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	Quarter	Site	Title	Description
05000237/FIN-2011002-01	2011Q1	Dresden	Satisfactory Performance of a Surveillance Test Procedure That Was Later Demonstrated to be Not Capable of Being Performed	The inspectors identified a non-cited violation (NCV) of the Dresden Nuclear Power Station Renewed Facility Operating License having very low safety significance (Green) for the licensees failure to perform adequate post-maintenance testing (PMT) on one smoke detector in the Control Room Ventilation System ductwork. During a walkdown of the Control Room Ventilation System, the inspectors identified that three smoke detectors in the ventilation ducts had been replaced in June 2010 and one was never tested successfully upon its return to service. During the course of this inspection, the inspectors identified several procedure quality issues. The inspectors reviewed WO 902046-01,D2/3 Annual PM Control Room HVAC System Smoke Detector Test, performed on November 25, 2008. This work order was to perform surveillance test DFPS 4183-14, Unit 2/3 Control Room HVAC Smoke Detector Annual Surveillance Procedure, Revision 9. The test results identified that Alarm 2/3-2223-89-C1, Control Room/East Turbine Building Smoke Detector Trouble, would not alarm when the following detectors were sprayed with test gas: Fn2/3-8941-017, Located in the Control Room Main Return Duct; Fn2/3-8941-018, Located in the Control Room HVAC Equipment Room Train B Exhaust Duct; and Fn2/3-8941-013, Located on the Main Control Room HVACX outside air supply duct. The 2/3-2223-89-C1, Control Room/East Turbine Building Smoke Detector Trouble, alarms at Panel 2/3-2223-89 in the Unit 2 switchgear room if a detector loses power. Other alarms at Panel 2/3-2223-89 and in the Control Room alarmed when the detectors were sprayed with test gas. The licensee wrote Issue Report (IR) 849580, Problems Encountered during Performance of DFPS 4183-14, to document the issue. The problem with the test procedure, in this case, was that per DFPS 4183-14 the 2/3-2223-89-C1 alarm was expected to annunciate when the detector was sprayed with test gas. As mentioned above, the 2/3-2223-89-C1 alarm is not designed to annunciate when sprayed with test gas but only when the detector loses power. This was not recognized by the licensee at the time even though the 2/3-2223-89-C1 alarm had not annunciated during the performance of DFPS 4183-14 since the first performance of the surveillance test in 2006. (See paragraph 4OA2.3 for more detail.) The licensee generated WO 1191692-01, Problems Encountered During Performance of DFPS 4183-14, to troubleshoot the failure of 2/3-2223-89-C1 to alarm when sprayed with test gas. The result of this work order was that all three smoke detectors needed to be replaced. This was documented in IR 957560, Three Smoke Detectors Require Replacement. Issue Report 957560 stated that the scope of work requested was to touch jumper between terminal 9 and 10 of each detector to determine if annunciator 2/3-2223-89-C1 alarmed. The author of the IR stated that annunciator 2/3-2223-89-C1 alarmed for each smoke detector and, therefore, the detectors were bad and needed to be replaced. In this case, the troubleshooting procedure did not identify that the cause of the failure of the 2/3-2223-89-C1 alarm to annunciate was a design issue and not an equipment issue. This was not recognized by the licensee at the time. However, surveillance test DFPS 4183-14 was performed again, per WO 1191661-01, D2/3 Annual PM Control Room HVAC System Smoke Detector Test, on February 3, 2010, this time with no issues regarding annunciator 2/3-2223-89-C1. The inspectors questioned how this could happen since the detectors, identified as bad in IR 957560 had yet not been replaced and no work had been performed on any of the smoke detectors in question. The system manager explained that steps within DFPS 4183-14 did not require the verification that annunciator 2/3-2223-89-C1 ever extinguished. Therefore, if the annunciator was in alarm at the beginning of the surveillance test, for whatever reason, then the test would have passed without issue. This issue would make DFPS 4183-14 inadequate because the surveillance could have passed without proper equipment operation. The inspectors searched and reviewed operator logs and corrective action program documents to determine if annunciator 2/3-2223-89-C1 was in alarm at the time the surveillance test was performed on February 3, 2010, and found no log entries or issue reports that would indicate that annunciator 2/3-2223-89-C1 was in alarm. The inspectors re-reviewed WO 1191661-01 and identified that there were separate steps to verify the annunciators on the 923-5 panel in the control room and the 2/3-2223-89 panel in the U2 switchgear room were reset after each individual smoke detector was tested. If the 2/3-2223-89 panel C1 alarm was in at the beginning of the test and would not extinguish, this should have been noted in the WO and/or in an IR. The inspectors concluded that this was not a valid explanation. The licensee performed fact finding based on the inspectors questions why this surveillance test passed when it should not have. The inspectors discussed the fact finding results with the licensee manager that performed the fact finding on April 6, 2011. The licensee found no explanation why the test passed. The individual that performed the test stated that the performance of that specific test could not be recalled. The satisfactory performance of DFPS 4183-14 on February 3, 2010, was unexplained. The unexplained satisfactory performance of a surveillance test procedure, that was later demonstrated to be not capable of being performed as written, was an Unresolved Item pending inspector review of additional licensee evaluation. (URI 05000237/2011002-01; 05000249/2011002-01) The inspectors reviewed WO 1264824-04, Three Smoke Detectors Require Replacement, performed on June 11, 2010, in which the smoke detectors were replaced and were to be post-maintenance tested. Smoke detector 2/3-8941-013, located on the Main Control Room HVAC outside air supply duct, was replaced but was not tested. The function of detector 2/3-8941-013 was to prevent or reposition ventilation dampers such that if smoke was detected coming into the building from outside, the smoke purge function of the control room ventilation system would be prevented. The WO stated that the dampers would not reposition to the smoke purge position, therefore, smoke detector 2/3-8941-013 could not be tested. This also meant that the control room ventilation smoke purge capability was non-functional. The smoke purge capability was still non-functional at the end of the inspection period. Troubleshooting was ongoing as of April 12, 2011, and the extent of the problems with smoke purge was unknown so there was no scheduled repair date. The smoke detector alarming in the control room should also result in manually switching to the isolation mode to prevent further smoke from entering the control room. The isolation dampers were separate for the smoke purge dampers and were functional. The inspectors determined the smoke purge control capability of detector 2/3-8941-013 could not be tested but the alarm function could have been tested and was not.
05000237/FIN-2011004-05	2011Q3	Dresden	Alert Declared Due to Chemical Spill	The inspectors identified an unresolved item regarding 10 CFR 50.59 Changes, Tests, and Experiments. The licensee installed tanks containing sodium hypochlorite and Hydroxyethylidenediphosphonic acid (HEDP, a strong acid) and may not have accounted for conditions for an accident of a different type than any previously evaluated in the Updated Final Safety Analysis Report (UFSAR). On July, 15, 2011, the licensee restricted access to the crib house due to a combined spill of sodium hypochlorite and HEPD. The mixture of the two chemicals produced chlorine gas. Based on initial assessment of the event and meeting the Emergency Action Level (EAL) threshold criteria an Alert, HA7, was declared at 10:16 a.m. The Alert was terminated at 3:20 p.m. on July 15, 2011, when actions to ventilate the crib house were completed and all areas were verified to be clear. The inspectors were in the process of reviewing two modifications in regard to 10 CFR 50.59 which may not have accounted for conditions for an accident of a different type than any previously evaluated in the UFSAR. The first was the addition of the chemical storage tanks and the second was the removal of the control room ventilation Toxic Gas Analyzer from service. The inspectors considered this issue an unresolved item (URI) pending further evaluation efforts. (URI 05000237/2011004-05; 05000249/2011004-05)
05000237/FIN-2012002-01	2012Q1	Dresden	Failure to Report an Unanalyzed Condition that Could Significantly Degrade Plant Safety	On January 11, 2012, it was postulated in IR 1312222 that while on shutdown cooling (SDC) in Mode 3 and a loss of coolant accident (LOCA) were to occur, the SDC and LPCI common discharge piping would void resulting in flashing and pipe damage during the 40 seconds it takes for the SDC isolation valves to close on a Group 3 isolation signal. This challenges the ability of both subsystems of LCPI to inject in such a scenario. Both sub-systems of LPCI are required to be operable by technical specifications while in Mode 3. The licensees immediate operability determination was that LPCI remained operable; however, additional analysis was required to determine if the event was plausible and if the plant was bounded by previous analysis. Corrective action assignments were generated to evaluate the condition with Exelon corporate due by January 25, 2013 (over 1 year later). Two other corrective action assignments were written to evaluate the final resolution of a similar scenario at Quad Cities Nuclear Power Station and to evaluate current operations procedures to determine if additional guidance is necessary in this postulated scenario at Dresden. All three corrective actions remained open at the end of the assessment period. The inspectors questioned the timeliness of licensee corrective actions, in particular with respect to prompt operability and reportability of the potential unanalyzed condition, which was documented in IR 1341563. The licensee justified prompt operability after 60 days based on 1) a GE BWR Owners Group Technical Report Effects of Voiding in emergency core cooling system (ECCS) Drywell Injection Piping, 2) the probability of occurrence of the aforementioned scenario being on the order of 1E-08 and was therefore not a credible event and did not require further analysis, and 3) the fact that preliminary results done at Quad Cities and Duane Arnold Energy Center for similar issues indicated that all operability requirements for piping were met. The licensee justified reportability as no loss of safety function occurred and therefore this issue was not reportable. The inspectors reviewed the GE technical report and determined that the report does not apply to this scenario as the scope of review was limited to small voids existing prior to an accident or transient - not voids developed as a result of an accident or transient. Additionally, the GE technical report indicated that flashing as a result of LPCI injection would occur in both the vessel and recirculation lines. In the postulated scenario, LPCI and SDC flashing would occur upstream of the recirculation lines in the LPCI piping that is significantly smaller in diameter than the recirculation piping, 16 inches as opposed to 28 inches, respectively. The licensee indicated that they had an ongoing technical evaluation underway that would show the potential unanalyzed condition would not challenge the ability of LPCI to inject. This analysis was not completed during the 60 day LER reportability timeframe, and at the end of the inspection period the technical evaluation was still in progress. The inspectors considered this issue an unresolved item (URI) pending completion and review of the licensees technical evaluation. (URI 05000237/2012002-01; 05000249/2012002-01, Failure to Report an Unanalyzed Condition that Could Significantly Degrade Plant Safety )
05000237/FIN-2012002-02	2012Q1	Dresden	Failure to Ensure the Effectiveness of Packages as required by DOT Regulations	A finding of very low safety significance was self-revealed following the licensees failure to appropriately package and transport radioactive material. This finding also resulted in two associated NCVs of 10 CFR 61.56(a)(3) and 10 CFR 71.5(a). The licensees corrective actions included revising procedures and completing a detailed review through an apparent cause evaluation of the event. Additionally, the licensee suspended all radioactive material shipments using similar general packagings as a part of their corrective actions. This finding was assessed using IMC 0609, Attachment D, Public Radiation Safety Significance Determination Process, and determined to be of very low safety significance (Green). The inspectors determined that the finding did not involve the radioactive effluent release program or the radiological environmental monitoring program. The finding did involve the transportation of radioactive material. However, no external radiation levels or surface contamination levels were exceeded, the finding did not involve the certificate of compliance, and there was no failure to make notifications or provide emergency information. The finding did involve a breach of the package during transit and low-level burial ground non-conformance. However, the finding did not involve the loss of package contents or waste classification issues. The inspectors determined that the primary cause of this finding was related to a cross-cutting aspect in the area of Problem Identification and Resolution.
