant control room or nearby fire panel indications were not available. Pending further review and verification by the NRC to determine if the changes to EAL HU6 threshold basis potentially decreased the effectiveness of the Plans, this issue was considered an Unresolved Item (URI 05000461/2009005-05)
05000461/FIN-2009502-01	Implementation of a Change which Decreased the Effectiveness of the Emergency Plan	2009Q4	The inspectors identified a NCV of 10 CFR 50.54(q) associated with 10 CFR 50.47(b)(2) because the licensee failed to obtain prior NRC approval for a change made to its emergency plan that decreased the effectiveness of the plan. Specifically, the licensee removed staffing and capabilities from the minimum on-shift emergency response staffing requirements from the Clinton Power Station Emergency Plan Annex, Section 2, Table B-1. The licensee entered this issue into their corrective action program and replaced staffing back on-shift as required by the 1998 emergency plan annex. This finding was more than minor and of very low safety-significance using IMC 0609, Appendix B, because the finding was associated with the Emergency Preparedness Cornerstone attribute of emergency response organization readiness for minimum on-shift emergency response staffing. Because the finding affected the NRCs ability to perform its regulatory function, the inspectors evaluated the significance using the traditional enforcement process. This finding was determined to be a Severity Level IV violation because the licensee failed to meet an emergency planning requirement not directly related to assessment and notification. The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, decision making because the licensee did not initially recognize that the removal of minimum on-shift emergency response staffing decreased the effectiveness of the emergency plan (H.1.(b)).
05000461/FIN-2010002-01	Failure to Control Transient Combustible Materials in Accordance with Fire Protection Program	2010Q1	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of the Clinton Power Station Unit 1 Operating License (NPF-62, Section 2.F). The licensee failed to implement the Fire Protection Program in accordance with program requirements by failing to follow approved Fire Protection Program procedures for the control of transient combustible materials. The licensee promptly removed the transient combustible materials found by the inspectors. The inspectors concluded that this finding could be reasonably viewed as a precursor to a significant event (i.e., a fire affecting more than one train of safe shutdown equipment). Specifically, the presence of transient combustible materials in a combustible free zone could reasonably result in degradation of the fire protection defense-in-depth elements in place to prevent fires from starting and mitigate the consequences of fires. In addition, based on review of Example 4k in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the issue would not be considered to be of minor significance because the identified transient combustibles were found in a combustible free zone required for separation of redundant trains. The finding was of very low safety significance because the items found in the combustible free zone would not be considered transient combustibles of significance as defined in IMC 0609, Appendix F, Fire Protection Significance Determination Process, Attachment 2, Degradation Rating Guidance Specific to Various Fire Protection Program Elements, and, therefore, the issue was assigned a low degradation rating. The inspectors concluded that this finding affected the cross-cutting area of problem identification and resolution. Specifically, the licensee missed an opportunity to identify and remove the transient combustible materials while implementing corrective actions for previous inspector identified findings involving the control of transient combustible materials. (IMC 0305 P.1(a)
05000461/FIN-2010002-02	Failure to Control Combustible Gas Cylinders in Accordance with Fire Protection Program	2010Q1	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of the Clinton Power Station Unit 1 Operating License (NPF-62, Section 2.F). The licensee failed to implement the Fire Protection Program in accordance with program requirements by failing to follow approved Fire Protection Program procedures for the control of combustible gas cylinders in the plant. As a corrective action, the licensee promptly removed the combustible gas cylinders found by the inspectors. The inspectors concluded that this finding was associated with the Protection Against External Factors 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 during shutdown as well as power operations. Specifically, the fire hazard for the affected area was increased by the uncontrolled presence of the compressed gas cylinders. In addition, based on review of Example 4k in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the issue would not be considered to be of minor significance because a credible fire scenario involving the identified transient combustibles could affect equipment important to safety. The finding was determined to be of very low safety significance during a Phase 3 Significance Determination Process review since the delta core damage frequency was determined to be negligible. Because a postulated fire in the area where the combustible gas cylinders were found could affect only one train of safe shutdown equipment, the safe shutdown path was not affected by the finding. The inspectors concluded that this finding affected the cross-cutting area of human performance. Specifically, the licensee did not adequately ensure that supervisory and management oversight of work activities involving contractors supported nuclear safety. (IMC 0310 H.4(c)
