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05000461/FIN-2008002-052008Q1ClintonChanges to ERO ON-SHIFT and Augmentation Staffing Levels and Position TitlesThe 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-2008002-012008Q1ClintonFailure to Follow Approved Fire Protection Program Procedures Concerning Control of Transient Combustible MaterialThe 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-2008002-032008Q1ClintonDuring the Performance of NRC Final Drywell Closeout, the Inspectors Noted That Foreign Material/Housekeeping Sock Had Not Been Removed from the Drywell Floor DrainsThe 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-2008002-042008Q1ClintonAS-FOUND Leakage Through Shutdown Service (Sx) Valve 1SX014AThe 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-2008002-072008Q1ClintonFailure to Barricade and Lock a Locked High Radiation AreaThe 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-2008002-062008Q1ClintonFailure to Evaluate Hydraulic Power Unit Piping for Impact with Containment Atmosphere Monitoring LineThe 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-2008002-022008Q1Clintonthe Licensee Discovered That the Wrong Component Was Installed in the B Turbine Driven Reactor Feed Pump Oil Pressure Sensing LogicA 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-2007004-042007Q3ClintonShipment Total Quantity RE-CHARACTERIZED After ShippingA 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-2007003-012007Q2ClintonLicensee-Identified ViolationSection 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.
05000454/FIN-2003007-022003Q4ByronFailure to Update the Updated Final Safety Analysis Report in a Timely Manner.

A finding of very low safety significance was self-revealed when the licensee discovered that an update to the Updated Final Safety Analysis Report was not accomplished for a period of almost 6 years following a design change. Between June and September of 1996, the licensee made a revision to the reactor water storage tank level set-point calculation to clarify design basis information with respect to emergency core cooling system and containment spray system operation and re-evaluated the time available to complete switchover to recirculation. The licensee did not include this update until the December 2002 revision to the Updated Final Safety Analysis Report.

Because this issue potentially impacted the NRC's ability to perform its regulatory function, this finding was evaluated using the traditional enforcement process. The finding was determined to be of very low safety signficance because it did not actually impede or influence any regulatory actions. This was determined to be a Severity Level IV NCV of 10 CFR 50.71.

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