05000237/FIN-2012002-03	2012Q1	Dresden	Failure to Ensure Packages Containing Solid Waste Contain as Little Free Standing and Noncorrosive Liquid as Reasonably Achievable	A finding of very low safety significance was self-revealed following the licensees failure to appropriately package and transport radioactive material. This finding also resulted in two associated NCVs of 10 CFR 61.56(a)(3) and 10 CFR 71.5(a). The licensees corrective actions included revising procedures and completing a detailed review through an apparent cause evaluation of the event. Additionally, the licensee suspended all radioactive material shipments using similar general packagings as a part of their corrective actions. This finding was assessed using IMC 0609, Attachment D, Public Radiation Safety Significance Determination Process, and determined to be of very low safety significance (Green). The inspectors determined that the finding did not involve the radioactive effluent release program or the radiological environmental monitoring program. The finding did involve the transportation of radioactive material. However, no external radiation levels or surface contamination levels were exceeded, the finding did not involve the certificate of compliance, and there was no failure to make notifications or provide emergency information. The finding did involve a breach of the package during transit and low-level burial ground non-conformance. However, the finding did not involve the loss of package contents or waste classification issues. The inspectors determined that the primary cause of this finding was related to a cross-cutting aspect in the area of Problem Identification and Resolution.
05000237/FIN-2012002-04	2012Q1	Dresden	Inadequate Basis in 10 CFR 50.59 Evaluation for Installation of Hypochlorite System	Title 10 CFR 50.59(b)(1) (1997, 1998) stated, in part, that the licensee shall maintain records of changes in the facility and of changes in procedures made pursuant to this section, to the extent that these changes constitute changes in the facility as described in the safety analysis report or to the extent that they constitute changes in procedures as described in the safety analysis report. These records must include a written safety evaluation which provides the bases for the determination that the change, test, or experiment does not involve an unreviewed safety question. Title 10 CFR 50.59 (a)(2)(ii) (1997, 1998) stated, in part, that a proposed change, test, or experiment shall be deemed to involve an unreviewed safety question if a possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis report may be created. Contrary to the above, from approximately 1998, through December 15, 2011, the licensee failed to maintain records of a change to the facility when it installed HEPD tanks in proximity to a sodium hypochlorite tank. The licensee did not maintain records of a written safety evaluation which provided the basis for the determination that the change did not involve an unreviewed safety question. Specifically, the accident scenario involving an on-site release of chlorine gas overcoming the control room operators had not been previously evaluated in the UFSAR and was not bounded by the UFSAR evaluation of chlorine released from off-site sources. In accordance with the Enforcement Policy, this violation of the requirements of 10 CFR 50.59 was classified as a Severity Level IV Violation because the underlying technical issue was of very low safety significance. Because this non-willful violation was non-repetitive, and was captured in the licensees CAP (IR 1302573), it is considered a NCV consistent Section 2.3.2 of the Enforcement Policy. (NCV 05000237/2012002-04; 05000249/2012002-04, Inadequate Basis in 10 CFR 50.59 Evaluation for Installation of Hypochlorite System
05000237/FIN-2012002-05	2012Q1	Dresden	Failure to Document a 10 CFR 50.59 Evaluation for Changes Made to the Facility	The inspectors identified a Severity Level IV NCV of 10 CFR 50.59, Changes, Tests, and Experiments, having very low safety significance (Green) for the licensees failure to perform an adequate safety evaluation review for changes made to the facility involving the placement of chemical storage tanks. As part of its corrective action, the licensee entered the issue into its corrective action program as IR 1302573 and performed Engineering Change Evaluations (EC) 38018 and EC 387073 which determined that the control room envelope had been historically operable. The licensee planned to install a completely different design of the chemical addition system that would separate the sodium hypochlorite storage from the hydroxyethylidenediphosphonic acid (HEDP, a strong acid) storage. Completion of the modification is planned for August 2012. The underlying technical finding was evaluated under the SDP using NRCs IMC 0609, Attachment 4, Phase 1 Initial Screening and Characterization of Findings, and the inspectors answered Yes to the question in Table 4a; Does the finding represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere? The SDP required a Phase 3 analysis to resolve this type of finding. However, after consultation with a Region 3 Senior Reactor Analyst it was determined that no SDP methods or tools exist to determine the significance of the finding. Therefore, the finding was not suitable for evaluation using the SDP, so the risk significance was established in accordance with the qualitative criteria of Appendix M (dated December 22, 2006) of IMC 0609. Specifically, the qualitative decision-making attribute from Table 4.1 of Appendix M, Finding can be bounded using qualitative and/or quantitative information was applicable to this finding. The licensee performed two quantitative engineering evaluations regarding this finding. The first (EC 387018) determined the minimum level of sodium hypochlorite stored in the tanks necessary that if it were to completely interact with the HEPD and completely release all of the contained chlorine would render the control room envelope inoperable. The second (EC 387073) determined that the tanks would not have been affected by wind, seismic, or missile impacts with a level of sodium hypochlorite equal to or greater than the level necessary to make the control room envelope inoperable identified in EC 387018. Therefore, based upon a qualitative measure of risk determined in accordance with Appendix M, NRC Management concluded that the issue was of very low safety significance (Green). This finding has no cross-cutting aspect because it does not represent current licensee performance.
05000237/FIN-2012002-06	2012Q1	Dresden	Unit 2 Control Rod Drive Flow Control Valve Failed Closed Due to Inadequate Work Order Instructions	A finding of very low safety significance was self-revealed for the failure to have adequate maintenance instructions to install the Unit 2 Control Rod Drive (CRD) Flow Control Valve A/B Selector Valve (2-302-6B) which resulted in the separation of the plastic instrument air tubing and the Unit 2 CRD flow control valves failing closed. The licensee made temporary repairs to 2-302-6B and wrote a work request to make final repairs. The licensee also wrote work requests to inspect the Unit 3 selector switch. The licensee also wrote a procedure change request to review DOA 0300-01, Control Rod Drive System Failure, to clarify the decision to scram upon flow control valve failure. The licensee generated a corrective action to tie procurement engineering (PE) document 56060 to the new 2-302-6B model number. The licensee planned to prepare an equipment apparent cause evaluation (EACE). Additional corrective actions should result from the EACE. A finding of very low safety significance was self-revealed for the failure to have adequate maintenance instructions to install the Unit 2 Control Rod Drive (CRD) Flow Control Valve A/B Selector Valve (2-302-6B) which resulted in the separation of the plastic instrument air tubing and the Unit 2 CRD flow control valves failing closed. The licensee made temporary repairs to 2-302-6B and wrote a work request to make final repairs. The licensee also wrote work requests to inspect the Unit 3 selector switch. The licensee also wrote a procedure change request to review DOA 0300-01, Control Rod Drive System Failure, to clarify the decision to scram upon flow control valve failure. The licensee generated a corrective action to tie procurement engineering (PE) document 56060 to the new 2-302-6B model number. The licensee planned to prepare an equipment apparent cause evaluation (EACE). Additional corrective actions should result from the EACE. resulted in the failure to include instructions to install plastic piping connectors in the work order that was used to replace 2-302-6B.
05000237/FIN-2012002-07	2012Q1	Dresden	Inadequate Work instruction Leads to Failure of Secondary Containment Interlock	A finding of very low safety significance and associated non-cited violation of Technical Specification (TS) Section 5.4.1 was self-revealed because the work instructions associated with WO 1450006-01, D2 SA PM 517 RB/TB INTLK DOOR (2-5850-52) ELECTRICAL CHECKS, were inadequate. The use of inadequate work instructions resulted in the temporary failure of the secondary containment boundary between the Unit 2 Reactor Building and the Unit 2 Turbine Building. The licensees corrective actions included disciplining the maintenance planner and having each of the maintenance department heads prepare human performance improvement plans. The finding was determined to be more than minor because the finding was associated with the Barrier Integrity Cornerstone attribute of configuration control and affected the cornerstone objective of maintaining the functionality of containment. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Barrier Cornerstone because the finding affected the secondary containment. The inspectors answered all four questions No which resulted in the finding screening as having very low safety significance (Green). This finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because the licensee did not ensure that human error techniques such as self and peer checking was used during the creation of the work package. Licensee and management personnel stated that the work planner failed to adequately self-check and get a peer check on the completion of the preparation of the work package.
05000237/FIN-2012002-08	2012Q1	Dresden	Failure to Make a Required 8 Hour Event Report Per 10 CFR 50.72(b)(3)(v)(D)	The inspectors identified a Severity Level IV NCV and associated finding of very low safety significance of 10 CFR 50.72(b)(3)(v)(D), Immediate Notification Requirements for Operating Nuclear Power Reactors, for the failure to report an event to the NRC within 8 hours, where an event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. The licensee had not prepared any corrective actions by the end of the inspection period. The inspectors determined that a failure to report was an example of a violation that could impact the regulatory process and was subject to Traditional Enforcement. The inspectors determined that the underlying technical issue involved the inability to scram The inspectors determined that a failure to report was an example of a violation that could impact the regulatory process and was subject to Traditional Enforcement. The inspectors determined that the underlying technical issue involved the inability to scram
05000237/FIN-2012002-09	2012Q1	Dresden	APRMs 4, 5, and 6, Not Within The TS limits Prescribed In TS 3.3.1.1 Table 3.3.3.3-1, 2.b and c	The inspectors identified a Severity Level IV NCV and associated finding of very low safety significance of 10 CFR 50.72(b)(3)(v)(D), Immediate Notification Requirements for Operating Nuclear Power Reactors, for the failure to report an event to the NRC within 8 hours, where an event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. The licensee had not prepared any corrective actions by the end of the inspection period. The inspectors determined that a failure to report was an example of a violation that could impact the regulatory process and was subject to Traditional Enforcement. The inspectors determined that the underlying technical issue involved the inability to scram The inspectors determined that a failure to report was an example of a violation that could impact the regulatory process and was subject to Traditional Enforcement. The inspectors determined that the underlying technical issue involved the inability to scram
05000237/FIN-2014004-01	2014Q3	Dresden	Failure to Perform an Adequate 10 CFR 50.59 Evaluation for Procedure DOP 130002	The inspectors identified a NCV of 10 CFR 50.59, Changes, Tests and Experiments, when, on February 10, 2011, the licensee failed to complete a 10 CFR 50.59 evaluation when they revised procedure DOP 130002 to change the position of Motor Operated Valve (MOV) 213013, Reactor Inlet Isolation, such that the Isolation Condenser (IC) system would not meet its design requirement of removing 84.2E+06 BTUs in 20 minutes when initiated from its minimum Technical Specification(TS) level and maximum TS temperature. The inspectors determined that the licensees failure to identify that the valve position adjustment required a 10 CFR 50.59 evaluation was a performance deficiency. This finding was evaluated using traditional enforcement because it had the potential for impacting the NRCs ability to perform its regulatory function. This finding was more than minor because there was a reasonable likelihood that the change would have required NRC review and approval prior to implementation. Specifically, by establishing a new position setting of MOV 213013, the licensee failed to determine that the proposed change would cause isolation condenser tubes to become exposed in the design basis accident such that it adversely affected a Final Safety Analysis Report described design function, which required an evaluation to be performed. In accordance with IMC 0612, Appendix B, Issue Screening, traditional enforcement does apply as the violation impacted the regulatory process. Using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was a design or qualification deficiency that did not represent a loss of the system and/or function, did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time, and did not result in the actual loss of one or more trains of non-technical specification equipment. Inspectors assessed the violation in accordance with the Enforcement Policy, and determined it to be a Severity Level IV violation because it resulted in a condition evaluated by the SDP as having very low safety significance (Enforcement Policy example 6.1.d.2). This finding has a cross-cutting aspect of Design Margins (IMC 0310, H.6) in the area of human performance, for failing to carefully guard and maintain the IC design requirement of removing 84.2E+06 BTU in 20 minutes.