05000461/FIN-2010002-03	Interconnecting Floor Drains Between the Residual Heat Removal A Pump Room and Radwaste Pipe Tunnel	2010Q1	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria III, Design Control, regarding the licensees failure to correctly translate the design basis into the design of the Auxiliary Building floor drain system with appropriate margin. The inspectors identified that floor drains in the Residual Heat Removal (RHR) A Pump Room and the Radwaste Pipe Tunnel were interconnected, which resulted in the plant being in an unanalyzed condition that degraded plant safety and could have prevented fulfillment of the safety function of the containment suppression pool. To address the immediate operability concern, the licensee plugged the two floor drains in the Radwaste Pipe Tunnel line to prevent communication with the floor drain system in the RHR A Pump Room. An exposed vertical section of the drain line was then cut and a solid steel plate welded into the pipe per an engineering design change to permanently isolate the floor drains between the two rooms. The finding was of more than minor significance because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the as-found configuration of the interconnecting floor drains resulted in the plant being in an unanalyzed condition that could have prevented fulfillment of the safety function of the containment suppression pool. Although the finding would represent a loss of safety function in the event of a postulated accident, it was determined to be of very low safety significance during a Phase 3 Significance Determination Process review because the delta core damage frequency was determined to be negligible since the initiating event frequency for flooding due to an RHR pump suction pipe failure was sufficiently low. Because this condition had existed since initial plant construction, the performance issue did not necessarily reflect current licensee performance and no cross-cutting aspect was identified
05000461/FIN-2010002-04	Failure to Recognize Examination Limitations for a Containment Penetration Weld	2010Q1	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow procedure instructions and record examination limitations for containment pipe-to-penetration weld 1-MS-B-11. The licensee subsequently documented the failure to record the 1-MS-B-11 limited weld examination in the corrective action program. The licensee planned to submit limited containment pipe-to-penetration weld examinations to the NRC for review and approval. The finding was of more than minor significance because, if left uncorrected, the failure to document limited weld examinations could become a more significant safety concern. Absent NRC identification, the licensee would not have submitted limited weld examinations to the NRC for approval. Further, the inspector could not determine if the NRC would approve the limited weld surface examinations without a licensee evaluation for the extent of additional coverage possible with volumetric weld examinations. This finding was of very low safety-significance based on answering no to each of the Phase 1 screening questions identified in the Containment Barrier column of Table 4a in Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings. Specifically, this finding did not represent an actual open pathway in the physical integrity of reactor containment. This finding has a cross-cutting aspect in the area of Human Performance, Resources because the licensee did not provide complete, accurate and up-to-date design documents (weld construction drawing) to the non-destructive examination staff. Specifically, the lack of a weld construction drawing, which included the weld profile, appeared to have contributed to the examination staffs failure to recognize that they had not completely examined the required weld surfaces. (IMC 0310 H.2(c)
05000461/FIN-2010002-05	Failure to Correct Inadequate FWLCS Response Resulted in High Reactor Vessel Water Level (Level 8) Scram	2010Q1	A finding of very low safety significance was self-revealed from an event that resulted in a Unit 1 reactor scram. The licensee failed to correct a non-conforming condition with inadequate response from the feedwater level control system (FWLCS) that caused an automatic reactor scram on February 10, 2008, following an unexpected loss of a reactor recirculation pump. This resulted in a second reactor scram for the same cause on October 15, 2009, following the unexpected loss of a reactor recirculation pump. Because the FWLCS is not safety-related, no violation of regulatory requirements was identified. The FWLCS response was corrected in January 2010 and proper system response was verified by the licensee upon start up from the January-February 2010 refueling outage. The finding was of more than minor significance because this issue was associated with the Equipment Performance attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, inadequate FWLCS response resulted in a reactor scram following the unexpected loss of a reactor recirculation pump. The finding was of very low safety significance because the issue: (1) did not contribute to the likelihood of a primary or secondary system loss-of-coolant-accident initiator, (2) did not contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions would not be available, and (3) did not increase the likelihood of a fire or internal/external flooding event. The inspectors did not identify a cross-cutting aspect related to this finding
05000461/FIN-2010002-06	Questions Regarding 10 CFR 50.59 Evaluation for CPS Procedure 3711.01 Involving Operations with the Potential to Drain the Reactor Vessel	2010Q1	The inspectors reviewed evaluation CL-2010-E-001, CPS Operations with the Potential to Drain the Reactor Vessel (OPDRV), Revision 0, for compliance with 10 CFR 50.59, Changes, Tests, and Experiments. The inspectors have questions remaining whether the implementation of the new procedure would create the possibility for an accident of a different type than any previously evaluated in the UFSAR. This issue is considered to be an Unresolved Item pending additional review by the inspectors. On January 11, 2010, the licensee approved CPS 3711.01, which established the definition of an OPDRV for use in determining the applicability of several TS requirements while in Modes 4 and 5. Prior to the procedure approval, an evaluation, CL-2010-E-001, was performed by the licensee to address the criteria of 10 CFR 50.59(c)(2). In its evaluation, the licensee concluded that none of the eight criteria were applicable under this requirement to obtain a license amendment pursuant to 10 CFR 50.90 prior to implementing the new procedure. Specifically, Criterion (v) which requires a license amendment prior to implementing a change that creates a possibility for an accident of a different type than any previously evaluated in the UFSAR was determined to not apply. Upon review of the implementation of CPS 3711.01, the inspectors identified a number of credible accident scenarios that were introduced by this procedure change and not previously evaluated in the UFSAR. The Clinton UFSAR analyzed a LOOP for only at-power conditions. This LOOP could also occur in Modes 4 and 5 at similar frequency and could have significance due to the implementation of the new procedure. Evolutions with non-isolable RCS leakage below 5 gpm, and up to 420 gpm with a single method of isolation were made procedurally acceptable and not to be considered an OPDRV by the licensee. Evolutions with RCS leakage up to these values could occur simultaneously with the inoperability of all ECCS and still remain in compliance with TS 3.5.2, which addresses the ECCS requirements for Modes 4 and 5. In addition, coincident with this scenario, neither primary nor secondary containment was required to be set according to TS 3.6.1.1 and 3.6.4.1, respectively. If a LOOP were to occur in this condition during refueling, it could possibly be of significance. No evaluation was performed by the licensee to determine how much time might be available for operators to respond prior to uncovering irradiated fuel in the upper containment pool for such a scenario. Rough estimations performed by the inspectors found the available time for operator response to be no more than six hours. In EC 376912, the licensee evaluated the time it would take to drain down to the reactor vessel flange with the new RCS leakage limits defined in CPS 3711.01 and found there to be greater than 17 hours for operators to respond. This evaluation did not consider the potential for uncovering irradiated fuel in the upper containment pool. The licensees evaluation accepted a non-controversial basis in the industry in defining an OPDRV. That definition specified that an open penetration that has the potential to uncover irradiated fuel is an OPDRV. Irradiated fuel would necessarily include any fuel that could be uncovered in the upper containment pool. Other credible scenarios introduced by the procedure change include the possible failure of administrative controls to preclude inadvertent withdrawal of a control rod that is being relied upon to isolate leakage for a removed control rod drive mechanism; or a fuel handling accident, which could result in a load movement disturbing the proper seating of such a control rod. The inspectors noted previous examples of failures of administrative controls similar to those relied upon in CPS 3711.01 to eliminate the potential for an accident. Notably during the recent refueling outage, on January 18, 2010, a location error occurred when the licensees refueling team discovered they had removed the incorrect control rod double blade guide. This incident occurred despite several procedural and human performance error prevention tools that were utilized. In addition, during the February 2008 refueling outage only a good questioning attitude by a contractor prevented removing safety relief valves prior to installing main steam line plugs and possibly resulting in the loss of RCS inventory. The inspectors requested assistance from regional specialists to review the licensees 10 CFR 50.59 evaluation and procedure change. This issue is considered to be an Unresolved Item (URI 05000461/2010002-06, Questions Regarding 10 CFR 50.59 Evaluation for CPS Procedure 3711.01 Involving Operations with the Potential to Drain the Reactor Vessel) pending additional review. The licensee wrote AR 01051306 to address the inspectors questions through its corrective action program
05000461/FIN-2010002-07	Main Turbine Trip During On-line Testing	2010Q1	The inspectors evaluated outage activities during Unit 1 forced outage C1F53, which began on February 5, 2010. During the performance of turbine on-line testing with the unit at about 17 percent power and the main generator synchronized to the grid, the turbine unexpectedly tripped due to mechanical overspeed. The turbine mechanical trip device was mis-adjusted during the refueling outage, which caused the turbine trip logic to activate prematurely. The reactor remained on line while troubleshooting the cause for the turbine trip. The licensee synchronized the unit to the grid on February 8th. The inspectors reviewed plant equipment configuration, risk management, startup activities, and identification and resolution of problems associated with the outage. This inspection constituted one other outage inspection sample as defined in IP 71111.20. No findings of significance were identified with the conduct of forced outage activities. During the refueling outage, the turbine mechanical trip device trip finger plunger gap was mis-adjusted by the turbine vendor while performing an inspection. This mis-adjusted gap caused the turbine trip logic to activate prematurely during start-up testing, causing the forced outage. This issue is considered to be an Unresolved Item (URI 05000461/20100002-07, Main Turbine Trip During On-line Testing) pending the inspectors review of the licensees cause evaluation for the event.
05000461/FIN-2010002-08	Inadequate Test Criteria in Standby Gas Treatment System Flow/Heater Operability Surveillance Test	2010Q1	The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings. The licensee failed to include appropriate quantitative or qualitative acceptance criteria in its surveillance test procedure for fulfilling the monthly surveillance requirement to demonstrate operability of the standby gas treatment (SGT) system as described in the Technical Specification Bases. As corrective action, the licensee revised the procedure to include acceptance criteria that system flow is normal and that no blockage, fan or motor failure, or excessive vibration is detected. The finding was of more than minor significance because it was associated with the Procedure Quality Cornerstone attribute for the Control Room and Auxiliary Building and adversely affected the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, by not providing appropriate acceptance criteria by which the operability of the SGT system trains could be assessed, the ability of the SGT system to collect and treat the design leakage of radionuclides from the primary containment to the secondary containment during an accident could not be assured. The inspectors did not identify a cross-cutting aspect related to this finding

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