05000237/FIN-2014004-02	2014Q3	Dresden	Inadequate Evacuation Time Estimate Submittals	The NRC identified a NCV of 10 CFR 50.54(q)(2) associated with 10 CFR 50.47(b)(10) and 10 CFR Part 50, Appendix E, Section IV.4, for failing to maintain the effectiveness of the Dresden Nuclear Power Station Emergency Plan as a result of failing to provide the station evacuation time estimate (ETE) to the responsible offsite response organizations (OROs) by the required date. Exelon submitted the Dresden Nuclear Power Station ETE to the NRC on December 12, 2012, prior to the required due date of December 22, 2012. The NRC completeness review found the ETEs to be incomplete due to Exelon fleet common and site-specific deficiencies, thereby preventing Exelon from providing the ETEs to responsible OROs and from updating site-specific protective action strategies as necessary. The NRC discussed its concerns regarding the completeness of the ETE, in a teleconference with Exelon on June 10, 2013, and on September 5, 2013, Exelon resubmitted the ETEs for its sites. The NRC again found the ETEs to be incomplete. The issue is a performance deficiency because it involves a failure to comply with a regulation that was under Exelons control to identify and prevent. The finding is more than minor because it is associated with the emergency preparedness cornerstone attribute of procedure quality and because it adversely affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The finding is of very low safety significance because it was a failure to comply with a non-risk significant portion of 10 CFR 50.47(b)(10). The licensee had entered this issue into their corrective action program (CAP) and re-submitted a new revision of the Dresden Nuclear Power Station ETE to the NRC on May 2, 2014, which was found to be complete by the NRC. The cause of the finding is related to the cross-cutting element of Human Performance, Documentation.
05000237/FIN-2014004-03	2014Q3	Dresden	Licensee-Identified Violation	A violation of 10 CFR 50.65(b)(2)(i) was identified by the licensee during a review of systems and components utilized in the emergency operating procedures (EOP) as compared to functions scoped into the sites Maintenance Rule Program. While reviewing emergency operating procedure DEOP 3001, Secondary Containment Control the Site Maintenance Rule Coordinator (SMRC) noted that one of the entry criterion for the procedure included receiving a Reactor Building Floor Drain Sump (RBFDS) Hi-Hi level alarm. The SMRC noted that the RBFDS was scoped into the Maintenance Rule Program, but the Hi-Hi level alarm function was not. This event was entered into the licensees CAP as IR 1698084. The failure to scope into the Maintenance Rule Program non-safety related structures, systems, and components that are relied upon to mitigate accidents or transients or are used in plant emergency operating procedures was considered a performance deficiency. The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, if left uncorrected, no maintenance performance criteria would have been established to ensure the reliability of a function serving as an entry criterion for an EOP associated with maintaining containment integrity. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, and Appendix A, The Significance Determination Process (SDP) for Findings At Power, Exhibit 3, Barrier Integrity Screening Questions, dated June 19, 2012. The inspectors answered No to the Appendix A, Exhibit 3 barrier integrity screening questions, therefore, the finding was determined to be of very low safety significance (Green). Licensee corrective actions included adding the RBFDS alarm function into the Maintenance Rule Program and performing an extent of condition review of all EOPs for SSC not scoped into the Maintenance Rule Program.
05000250/FIN-2010002-01	2010Q1	Turkey Point	Failure to implement design controls in a temporary modification.	The inspectors identified an NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for failing to maintain control of temporary equipment installed on unit 4 A residual heat removal pump piping when the permanent component cooling water flow indication to the pump seal failed high. Operators were using a controlotron as a compensatory measure to verify adequate cooling flow to the unit 4A residual heat removal pump seal and to assure operability of the unit 4A residual heat removal pump. If the controlotron had failed, the operators would not have received a component cooling water low flow alarm in the control room, lack of cooling flow to the pump would have gone undetected, and operability of the residual heat removal pump could have been affected. The inspectors identified the licensee failed to follow the temporary system alteration procedure to ensure design adequacy and to determine if the alteration required a 10 Code of Federal Regulations (CFR) 50.59 evaluation and NRC approval. The licensee documented this in the corrective action program as condition report 2010- 479. The finding is more than minor because it affected the configuration control attribute of the Mitigating Systems Cornerstone in that it reduced the reliability of the 4A residual heat removal pump with the permanent flow indicator out of service while using an unevaluated controlotron to determine continued operability of the 4A residual heat removal pump. The inspectors screened the finding using NRC Inspection Manual Chapter 0609, Significance Determination of Reactor Inspection Findings for At Power Operations, Phase 1 screening. The finding was of very low safety significance because the design or qualification deficiency did not result in actual loss of operability or functionality of the pump. The cross cutting aspect of Human Performance, Work Practices (H.4(b)) was affected. (1R18)
05000250/FIN-2010002-02	2010Q1	Turkey Point	Licensee-Identified Violation	Technical Specification 3.9.13 requires that with one containment radiation monitor out of service during core alterations, core alterations may continue as long as the containment ventilation isolation valves be maintained shut and within one hour, operate the control room ventilation system in the recirculation mode. Contrary to the above, on April 1, 2009, and on prior occasions, core alterations continued with one channel of control room isolation actuation out of service and without the control room ventilation in the recirculation mode. The non-compliance was identified during review of plant conditions while performing engineered safeguards integrated testing with the plant in Mode 6 refueling. The redundant radiation monitoring and actuation channel remained available and had an event occurred, operators would have been able to use standby Self-contained breathing apparatus (SCBA) assuring the safety function. The issue was screened to be of very low safety significance (Green). When identified, the licensee placed the control room in recirculation and isolated the ventilation valves. The issue was documented in condition report 2009-9899 and additional corrective actions were specified. Because the licensee identified the issue and documented it into their corrective action program, and because the finding is of very low safety significance, this violation is being treated as a licensee identified NCV consistent with Section VI.A of the NRC Enforcement Policy
05000254/FIN-2017004-01	2017Q4	Quad Cities	Repeat Use of Written Exams during Licensed Operator Requalification Examinations	a. Inspection ScopeThe following inspection activities were conducted during the weeks of October 9 and October 16, 2017, to assess: (1) the effectiveness and adequacy of the facility licensees implementation and maintenance of its systems approach to training (SAT) based LORT Program put into effect to satisfy the requirements of 10 CFR 55.59; (2) conformance with the requirements of 10 CFR 55.46 for use of a plant referenced simulator to conduct operator licensing examinations and for satisfying experience requirements; and (3) conformance with the operator license conditions specified in 10 CFR 55.53. The documents reviewed are listed in the Attachment to this report.Licensee Requalification Examinations (10 CFR 55.59(c); SAT Element 4 as Defined in 10 CFR 55.4): The inspectors reviewed the licensees program for development and administration of the LORT biennial written examination and annual operating tests to assess the licensees ability to develop and administer examinations that are acceptable for meeting the requirements of 10 CFR 55.59(a).- The inspectors conducted a detailed review of one biennial requalification written examination versions to assess content, level of difficulty, and quality of the written examination materials. (02.03)- The inspectors conducted a detailed review of ten job performance measures and four simulator scenarios to assess content, level of difficulty, and quality of the operating test materials.(02.04)- The inspectors observed the administration of the annual operating test to assess the licensees effectiveness in conducting the examination(s), including the conduct of pre-examination briefings, evaluations of individual operator and crew performance, and post-examination analysis. The inspectors evaluated the performance of one crew in parallel with the facility evaluators during two dynamic simulator scenarios, and evaluated various licensed crew members concurrently with facility evaluators during the administration of several job performance measures. (02.05)- The inspectors assessed the adequacy and effectiveness of the remedial training conducted since the last requalification examinations and the training planned for the current examination cycle to ensure that they addressed weaknesses in licensed operator or crew performance identified during training and plant operations. The inspectors reviewed remedial training procedures and individual remedial training plans. (02.07) Conformance with Examination Security Requirements (10 CFR 55.49): The inspectors conducted an assessment of the licensees processes related to examination physical security and integrity (e.g., predictability and bias) to verify compliance with 10 CFR 55.49, Integrity of Examinations and Tests. The inspectors observed the implementation of physical security controls (e.g., access restrictions and simulator I/O controls) and integrity measures (e.g., security agreements, sampling criteria, bank use, and test item repetition) throughout the inspection period. (02.06)Conformance with Operator License Conditions (10 CFR 55.53): The inspectors reviewed the facility licensee's program for maintaining active operator licenses and to assess compliance with 10 CFR 55.53(e) and (f). The inspectors reviewed the procedural guidance and the process for tracking on-shift hours for licensed operators, and which control room positions were granted watch-standing credit for maintaining active operator licenses. Additionally, medical records for seven licensed operators were reviewed for compliance with 10 CFR 55.53(I). (02.08)Conformance with Simulator Requirements Specified in 10 CFR 55.46: The inspectors assessed the adequacy of the licensees simulation facility (simulator) for use in operator licensing examinations and for satisfying experience requirements. The inspectors reviewed a sample of simulator performance test records (e.g., transient tests, malfunction tests, scenario based tests, post-event tests, steady state tests, and core performance tests), simulator discrepancies, and the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and evaluated the discrepancy corrective action process to ensure that simulator fidelity was being maintained. Open simulator discrepancies were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator actions as well as on nuclear and thermal hydraulic operating characteristics. (02.09)Problem Identification and Resolution (10 CFR 55.59(c); SAT Element 5 as Defined in 10 CFR 55.4): The inspectors assessed the licensees ability to identify, evaluate, and resolve problems associated with licensed operator performance (a measure of the effectiveness of its LORT Program and their ability to implement appropriate corrective actions to maintain its LORT Program up to date). The inspectors reviewed documents related to licensed operator performance issues (e.g., licensee condition/problem identification reports including documentation of plant events and review of industry operating experience from previous 2 years). The inspectors also sampled the licensees quality assurance oversight activities, including licensee training department self-assessment reports. (02.10)This inspection constituted one Biennial LOR Program inspection sample as defined in IP 71111.1105.b. FindingsIntroduction: While performing an assessment of the licensees processes related to examination physical security and integrity (e.g. predictability and bias) to verify compliance with 10 CFR 55.49, Integrity of Examinations and Tests, the inspectors 10 identified that Quad Cities 2015 LOR written examinations were duplicated from the 2013 LOR examinations, that 2017 LOR written examinations were duplicated from the 2015 LOR examinations, and that four individuals were administered the same written examinations from the previous exam cycle.Description: The inspectors identified that, with few exceptions, the licensee had duplicated or reused questions from the 2015 written exam when they created the 2017 written exam. The licensee created six LOR written exam versions (i.e., AF), one for each crew. For the 2017 biennial exam, the licensee essentially swapped exam versions from 2015 that were given to each crew (i.e., the 2015 Version A was given to crew B in 2017 and Version B was given to crew A, etc.). The inspectors noted that no crew received the same exam version in 2017 as they did in 2015. However, due to crew personnel adjustments/realignments, the inspectors requested the licensee to investigate if, and how many, operators were going to receive the same exam in 2017 as in 2015. The licensee identified that one reactor operator had already taken the same exam in 2017 that they were given in 2015. In addition, the licensee also identified that two additional licensed operators were scheduled to take the same exam they had taken in 2015, but they had not yet been given the exam due to the exam schedule. After discussing the issue and concern with the inspectors, the licensee decided to administer those two individuals different exam versions to which they had not been previously exposed. In addition, the inspectors inquired how long the particular set of exam versions had been reused and swapped among the crews (i.e., before 2015). The licensee reviewed biennial written exams in 2013 and 2011 and determined the exam content was different and stated, there was no predictable pattern in exam versions. After reviewing all of the 2013 exam versions, the inspectors identified that three versions were a mixture of questions between reused and new questions. For example, 2013 Version A was a mixture of questions of 2015 exam Versions C and D and twounique questions. The 2013 Version B was a mixture of 2015 Version C and D and seven unique questions. The 2013 Version F was a mixture of 2015 D and F and fiveunique questions. The three remaining versions from 2013 were replicated in 2015, but given to different crews. The inspectors requested the licensee determine the number of personnel that took the same exam in 2015 as in 2013, and the licensee identified three individuals who were given the same exam in 2013 and 2015 (two senior reactor operators and one reactor operator). The inspectors are considering this issue to be an unresolved item (URI) concerning whether the repeated use of a biennial written examination for sequential requalification programs (consecutive 24 month periods), and the resulting predictability induced to the examination process, constitutes a violation of 10 CFR 55.49, Integrity of Examinations and Tests. The inspectors have requested the licensee provide the written examinations in question to the inspectors for further review. The inspectors will review individual questions of the written examinations in order to determine if there were sufficient differences between the examinations to characterize the examinations as either different or similar. The results of the review will be used to determine if a violation of 10 CFR 55.49 requirements exists. (URI 05000254/201700401; 05000265/201700401: Repeat Use of Written Exams during Licensed Operator Requalification Examinations)
05000255/FIN-2011003-01	2011Q2	Palisades	Failure to Evaluate Reactor Vessel Head Corrosion During Visual Examination, Human Performance, Decision Making	A finding of very low safety significance and associated NCV of 10 CFR Part 50.55a(g)(6)(ii)(D)(1), Reactor Vessel Head Inspections, was identified by the inspectors for the licensees failure to evaluate corrosion present on the reactor vessel head during a Code Case (CC) N-729-1 VE visual examination. The licensee entered the condition into the corrective action program. As a corrective action the licensee compared pictures taken during the 2010 head visual examination with video records from a 2003 visual head examination. Based upon this comparison, the licensee determined that no indication of significant wall loss or structural degradation had occurred. Further, the licensee determined that the surface irregularities observed were caused by a combination of scaling (e.g., rusting) due to high humidity and a rough surface condition caused by the original head forging process and were not the result of boric acid induced corrosion or wastage. Additionally, the licensee determined that the white spots on the head were the result of boron staining, white mastic residue used to attach insulation to the head, or chromate water deposits from a previous component cooling water leak. The licensee did not identify any evidence of leakage of boron or boric acid on the head since the 2003 visual head examination. Based upon these observations and conclusions, the licensee determined that the reactor vessel head was operable and acceptable for continued service. The licensee also assigned a corrective action to ensure that an appropriate evaluation of relevant indications was incorporated into the vessel head VE examination procedure. The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of Equipment Performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Absent NRC identification, the failure to evaluate head corrosion could have allowed unacceptable wastage to be returned to service. If areas of corrosion reduced vessel head strength, it could place the reactor coolant system at increased risk for through-wall leakage and/or failure. The licensee completed actions to assess the corrosion and surface irregularities observed and determined that no indication of significant wall loss or structural degradation had occurred. The inspectors answered No to the SDP Phase I screening question Assuming worst case degradation, would the finding result in exceeding the Technical Specification (TS) limit for any reactor coolant system leakage or could the finding have likely affected other mitigation systems resulting in a total loss of their safety function assuming the worst case degradation? Therefore, the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Decision Making because the licensee staff failed to make conservative assumptions in decisions affecting the integrity of the reactor vessel head. Specifically, the decision to not evaluate areas of corrosion present on the vessel head was not based sufficient information to demonstrate that the proposed action/decision was safe (H.1(b)).
05000255/FIN-2011003-02	2011Q2	Palisades	Failure to Establish a Back-up Radiation Monitor	The inspectors identified a finding of very low safety significance and associated NCV of TS 5.5.1 for failure to establish, implement and maintain the Offsite Dose Calculation Manual (ODCM). Specifically, the licensee failed to establish a backup radiation monitor capable of performing monitoring consistent with the primary radiation monitors and ODCM requirements. Over several months, the licensee experienced multiple failures of the steam line and stack radiation monitors. The ODCM provides direction to point a backup monitor at the effected effluent path should the primary monitor fail. The backup radiation monitor could not perform its intended function due to physical obstructions and geometry. The licensee instituted alternate means of monitoring releases when the primary monitor does not work and has entered the condition into the corrective action program. The inspectors concluded that the failure to establish RIA 2328 to be an effective backup for the stack and steam line radiation monitors was a performance deficiency that warranted a significance determination. Since RIA-2328 potentially impacts both Public Radiation Safety and Emergency Planning Cornerstones, the inspectors reviewed the significance under both cornerstones. For radiation protection, the inspectors compared the issue to the examples in Appendix E, and concluded that example 6.b applied. Example 6.b states that a radiation monitor that cannot perform its safety function with a reasonable level of safety margin is an example of a more than minor issue. Further, the inspectors determined the finding was more than minor because it impacted the Public Radiation Safety Cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation and is associated with the program and process attribute. This finding was assessed using IMC 0609, Attachment D for the Public Radiation Safety SDP and determined to be of very low-safety-significance (Green) because this was not a failure to implement the effluent program and public dose remained less than 10 CFR Part 50, Appendix I, limits. In addition, the radiation monitor is used in the emergency plan for determining an emergency action level. The issue screened out as minor in this cornerstone, because there are other EALs that would be available to ensure the correct classification could be met within required times. There was no cross-cutting aspect in that the procedures and radiation monitor have been in place for several years and do not reflect current plant performance.
05000255/FIN-2011003-03	2011Q2	Palisades	Failure to Establish a Back-up Radiation Monitor	A self-revealed finding of very-low safety significance with an associated NCV of TS 5.4.1, Procedures, occurred for the licensees failure to properly implement the procedure for inspection of American Society of Mechanical Engineers (ASME) Class 2 piping associated with the Safety Injection and Refueling Water tank. Specifically, while investigating roof leakage into the control room and auxiliary building, boric acid deposits and an active flange leak discovered on piping under the tank roof indicated that this ASME Class 2 piping had not been inspected per the site procedure for approximately 20 years. Upon discovery, this leak would require ASME Code Section XI corrective actions to confirm the structural integrity of the connection. Although the licensee considered the area with the piping inaccessible, while investigating the roof leakage issue, the licensee was able to construct a scaffold and reach the area of concern. The licensee initiated condition reports, cleaned off all of the deposits and completed VT-2 inspections of piping in the area. The issue was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone, whose objective is to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, boric acid accumulations and leakage impacting a Class 2 system requiring ASME Code Section XI corrective actions could go undetected during further code inspection intervals. Inspection Manual Chapter 0609, Appendix E, example 2c, helped inform that determination because the example states that a finding would be more than minor if degradation existed following periods of missed testing. The finding screened as very low safety significance (Green) by answering no to questions in the Mitigating Systems column of IMC 0609, Attachment 4, Table 4a, since the boric acid accumulations did not result in a loss of function for the impacted components. The inspectors determined that there was no associated cross-cutting aspect due to the age of the issue.
05000255/FIN-2011003-06	2011Q2	Palisades	Failure to Include The Steam Generator Mausoleum in the Groundwater Protection Risk Ranking Program, Problem Identification & Resolution	The inspectors identified a finding of very low-safety-significance and an associated NCV of TS 5.4.1, Procedures, for the failure to implement procedures and include the steam generator mausoleum in the groundwater risk-ranking program for structures, systems, or components after a small amount of water was identified on the floor that contained Cs-137 and tritium with a credible mechanism to reach groundwater. Specifically, the licensee did not implement Station Procedure EN-CY-111, Radiological Groundwater Monitoring Program to evaluate and document this structure after it was determined to contain radioactive liquids with a single barrier before reaching groundwater. Completion of the groundwater risk-ranking process may have prescribed additional measures to enhance or reinstate leak detection methods for this structure that contains licensed material and for which there is a credible mechanism for licensed material to reach groundwater. The licensee entered the condition into the corrective action program. Corrective actions included creating a recurring action item AR 00107492 to inspect the mausoleum every 6 months and clean up any water. The finding was more than minor because it affected the Public Radiation Safety Cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain, in that these conditions could result in reduced capability to detect and correct leaks of radioactive material before there is an impact on public dose. It is associated with program and process attribute of this cornerstone. Using IMC 0609, Attachment D, for the Public Radiation Safety SDP, the inspectors determined the finding to be of very low-safety significance because there is no indication of a spill or release of radioactive material on site or to the offsite environs from this structure and therefore, this finding was not a failure to implement the effluent program and public dose remained less than 10 CFR Part 50, Appendix I, limits. The finding was previously entered in the licensees corrective action program. However, the licensee failed to take appropriate corrective actions to address issues. Consequently, this deficiency has a cross-cutting aspect in Problem Identification and Resolution (Corrective Action Program).
05000255/FIN-2011003-08	2011Q2	Palisades	Failure to Adequately Manage Changes to the ODCM, Problem Identification & Resolution	The inspectors identified a finding of very low-safety significance and associated NCV of TS 5.5.1.c, for a change that was made to the ODCM in 2004 to eliminate drinking water well sampling with an inaccurate evaluation for the change. This evaluation failed to address community wells that provide drinking water to homes immediately adjacent to plant property to the south. These community wells are between the plant site and the Covert Township Park. These locations were drinking water wells that were historically sampled until the 2004 ODCM change. This issue was entered into the licensee corrective action program as CR-PLP-2010-1013. The licensee revised the ODCM to add the sampling and analysis of the Palisades Park drinking water well. The finding was more than minor because it affected the Public Radiation Safety Cornerstone objective to ensure adequate protection of public health and safety from exposure to radioactive materials released into the public domain, in that these conditions could result in reduced capability to detect potential impacts associated with this pathway. It is associated with program and process attribute of this cornerstone. Using IMC 0609, Attachment D, for the Public Radiation Safety SDP, the inspectors determined that the finding was of very low-safety significance because it involved the environmental monitoring program. The finding was previously entered in the licensees corrective action program. However, the licensee failed to thoroughly evaluate the problem and did not ensure that the problem was resolved. Consequently, this deficiency has a cross-cutting aspect in Problem Identification and Resolution (Corrective Action Program).
05000255/FIN-2012005-01	2012Q4	Palisades	Failure to Perform Immediate Operability Determination	The inspectors identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50 Appendix B, Criterion V, for the failure to perform an immediate operability determination in accordance with EN-OP-104, Operability Determination Process. After discovering a non-isolable steam leak on a main steam header drain valve (an American Society of Mechanical Engineers (ASME) Class 2 system) at approximately 2:30 a.m., the licensee failed to perform the steps specified in EN-OP-104 to expeditiously evaluate and to document a basis for operability. In addition, EN-OP-104 required input from engineering to be obtained for an ASME Class 2 thru-wall leak. However, the night-shift operators did not obtain input from engineering and did not document the basis for operability. After day-shift took over in the morning around 6:30 am, engineering and management were contacted and more rigorous efforts to assess operability commenced. The licensee subsequently declared the associated primary coolant system (PCS) loop, which requires an operable steam generator, to be inoperable at 11:15 am (approximately 9 hours after the condition was initially documented) and shut down the plant to repair the leak. The inspectors determined that not completing an immediate determination in accordance with EN-OP-104 caused an unnecessary delay in commencing a plant shutdown to repair the non-isolable leak. The licensee entered this issue into their corrective action program as CR-PLP-2013-00158. The issue was determined to be greater than minor in accordance with IMC 0612, Appendix B, because if left uncorrected, it could lead to a more significant safety concern. Specifically, the failure to perform an immediate operability determination when assessing safety-related components, including a delay in requesting assistance, could lead to more significant issues. The performance deficiency also affected the Initiating Events cornerstone attribute of Equipment Performance, adversely impacting the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The issue was determined to be of very low safety significance (Green) because it did not cause a reactor trip AND a loss of accident mitigation equipment. The finding had an associated cross-cutting aspect in the decision-making component of the human performance area because the night-shift operators did not obtain interdisciplinary input and reviews on the safety-significant operability decision.
05000255/FIN-2012005-02	2012Q4	Palisades	Failure to Manage Non-Covered Worker Hours	A finding of very low safety significance was identified by the inspectors for the programmatic failure to appropriately implement procedure, EN-FAP-OM-006, Working Hour Limits for Non-Covered Workers. Two non-covered supervisors and six individual contributors, performing work or overseeing work on a safety-related component, did not follow the procedural requirements of obtaining supervisor approval prior to exceeding working hour limits, document excess work hours in the payroll system, or initiate a condition report in a timely manner. An extent-of-condition review identified two additional instances of individuals, one contractor and one plant employee, not obtaining prior approval to exceed work hour limits nor completing the appropriate documentation. No violation of regulatory requirements occurred since the performance deficiency involved workers not covered by 10 CFR 26.205 through 26.209, which defines the work hour limitations and exceptions for covered workers. The licensee documented the programmatic weaknesses associated with the use of EN-FAP-OM-006 in their corrective action program. The Working Hour Limits for Non-Covered Workers procedure was revised to clarify when and by whom condition reports should be written when working hour limits are to be exceeded, as well as, who should write the report. The finding was more than minor in accordance with IMC 0612, Appendix B, because if left uncorrected, the programmatic failure to appropriately implement work hour limitations for non-covered workers could lead to more significant safety concerns associated with fatigue potentially impacting the conduct and oversight of work on safety significant components. The performance deficiency also affected the Initiating Events cornerstone attribute of Equipment Performance, adversely impacting the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the individuals who exceeded the working hour limits for non-covered workers were involved in a forced outage for repair and inspection of a control rod drive mechanism housing (part of the primary coolant system pressure boundary) that had a thru-wall leak which caused an emergent plant shutdown. Management review of this issue per IMC 0609 Appendix M, Significance Determination Process Using Qualitative Criteria, effective April 12, 2012, determined that this finding was of very low safety significance, or Green, since the performance deficiency did not directly contribute to the event. The finding had a cross-cutting aspect in the area of Problem Identification and Resolution, related to the cross-cutting component of Corrective Action Program, in that the licensee thoroughly evaluates problems such that the resolutions address causes and extent of conditions and also includes, for significant problems, conducting effectiveness reviews of corrective actions to ensure that the problems are resolved. In this finding, similar instances of non-covered workers not adhering to the standards for work hour limits and not initiating condition reports as required by EN-FAP-OM-006 were identified in 2011, and the corrective actions for those issues were not sufficient to prevent them from occurring again.
05000255/FIN-2012005-03	2012Q4	Palisades	Safety Injection Refueling Water Tank Evaluation of Corrosion	After reviewing CR-PLP-2012-4451, the inspectors were concerned the associated aging effects of the accumulated water were not properly managed because the condition of the affected annulus region was not evaluated by the licensee. Specifically, the accumulated water beneath the floor of the SIRW tank created an environment that could promote corrosion of the tank floor, and this condition does not appear to be formally evaluated. Also, the potential for corrosion could be exacerbated by concrete-aluminum interaction. The inspectors required more information to determine whether this issue constituted a finding of significance. This issue is considered an unresolved item pending further NRC review of the licensees actions.
05000255/FIN-2012005-04	2012Q4	Palisades	Underground Pipe and Tank Program- Potential Deviations from NEI 09-14 Guide	The licensees buried piping and underground piping and tanks program was inspected in accordance with Paragraphs 03.01.a through 03.01.c of TI-2515/182 and the inspector could not determine if the program met all applicable aspects of NEI 09-14 Revision 1, as set forth in Table 1 of the TI. Specifically, the following six issues were identified that appeared to deviate from the NEI 09-14 guideline. 1. The inspectors identified a site procedure, EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, that allowed exclusion of buried pipe line segments and appeared to conflict with Section 3.1 Scope of NEI 09-14, which included: All piping that is below grade and contains any fluid and is in direct contact with the soil. Specifically, EN-DC-343 Section 5.3, Risk Ranking, step 4, stated, An underground segment whose failure is inconsequential and would cause no direct or collateral damage to plant SSCs may be excluded from the scope of the program. The inspectors were concerned that providing a procedure which allowed excluding pipe segments within the scope of the NEI 09-14 guidelines from the risk ranking process, may require a deviation from NEI 09-14, Section 3.1. 2. The licensee had previously identified (reference LO-HQNLO-2008-00015, CA 511) that site procedures EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, and CEP-UPT-0100, Underground Piping and Tanks Inspection and Monitoring, did not contain instructions for justifying and approving exceptions to the initiative and assigned a due date of December 30, 2013, to correct this error. However, the licensee had not considered Section 6.2.1, Procedures and Oversight, of NEI 09-14, which required that the necessary procedural governance and oversight responsibilities be in place by June 30, 2010, and this included a process for justifying and approving exceptions to the initiative. The inspectors were concerned that lack of procedural instructions for justification of exceptions to the initiative by the due date, may require a deviation from the NEI 09-14 Section 6.2.1. The licensees buried piping and underground piping and tanks program was inspected in accordance with Paragraphs 03.01.a through 03.01.c of TI-2515/182 and the inspector could not determine if the program met all applicable aspects of NEI 09-14 Revision 1, as set forth in Table 1 of the TI. Specifically, the following six issues were identified that appeared to deviate from the NEI 09-14 guideline. 3. The inspectors identified a site procedure, EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, that allowed exclusion of buried pipe line segments and appeared to conflict with Section 3.1 Scope of NEI 09-14, which included: All piping that is below grade and contains any fluid and is in direct contact with the soil. Specifically, EN-DC-343 Section 5.3, Risk Ranking, step 4, stated, An underground segment whose failure is inconsequential and would cause no direct or collateral damage to plant SSCs may be excluded from the scope of the program. The inspectors were concerned that providing a procedure which allowed excluding pipe segments within the scope of the NEI 09-14 guidelines from the risk ranking process, may require a deviation from NEI 09-14, Section 3.1. 4. The licensee had previously identified (reference LO-HQNLO-2008-00015, CA 511) that site procedures EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, and CEP-UPT-0100, Underground Piping and Tanks Inspection and Monitoring, did not contain instructions for justifying and approving exceptions to the initiative and assigned a due date of December 30, 2013, to correct this error. However, the licensee had not considered Section 6.2.1, Procedures and Oversight, of NEI 09-14, which required that the necessary procedural governance and oversight responsibilities be in place by June 30, 2010, and this included a process for justifying and approving exceptions to the initiative. The inspectors were concerned that lack of procedural instructions for justification of exceptions to the initiative by the due date, may require a deviation from the NEI 09-14 Section 6.2.1. The licensee had previously identified (reference CR-PLP-2012-00631 and LO-PLPLO-2011-00127) that 16 buried lines containing radiological materials and in excess of 75 nonradiological buried lines were not included in the buried pipe program and risk evaluation completed in 2008 (reference LO-HQNLO-2008-00015, CA 25, 26 and 27). The licensee had contracted with a vendor to redo a risk evaluation of the piping within the program by February of 2013 and stated the scope of this new risk evaluation would include the buried lines missed in the original reviews. However, the licensee had not considered Section 3.3. A.2 Risk Ranking of NEI 09-14 which required completion of the risk ranking of buried pipe segments by December 31, 2010, to determine the likelihood and consequences of failure for each buried pipe segment. The inspectors were concerned that by not including a substantive number of buried pipe lines in the original risk ranking by the due date, may require a deviation from the NEI 09-14 Section 3.3.A.2. 5. The inspectors identified that the licensees buried pipe risk ranking had not been periodically reviewed and updated since the original risk ranking was completed in 2008 (reference LO-HQNLO-2008-00015, CA 25, 26 and 27). This appeared to conflict with Sections 3.3.A.2 and 6.2.2 of the NEI guidelines, which stated that the risk ranking shall be periodically reviewed and updated as necessary to reflect inspection results, changes in operating conditions, and design modifications. Further, the lack of a review was not consistent with Section 5.9.2 of CEP-UPT-0100, Underground Piping and Tanks Inspection and Monitoring, which required the Underground Pipe and Tank Program Engineer and the Groundwater Protection Specialist to perform a periodic review (at six month intervals) to update the scope and risk ranking for changes that have occurred. The inspectors were concerned that the lack of periodic reviews of the program scope and risk ranking may require a deviation from the NEI 09-14 Section 3.3.A.2 and 6.2.2. 6. The inspectors identified that SEP-UIP-005, Underground Components Inspection Plan, Revision 1, did not contain each of the attributes required for an inspection plan as discussed in NEI 09-14 Section 3.3.A.3. Specifically, for buried piping containing radiological material identified in Appendix A1 of SEP-UIP-005, 13 lines did not identify the portion of the line (piping segment) subject to inspection and 7 lines did not identify the intended/potential inspection technique. Additionally, for non-radioactive buried piping lines identified in Appendix A2 of SEP-UIP-005, each of the 27 lines listed did not identify the risk ranking nor the pipe segment subject to inspection, and for 10 lines the intended/potential inspection technique was not identified. Therefore, SEP-UIP-005 appeared to conflict with NEI 09-14 Section 3.3.A.3, Inspection Plan, that required the inspection plan to include the following key attributes: identification of piping segments to be inspected, potential inspection techniques, inspection schedule based on risk ranking, and assessment of cathodic protection (if applicable). The inspectors were concerned that licensees Underground Components Inspection Plan did not identify specific pipe segments to be inspected, included pipe segments without inspection techniques, and set an inspection schedule without risk ranking pipe segments, and may require a deviation from NEI 09-14 Section 3.3.A.3. NEI 09-14 Section 6.2.6 states, If a utility finds itself outside of a required initiative element, and takes immediate action to meet the element, a deviation justification is not required, but the condition should be entered into the CAP and the Buried Pipe Integrity Task Force should be notified. At the conclusion of the inspection, the licensee documented these issues in CR-PLP-2012-07697 and intended to discuss resolution of these issues with NEI. These examples of potential deviations from NEI 09-14 represent an unresolved item (URI 05000255/2012005-04, Underground Pipe and Tank Program- Potential Deviations from NEI 09-14 Guideline) pending completion of reviews by the licensee and NEI to determine the final status/disposition of these items.
05000255/FIN-2012005-05	2012Q4	Palisades	Concerns with the Methodology Used to Determine Suction Side Void Acceptance Criteria	On January 11, 2008, the NRC requested each addressee of GL 2008-01 to evaluate its emergency core cooling, decay heat removal, and containment spray systems licensing basis, design, testing, and corrective actions to ensure gas accumulation was maintained less than the amount which would challenge the operability of these systems, and take appropriate actions when conditions adverse to quality were identified. In order to determine what amount of gas could challenge the operability of the subject systems, the licensee needed to develop appropriate acceptance criteria for evaluating identified voids. As part of this effort, the licensee developed acceptance criteria for evaluating voids identified in the suction side of the subject systems pumps. The suction side void acceptance criteria were based on an average over the transient duration time. This was inconsistent with the 0.5-second criterion recommended by NRR in TI 2515/177 Inspection Guidance (ML111660749). The NRR-recommended methodology was more conservative because it ensured there were no significant deviations exceeding the maximum recommended void fractions. However, because the licensees methodology averaged over the entire transient duration time, it allowed void volumes that could significantly exceed the recommended void fraction when the actual duration transient time was shorter than the maximum allowable duration time specified by the recommended void fraction acceptance criteria. The inspectors discussed this observation with NRR. This issue was captured in the licensees CAP as CR-HQN-2011-00853. Because the inspectors did not identify an existing void which would have exceeded the more conservative acceptance criteria, this issue does not involve current operability of any system. This issue is unresolved pending further evaluation of the licensees methodology
05000255/FIN-2013004-01	2013Q3	Palisades	Failure to Monitor in Alpha 3 Area	The inspectors identified a finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1. Specifically, the licensee failed to perform air sampling as required by station procedure EN-RP-122 Alpha Monitoring. The issue was entered in the licensees Corrective Action Program (CAP) as CR-PLP-2013-02054. The licensees immediate corrective actions included performance management of the radiation protection technician and direct radiation protection supervisor oversight of the work activity. The finding is more than minor because it was associated with the program and process attribute of the occupational radiation safety cornerstone and affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation. Specifically, not monitoring the worker intake in an Alpha Level 3 area affected the licensees ability to assess workers internal exposures in a timely manner, and adversely impacted the licensees ability to monitor, control, and limit radiation exposures (i.e., committed effective dose equivalent or internal dose). In accordance with IMC 0609 Appendix C, Occupational Radiation Safety Significance Determination Process, the inspectors determined that the finding had very low safety significance (Green) because the finding did not involve: (1) as-low-as-reasonably-achievable (ALARA) planning and controls; (2) a radiological overexposure; (3) a substantial potential for an overexposure; and (4) a compromised ability to assess dose. The inspectors determined that the primary cause of this finding was related to the cross-cutting aspect of problem identification and resolution in the component of corrective actions, specifically the licensee did not take appropriate corrective actions to address safety issues and adverse trends in Alpha monitoring in a timely manner, commensurate with their safety significance and complexity.
05000255/FIN-2014005-01	2014Q4	Palisades	Failure to Follow Procedure for Storage of Equipment in the Vicinity of Safety-Related Equipment	The inspectors identified a finding of very low safety significance (Green) with an associated non-citied violation of Technical Specification (TS) 5.4.1, Procedures and Programs, for the failure to follow site procedures covering the storage of material in the vicinity of safety-related equipment. Specifically, on three occasions the inspectors identified ladders at ladder station 42 in the 590 elevation of the component cooling water room that were either in contact with safety-related equipment or were capable of toppling into safety-related equipment. For immediate corrective actions, licensee personnel properly stored the ladder after each issue was identified by the inspectors. This issue is documented in the licensees corrective action program (CAP) as Condition Report CR-PLP-2015-00126. The performance deficiency was determined to be more than minor based on Inspection Manual Chapter (IMC) 0612, Appendix E, Example 4.a, which determined that low-level procedural errors without a safety consequence are more than minor when they become a repetitive/routine occurrence. Specifically, unrestrained ladders could impact safetyrelated equipment during a design basis seismic event. The inspectors evaluated the significance of the finding in accordance with IMC 0609, Attachment 4, Initial Characterization of Findings. In accordance with Table 2, the finding was determined to affect the Mitigating Systems Cornerstone. The inspectors answered No to the questions in Table 3 and continued the significance evaluation in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors answered No to the Mitigating Systems Screening Questions contained in Exhibit 2 and determined the finding was of very low safety significance (Green). This finding was associated with a cross-cutting aspect of Identification in the Problem Identification and Resolution cross-cutting area (P1).
05000255/FIN-2015002-01	2015Q2	Palisades	Failure to Take Appropriate Corrective Action for the Charging System While in Maintenance Rule (a)(1) Status	Green. An NRC-identified finding of very low safety significance and an associated NCV of Title 10 of the Code of Federal Regulations (CFR) 50.65(a)(1) was identified for the failure to take appropriate corrective actions for the charging system, while in Maintenance Rule (a)(1) status, when performance or condition goals were not met. Specifically, on April 2, 2015, the front cap of the B charging pump cracked, causing volume control tank (VCT) level and pressure to lower, most likely due to excessive local cavity pressures in the pump caused by the suction accumulator pressure being out of specification. Accumulator pressures being out of specification, which causes pressure oscillations and vibrations in the charging pumps and their associated suction and discharge piping, was a similar cause to previous maintenance rule system functional failures that occurred in 2013 and 2014, which transitioned the system to (a)(1) status in July 2014. The licensee documented the issue in their corrective action program (CAP), conducted an equipment apparent cause evaluation (EACE) for the most recent failure, and revised the Maintenance Rule (a)(1) Action Plan to address the on-going issues with the suction and discharge accumulators. The inspectors determined that the performance deficiency was more than minor in accordance with IMC 0612 because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone and adversely impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The charging system provides the critical safety functions of pressure and inventory control in the emergency operating procedures. The finding screened as having very low safety significance (i.e., Green) based on answering No to all the screening questions under the Mitigating Structures, Systems, and Components (SSCs) and Functionality section of the significance determination process (SDP). The finding had a cross-cutting aspect of Evaluation in the Problem Identification and Resolution area. Specifically, the organization did not thoroughly evaluate previous data on the suction and discharge accumulators pressures being out of specification and what affect that may have on the system. Also, when the accumulator pressures were found out of specification, sometimes that information was not documented in condition reports (CRs), nor were the preventive maintenance (PM) frequencies re-evaluated in a technical and rigorous manner to ensure the correct PM activities were being conducted on these components in a timely manner to assure system reliability.
05000255/FIN-2015002-02	2015Q2	Palisades	Failure to Wear Prescribed Respiratory Protection	Green. A self-revealed finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1 was identified for insulation work activities during the refueling outage associated with pressurizer spray valve CV1057. Specifically, prior to the work beginning, the licensee determined that the use of powered air purifying respirators would be required to minimize worker dose and maintain exposures as-low-as-reasonably-achievable (ALARA), but the work was performed using only face shields, and as a result a worker was contaminated externally and internally. Corrective actions included creation of an administrative requirement to revise any radiation work permit (RWP) task that required respiratory protection to more clearly state the requirements. The inspectors determined that the performance deficiency was more than minor in accordance with IMC 0612 because it was associated with the Program and Process attribute of the Occupational Radiation Safety Cornerstone and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation. Specifically, the failure to wear required respiratory protection during the reinsulating of CV1057 resulted in personal contamination and the intake of radioactive material. The inspectors concluded that the radiological hazards had the potential to result in higher exposures to the individuals had the circumstances been slightly altered. The finding was determined to be of very low safety significance (Green) in accordance with IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, because it was not an ALARA planning issue, there was neither an overexposure nor a substantial potential for an overexposure, and the licensees ability to assess dose was not compromised. The inspectors concluded that the cause of the issue involved a cross-cutting aspect in the area of Human Performance, Basis for Decisions. Specifically, the bases for operational decisions were communicated in a timely manner.
05000255/FIN-2015002-03	2015Q2	Palisades	Licensee-Identified Violation	Title 10 CFR 50.54(q)(2) requires that a holder of a nuclear power reactor operating license follow and maintain the effectiveness of an emergency plan that meets the requirements in 10 CFR Part 50, Appendix E and the planning standards of 10 CFR 50.47(b). Title 10 CFR Part 50.47(b)(4) states, A standard emergency classification and action level scheme, the bases of which includes facility system and effluent parameters, is in use by the nuclear facility licensee, and State and local response plans call for reliance on information provided by facility licensees for determinations of minimum initial offsite response measures. Section 4.1 of the Palisades Site Emergency Plan states, in part, that a conservative philosophy for classification shall be used to declare the highest classification for which an EAL has been exceeded and that Palisades EALs can be found in the Site Emergency Plan, Supplement 1 EAL Wall Charts. Site Emergency Plan, Supplement 1 EAL Wall Charts requires, in part, the declaration of an Unusual Event for EAL HU 1.1 for a seismic event if identified by both: (1) earthquake felt in plant, and (2) National Earthquake Information Center. The Palisades EAL Technical Basis defines a felt earthquake as, An earthquake of sufficient intensity such that: (a) the vibratory ground motion is felt at the nuclear plant site and recognized as an earthquake based on a consensus of control room operators on duty at the time, and (b) for plants with operable seismic instrumentation, the seismic switches of the plant are activated. Contrary to the above, on May 2, 2015, the licensee control room staff declared EAL HU 1.1 without meeting the threshold criteria stated in the EAL. Specifically, the control room staff based the Notification of Unusual Event declaration on outside personnel reports and information from the National Earthquake Center, but without the consensus of control room operators on duty at the time or a valid recorded indication on the operable seismic instrumentation. The NRC determined that the EAL Overclassification, which resulted in no unnecessary protective action recommendations, was of very low safety significance (i.e., Green) as specified in IMC 0609, EP Significance Determination Process, Appendix B, Figure 5.41, Significance Determination for Ineffective EALs and Overclassification. As such the NRC determined this to be an NCV in accordance with Section 2.3.2 of the Enforcement Policy. The licensee entered this issue into their CAP as CR 201508137.
05000255/FIN-2015002-04	2015Q2	Palisades	Licensee-Identified Violation	The licensee identified an NCV of TS 5.4.1, Procedures for an inadequate procedure that failed to ensure all of the regulatory requirements for fit testing of respiratory protection were satisfied before use. Technical Specification 5.4.1 required, in part, that written procedures shall be established, written, and maintained for respiratory protection. The licensees procedure governing respirator fit testing was ENRP505, Portacount Respirator Fit Testing, and provided the fleet standard for performing personnel respirator fit testing for tight-fitting respirators. Title 29 CFR 1910.134, Respiratory Protection. Specifically, 29 CFR 1910.134(f)(8) states that, Fit testing of tight-fitting atmosphere-supplying respirators and tight-fitting PAPRs shall be accomplished by performing quantitative or qualitative fit testing in the negative pressure mode, regardless of the mode of operation (negative or positive pressure) that is used for respiratory protection. Contrary to the above, on June 2, 2013, multiple respirator fit tests of tight fitting PAPRs were performed in only the positive pressure mode. The inspectors reviewed IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008. The inspectors determined that it was not an ALARA planning issue, there was neither an overexposure nor a substantial potential for an overexposure, and the licensees ability to assess dose was not compromised. Therefore the finding screened as having very low safety significance (i.e., Green). The licensee entered this issue into their CAP as CRPLP20132469.
05000261/FIN-2010004-01	2010Q3	Robinson	Failure to Have Adequate Work and Post Maintenance testing Instructions for the Volume Control Tank Comparator Module	A self revealing Green finding was identified for a failure to have adequate work orders to properly configure and post maintenance test the volume control tank (VCT) level comparator module. The licensees procedure ADM-NGGC-0104, Work Implementation and Completion, required that work orders contain all work activities necessary to perform all related work activities including Post Maintenance Testing (PMT). The licensees work orders for installing a jumper on the VCT level comparator module and for post maintenance testing failed to contain adequate instructions to properly configure (place jumper in correct location) and post maintenance test the volume control tank level comparator module. This resulted in the failure of the charging pump suction to automatically transfer from the volume control tank to the refueling water storage tank (RWST) when the auto transfer VCT low level setpoint was reached. The licensees identified corrective actions included repairing the subject VCT level module, reviewing the adequacy of other replacement NUS modules that have nonsafety control functions and revising the site specific PMT procedures to provide more specific guidance for ensuring that the control loop circuit is adequately tested. The failure to have adequate work order instructions to properly configure and post maintenance test the volume control tank level comparator module is a performance deficiency. This finding is greater than minor because the failure to auto transfer from the VCT to the RWST could cause a failure of the charging pump, resulting in the loss of seal injection which is a precursor to a seal LOCA. Using IMC 0609, Significance Determination Process, (SDP) Phase 1 Worksheet, the inspectors concluded that a Phase 2 evaluation was required since the finding could have likely affected other mitigation systems resulting in a total loss of their safety function. This issue was evaluated using IMC 0609, Appendix A (SDP Phase 2) as being potentially greater than green with loss of component cooling water (LOCCW) and loss of service water (LOSW) as the dominant sequences. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst in accordance with the guidance in IMC 0609 Appendix A utilizing the NRCs Robinson Standardized Plant Analysis Risk (SPAR) model. The VCT level comparator module performance deficiency resulted in a core damage frequency increase of less than 1E-6, Green. The risk was mitigated by the availability of the letdown and normal makeup charging pump suction sources, which would be available under certain conditions reducing the likelihood of an autoswap demand. Another factor which mitigated the risk is that the fire shutdown procedures for most fire areas specify use of a manual RWST supply valve. The performance deficiency is characterized as Green, a finding of very low safety significance. This issue has a cross-cutting aspect in the resources component of the human performance area because the licensee did not provide complete, accurate, and up-to-date work packages for the configuration and testing of the VCT comparator module.
05000261/FIN-2010004-02	2010Q3	Robinson	Failure to Design and Implement a Simulator Model that Demonstrated Reference Plant Response	A self-revealing Green NCV of 10 CFR 55.46(c), Simulation Facilities, was identified for a plant referenced simulator used for administration of operating tests not correctly modeling the reference plant. A loss of electrical power that resulted in a loss of component cooling water (CCW) to the reactor coolant pump seals was not properly modeled in the simulator. When power to safety-related 480 volt bus E-2 was transferred to the emergency diesel generator in the reference-plant, FCV-626, thermal barrier heat exchanger outlet isolation flow control valve, closed. The simulator modeled FCV-626 to respond to CCW flow through the valve and did not model the effect of a loss of power to the valve operator and associated control circuit. Consequently, with a loss of power to bus E-2, the simulator model allowed this valve to remain open. The licensee documented the issue in Significant Adverse Condition Investigation Report, 390095. As corrective action the licensee changed the simulator modeling to match the plant configuration. The inspectors determined that the failure of the simulator to accurately demonstrate reference plant response was a performance deficiency. This finding was more than minor because it affected the human performance attribute of the initiating events cornerstone in that the unexpected closure of FCV-626 raises the likelihood of human error in response to a loss and subsequent re-energization of the E-2 Bus. This could challenge reactor coolant pump seal cooling and result in reactor coolant pump seal failure. The finding was evaluated using the Operator Requalification Human Performance SDP (MC 0609, Appendix I) because it was a requalification training issue related to simulator fidelity. The finding was of very low safety significance (Green) because the discrepancy did not have an impact on operator actions resulting in a total loss of RCP seal cooling and subsequent increase in reactor coolant system (RCS) leakage. There is not a cross-cutting aspect associated with the finding because the performance deficiency involving the simulator modeling occurred over 3 years ago and does not reflect current licensee performance.
05000261/FIN-2010004-03	2010Q3	Robinson	Deficiencies in Non Safety-Related Cable Installation Result in Fire and Reactor Trip	A self-revealing Green finding was identified for the licensees failure to adequately follow guidance in a design change package for the installation of non safetyrelated 4kV cables. This resulted in cables with design features inappropriate for the application being installed and eventually led to a fire and a reactor trip. Specifically, the licensee failed to follow the cable vendor recommendations and a self-imposed administrative requirement/standard for cable installation contained in cable specification L2-E-035, Specification for 5,000 Volt Power Cable. The licensee entered this into the CAP as NCR 390095. As corrective actions, the licensee replaced the cable, conduit and other damaged equipment, including evaluation on damage to cables in overhead, and the feeder cables to station service transformer (SST) 2E and 4kV bus 5. The failure to follow the guidance in the design change package to install non safetyrelated cables between Bus 4 and Bus 5 in accordance with their design change program and vendor and cable installation specifications was a performance deficiency. This finding was determined to be more than minor because it affected the Initiating Events Cornerstone objective of limiting events that upset plant stability, and was related to the attribute of Design Control (i.e., Plant Modifications). Specifically, the inadequate cable modification was determined to be the root cause of the reactor trip that occurred on March 28, 2010. This deficiency also paralleled Inspection Manual Chapter 0612, Appendix E, Example 2.e, as the licensee did not follow their own administrative requirements and vendor recommendations for cable installation. The performance deficiency was screened using Phase 1 of Inspection Manual Chapter 0609, Significance Determination Process, which determined that because the finding increases the likelihood of a fire, a Phase 3 SDP analysis was required. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst in accordance with the guidance in IMC 0609 Appendix F utilizing the NRCs Robinson SPAR model. The Phase 3 analysis determined the finding to be of very low safety significance (Green) because the core damage frequency increase was less than 1E-6. There is not a crosscutting aspect associated with the finding because the performance deficiency involving the cable installation occurred greater than 20 years ago and does not reflect current licensee performance.
05000261/FIN-2010004-04	2010Q3	Robinson	Failure to Establish an Adequate PATH-1 Emergency Operating Procedure	(TBD) The inspectors identified an apparent violation (AV) of Technical Specifications (TS) 5.4.1, Procedures , for the licensees failure to establish and maintain an adequate emergency procedure that ensured reactor coolant pump (RCP) seal cooling was maintained following a reactor trip. The licensee has entered this into the CAP as nuclear condition report (NCR) 423147. Corrective actions for this finding are still being evaluated. The failure to establish and maintain an emergency procedure that would ensure adequate reactor coolant pump seal cooling, preventing seal degradation and a possible seal LOCA was a performance deficiency. The finding is more than minor because it is associated with 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 a loss of seal cooling to prevent the initiation of a RCP seal loss of coolant accident (LOCA). Using Manual Chapter Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding required a Phase 2 analysis because the finding could result in RCS leakage exceeding Technical Specification limits. The Phase 2 analysis determined that this finding was potentially greater than green; therefore, a Phase 3 analysis is required by a regional senior reactor analyst due to an increase in the likely hood of an RCP seal LOCA. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. The cause of this finding had a cross-cutting aspect of Documentation, Procedures, and Component Labeling, in the Resources component of the cross-cutting area of Human Performance, in that the licensee failed to ensure procedures for emergency operations were adequate to assure nuclear safety.
05000261/FIN-2010004-05	2010Q3	Robinson	Failure to Correctly Implement a Systems Approach to Training for the Licensed Operator Requalification Program	(TBD) The inspectors identified an Apparent Violation (AV) of 10 CFR 55.59(c), Requalification program requirements , for the licensees failure to properly implement elements of a Commission approved program developed using a systems approach to training (SAT), that was implemented in lieu of meeting the requirements defined in 10 CFR 55.59 (c). The finding was entered into the licensees corrective action program as NCR-423232, NCR-423238, and NCR-423239. Corrective actions for this finding are still being evaluated. The licensees failure to properly implement elements of a Commission approved requalification program was a performance deficiency. The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone and affected the cornerstones 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 implement training requirements for Path-1 and perform adequate retraining of operators that demonstrated areas of weakness during operating tests contributed to operators failure to identify and implement actions to mitigate a loss of seal cooling to the reactor coolant pumps (RCPs) during the events of March 28, 2010. Contrary to Augmented Inspection Team Report 05000261/2010009, further inspection revealed that RCP seal injection was not adequate coincident with a loss of cooling to the thermal barrier heat exchanger to the B RCP. Using Manual Chapter Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding required a Phase 2 analysis because the finding could result in reactor coolant system (RCS) leakage exceeding Technical Specification limits. The Phase 2 analysis determined that this finding was potentially greater than green; therefore, a Phase 3 analysis is required by a regional senior reactor analyst due to an increase in the likelihood of an RCP seal LOCA. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. The cause of this finding was directly related to the cross cutting aspect of Personnel Training and Qualifications in the Resources component of the Human Performance area, in that the licensee failed to ensure the adequacy of the training provided to operators to assure nuclear safety.
05000261/FIN-2010009-01	2010Q2	Robinson	Monitoring of Plant Parameters and Alarms	The team conducted an independent review of control room activities to determine if licensee staff responded properly during the events. With respect to operator awareness and decision making, the team was specifically focused on the effectiveness of control board monitoring, communications, technical decision making, and work practices of the operating crew. With respect to command and control, the team was specifically focused on actions taken by the control room leadership in managing the operating crews response to the event. The team performed the following activities in order to understand and/or confirm the control room operating teams actions to diagnose the event and implement corrective actions: Conducted interviews with control room operations personnel on shift during the event. Reviewed procedures, narrative logs, event recorder data, system drawings, and plant computer data. Observed a simulated plant response to this event as demonstrated on the plant reference simulator. Reviewed the crews implementation of emergency, abnormal, and alarm procedures as well as Technical Specifications. Reviewed Operations administrative procedures concerning shift manning and procedure use and coordination. Reviewed Operations procedures in use at the time of the second fire. The team determined that operators exhibited weaknesses in fundamental operator competencies when responding to the event. Specifically, the team determined that the operating crew did not identify important off-normal parameters and alarms in a timely manner, resulting in a failure to recognize an uncontrolled RCS cooldown and a potential challenge to RCP seal cooling. Additionally, the team determined that crew supervision did not exercise effective oversight of plant status, crew performance, or site resources. Through a review of plant data, the team determined that the crews response to the first event was not effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew did not recognize the magnitude of the RCS cool down caused by an on-going steam demand. The RCS cool down rate exceeded the limit of 100o/hr in any one hour period as specified in Technical Specification (TS) 3.4.3, RCS Pressure and Temperature (P/T) Limits. The fact that the RCS cooldown rate exceeded the limiting value specified in TS 3.4.3, and the requirement to evaluate the actions contained in TS 3.4.3, was not recognized by the crew at any time during or after the cooldown. Based on interviews, the Reactor Operator (RO) and Control Room Supervisor (CRS) assessed the cool down rate as being consistent with what was experienced during simulator training for an RCP trip followed by a reactor trip. The RCS cool down continued until Instrument Bus 3 was inadvertently de-energized (approximately 33 minutes after the start of the first event), which caused the MSIVs to close, isolating the steam generators from the steam header. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the crew did not recognize that VCT level was decreasing, a low VCT level alarm had annunciated, and automatic swapover of the charging pump suction from the VCT to the RWST failed to occur, until indicated level in the VCT had decreased to approximately 2-3 inches and charging flow had degraded. Once the crew identified this condition, the RO attempted to manually align the suction of the charging pumps to the RWST but made an error when performing the alignment. The error left the suction of the charging pumps aligned to the VCT. The Shift Technical Advisor (STA) determined the alignment was incorrect and the RO corrected the error. The crew did not reference APP-003-E3, VCT HI/LO LVL, which provided direction to manually transfer the charging pump suction to the RWST. RCP seal cooling was maintained because the crew reopened FCV-626 to restore CCW cooling to the RCP thermal barrier heat exchanger approximately 6 minutes before depletion of the VCT. However, high pump bearing temperature alarms were received on all three RCPs. The high temperature alarms subsequently cleared after operators reopened FCV-626. Based on operator interviews, the team concluded that, following implementation of Emergency Operating Procedures (EOPs), the operators did not complete a satisfactory review and evaluation of alarm conditions prior to the second event. Instead, the operating crew entered GP-004, Post Trip Stabilization, and attempted to reset the generator lockout relay without using the information in the Annunciator Panel Procedures (APPs) to completely and accurately assess abnormal electric plant status. GP-004 is a normal operating procedure and is written with the assumption that the plant is in a normal (undamaged) configuration. The crew was not aware that a sudden pressure fault signal from the UAT was still applied to the generator lockout circuit logic, as indicated by a locked in UAT fault trip alarm (APP-009-B6, AUX TRANSF FAULT TRIP). The attempted reset reenergized Bus 4 and caused a fault at breaker 52/24, initiating the sequence for the second fire. The team concluded that if the crew had performed a thorough control board walkdown, additional electric plant APPs and/or AOPs could have been identified and implemented before exiting to a normal operating procedure (GP-004). Additional review by the NRC will be required to determine if the licensees programs resulted in untimely identification and investigation of abnormal plant parameters and unexpected main control room alarms. This review will also determine whether the crews monitoring of plant parameters and alarms, and use of associated procedures, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-01, Monitoring of Plant Parameters and Alarms. Additionally, further review by the NRC will be required to determine if the RCS cooldown rate exceeding the limiting value specified in TS 3.4.3 represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-02, RCS Cooldown Rate Exceeds Technical Specification 3.4.3 Limit.
05000261/FIN-2010009-02	2010Q2	Robinson	RCS Cooldown Rate Exceeds Technical Specification 3.4.3 limit	Through a review of plant data, the team determined that the crews response to the first event was not effective in stabilizing the plant. Through interviews and review of plant data, the team determined that the crew did not recognize the magnitude of the RCS cool down caused by an on-going steam demand. The RCS cool down rate exceeded the limit of 100o/hr in any one hour period as specified in Technical Specification (TS) 3.4.3, RCS Pressure and Temperature (P/T) Limits. The fact that the RCS cooldown rate exceeded the limiting value specified in TS 3.4.3, and the requirement to evaluate the actions contained in TS 3.4.3, was not recognized by the crew at any time during or after the cooldown. Based on interviews, the Reactor Operator (RO) and Control Room Supervisor (CRS) assessed the cool down rate as being consistent with what was experienced during simulator training for an RCP trip followed by a reactor trip. The RCS cool down continued until Instrument Bus 3 was inadvertently de-energized (approximately 33 minutes after the start of the first event), which caused the MSIVs to close, isolating the steam generators from the steam header. Based on the sequence of events, a review of plant data, and operator interviews, the team concluded that the crew did not recognize that VCT level was decreasing, a low VCT level alarm had annunciated, and automatic swapover of the charging pump suction from the VCT to the RWST failed to occur, until indicated level in the VCT had decreased to approximately 2-3 inches and charging flow had degraded. Once the crew identified this condition, the RO attempted to manually align the suction of the charging pumps to the RWST but made an error when performing the alignment. The error left the suction of the charging pumps aligned to the VCT. The Shift Technical Advisor (STA) determined the alignment was incorrect and the RO corrected the error. The crew did not reference APP-003-E3, VCT HI/LO LVL, which provided direction to manually transfer the charging pump suction to the RWST. RCP seal cooling was maintained because the crew reopened FCV-626 to restore CCW cooling to the RCP thermal barrier heat exchanger approximately 6 minutes before depletion of the VCT. However, high pump bearing temperature alarms were received on all three RCPs. The high temperature alarms subsequently cleared after operators reopened FCV-626. Based on operator interviews, the team concluded that, following implementation of Emergency Operating Procedures (EOPs), the operators did not complete a satisfactory review and evaluation of alarm conditions prior to the second event. Instead, the operating crew entered GP-004, Post Trip Stabilization, and attempted to reset the generator lockout relay without using the information in the Annunciator Panel Procedures (APPs) to completely and accurately assess abnormal electric plant status. GP-004 is a normal operating procedure and is written with the assumption that the plant is in a normal (undamaged) configuration. The crew was not aware that a sudden pressure fault signal from the UAT was still applied to the generator lockout circuit logic, as indicated by a locked in UAT fault trip alarm (APP-009-B6, AUX TRANSF FAULT TRIP). The attempted reset reenergized Bus 4 and caused a fault at breaker 52/24, initiating the sequence for the second fire. The team concluded that if the crew had performed a thorough control board walkdown, additional electric plant APPs and/or AOPs could have been identified and implemented before exiting to a normal operating procedure (GP-004). Additional review by the NRC will be required to determine if the licensees programs resulted in untimely identification and investigation of abnormal plant parameters and unexpected main control room alarms. This review will also determine whether the crews monitoring of plant parameters and alarms, and use of associated procedures, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-01, Monitoring of Plant Parameters and Alarms. Additionally, further review by the NRC will be required to determine if the RCS cooldown rate exceeding the limiting value specified in TS 3.4.3 represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-02, RCS Cooldown Rate Exceeds Technical Specification 3.4.3 Limit.
05000261/FIN-2010009-03	2010Q2	Robinson	Utilization of operators During Events Requiring Use of Concurrent Procedures	Through interviews, the team determined that the Balance of Plant (BOP) operator concurrently performed Abnormal Operating Procedure (AOP)-041, Response to Fire Event, during the first event. The team observed that AOP-041 contains numerous steps to coordinate on-site and off-site fire brigade response and notifications. The team determined that having a licensed operator perform AOP-041, concurrent with the CRS and RO performing emergency operating procedures, is a licensee expectation in accordance with OMM-022, Emergency Operating Users Guide. Through interviews, the team determined that because the BOP operator was performing AOP-041, he was unavailable to assist the control room team in recognizing and diagnosing off-normal events and conditions for approximately the first 30 minutes of the first event. During interviews, the two operators responsible for panel operation (the RO and CRS) consistently noted the unavailability of a third person (the BOP licensed operator) to perform independent panel checks. The team noted that during conditions of minimum manning, using the BOP operator to concurrently perform certain AOPs may hinder or prevent him or her from assisting the CRS and RO in stabilizing the plant during events that challenge the control room crew. Additional review by the NRC will be needed to determine if the licensees utilization of operators, during conditions of minimum control room manning, is adequate during complex events. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-03, Utilization of Operators During Events Requiring Use of Concurrent Procedures.
05000261/FIN-2010009-04	2010Q2	Robinson	Fidelity of Plant-Referenced Simulator	A review of simulator performance and event data by the team confirmed one simulation deficiency which had been identified by the licensee as part of their event review. When power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator, FCV-626 (thermal barrier heat exchanger outlet isolation flow control valve) closed unexpectedly. As discussed in more detail in the Section 4.5, Unexpected Closure of FCV-626, the as-built plant configuration resulted in the valve closing on a loss of power. This response was not obtained in the simulator because the simulator modeling of FCV-626 was based solely on CCW flow through the valve and did not take into account power to the valve operator and associated control circuit. Consequently, in simulator scenarios which included a loss of power to Instrument Bus 4, this valve remained open. Because the plant reference simulator did not demonstrate expected plant response for a loss of Instrument Bus 4, the team identified the need for additional NRC review to determine the adequacy of fidelity of the plant reference simulator for conducting loss of component cooling system control manipulations and plant evolutions. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-04, Fidelity of Plant-Referenced Simulator.
05000261/FIN-2010009-05	2010Q2	Robinson	Corrective Action for Operating Crew Performance Issues	To assess the extent of condition for the operator performance issues demonstrated during this event, the team reviewed a sample of simulator crew evaluation forms spanning the period of February 2008 to February 2010. The team identified multiple examples of operating crew weaknesses identified by training, relative to monitoring and control of major plant parameters. Of the six packages reviewed, four contained comments summarized as follows: February 27, 2008 unaware of steam dumps open; no attempt at RCS temperature control March 3, 2008 crew not clear if steam dumps actuated February 19, 2009 pressurizer level control post-trip was not anticipated; S/G level control needed improvement February 24, 2009 slow to identify steam dump malfunction; post- trip trends of associated parameters not provided The team noted that even though the evaluations highlighted the operators responsibility for monitoring and controlling major plant parameters, this emphasis was not effective in achieving the level of performance necessary to stabilize the plant following the uncontrolled cooldown that occurred during this event. The team concluded that additional inspection is warranted to determine if the licensees corrective action program is effective in capturing and addressing operating crew performance weaknesses. The team noted that the licensee also identified this issue regarding operating crew performance standards as part of their event investigation. This review will also determine if this issue represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-05, Corrective Action for Operating Crew Performance Issues.
05000261/FIN-2010009-06	2010Q2	Robinson	Adequacy of Emergency Operating Procedure Background Documents	From interviews, the team determined that the control room operators, in responding to the event, relied exclusively on actions and guidance explicitly described in EOPs. The operators did not consider mitigating actions that would have stabilized the plant that were not explicitly contained in these procedures, such as shutting the MSIVs. The emergency procedures being implemented centered on the Path-1 EOP. From a review of the plant procedures used by operators to respond to this event, the team determined that certain Path-1 procedure steps required operators to rely on their knowledge because these steps did not contain detailed (rule-based) guidance. The team observed that Path-1 is a flow diagram that assists with diagnostics but does not consistently provide acceptance criteria and alternate actions. The team determined that, in general, implementation of the Path-1 EOP relies more heavily on operator knowledge-based behavior versus the rule-based behavior emphasized in WOG Emergency Response Guidelines. The team noted that common industry practice among Westinghouse technology plants is to utilize a two-column page format for EOPs and to also provide more explicit detail regarding specific parameters to be checked and specific components to manipulate within each step. The team observed that EOPs did not contain explicit guidance to fully isolate ongoing steam flow in all cases. For example, End Path Procedure (EPP) Foldout A Step 6 MSR Isolation Criteria does not contain additional contingency actions in the event the specified action cannot be taken or is not effective (i.e. loss of power to MSR steam supply valves). During interviews, operators stated that they had been trained in the simulator to send local operators to close MSR valves as a contingency action. However, this action is not listed in the Foldout A procedure and no additional or alternate action that could be performed from the control boards, such as closing the MSIVs, is specified. Additionally, Path-1 Turbine Tripped does not contain additional steps that operators might be reasonably expected to take in order to accomplish the intent of the step, such as closing the MSIVs, in the event that the specified contingency actions of manually tripping the turbine and running back the turbine are not successful. The team also identified an inconsistency between the Path-1 Basis Document and the licensees emergency operating procedure users guide regarding the immediate operator action of SI Initiation. Path-1 EOP does not explicitly list parameters or conditions to be checked in order to determine if a safety injection is required (requiring both the operator performing the immediate action and the CRS who is reading the procedure to rely on their knowledge). However, the Path-1 Basis Document provides an interpretation of this step that states, in part, that a safety injection is required if RCS inventory is decreasing in an uncontrolled manner and exceeding all available makeup flow. OMM-022, Emergency Operating Procedures Users Guide Section 8.3.1, Item 10, lists parameters and values that operators are expected to check when performing this immediate action step. The team noted that this step in OMM-022 does not specify checking RCS parameters directly related to RCS inventory, such as pressurizer level, as described in the Path-1 basis document. The team reviewed plant data from the first event and determined that pressurizer level decreased off-scale. Based on interviews, the team also determined that operators did not recognize the magnitude and rate of the pressurizer level decrease caused by the ongoing RCS cool down. Consequently, the team identified the need for additional NRC review to determine the adequacy of OMM-022 with respect to the immediate operator action of checking whether a safety injection is required. This review will determine whether the inconsistency between the Emergency Operating Procedures Users Guide and the Path-1 Basis Document is a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000216/2010009- 06, Adequacy of Emergency Operating Procedure Background Documents.
05000261/FIN-2010009-07	2010Q2	Robinson	Loss of Seal Water Results in Failure of the A Main Condeser Vacuum Pump	The team observed that procedure GP-004 Post Trip Stabilization contained a step to reset the generator lockout relays but did not contain steps, cautions, or notes that prompt operators to ensure the inputs are clear prior to attempting a reset. Although AOP-024, Loss of Instrument Buses was not used, and was not required to be used per the licensees procedure use guidelines during this event, the team noted that the procedure does not address the effect of a loss of an instrument bus on the main steam flow channels that input into the Main Steam Line Isolation Signal. Additionally, AOP-024 does not address the loss of CCW flow to the RCP thermal barrier heat exchangers (FCV-626 closure). The team reviewed the circumstances which resulted in the fire in and subsequent failure of the A Main Condenser Vacuum Pump. The pump failed because seal water to the pump, which is supplied by demineralized water, was lost for approximately three and a half hours prior to the pump failure. The loss of power following the first fire caused the loss of demineralized water. The Main Condenser Vacuum Pump establishes and maintains condenser vacuum to provide a heat sink used for decay heat removal following a reactor trip. The team observed that the licensee does not have a procedure to address loss of seal water makeup to the main condenser vacuum pumps. Use of such a procedure could have prevented the fire and associated damage to this equipment. As a result of this observation, the team identified the need for additional NRC review to determine if procedures should have been available to address a sustained loss of seal water makeup to the main condenser vacuum pumps. Additional review by the NRC will be needed to determine whether the lack of a procedure for loss of seal water to the main condenser vacuum pumps is a performance deficiency. An Unresolved Item will be opened pending completion of this review. The URI is identified as 05000261/2010009-07, Loss of Seal Water Results in Failure of the A Main Condenser Vacuum Pump.
05000261/FIN-2010009-08	2010Q2	Robinson	Deficiencies in Non Safety-Related Cable Installation	To determine the circumstances surrounding the fault in the cable that led to the first electrical disturbance and subsequent reactor trip, the team performed the following activities: Determined details of the cable construction including conductor size, insulation thickness and material, and type of shielding using the manufacturers data sheet Compared the cable construction to system requirements and standard industry practice Reviewed relevant portions of the plant modification that installed the cable Viewed the site of the cable fault Reviewed cable records to determine where other similar cables are installed in the plant Interviewed engineering staff involved with the electrical distribution systems and components Reviewed the licensees causal analysis for the cable fault Evaluated the licensees proposed corrective actions The cable that faulted did not meet many of the specifications for the design change that installed the cable. This contributed to the cable failure. The cable, manufactured by the Rome Cable Corporation (Rome), was installed in 1986 when 4 kV Bus 5 was installed as an extension of Bus 4 per Plant Design Change Number DCN-851. The cable, identified as C21344A, served as the interconnection between 4 kV Buses 4 and 5 and was comprised of two conductors for each of three phases. The cable was installed in two steel conduits, with each conduit containing all three phases. As noted in Section 2.1, all 4 kV buses at Robinson are non safety-related. The Bill of Materials for DCN-851 indicated that the cable should be in accordance with Standard Specification L2-E-035 for 5,000 Volt Power Cable. However, the Bill of Materials did not indicate a purchase order number for the cable that faulted, as it did for other cables installed by the modification, such as 3/c No. 12 AWG cable. Records reviewed by the team indicated that the cable came from reel number HBR-13505. Differences between Standard Specification L2-E-035 and the actual installed Rome cable are listed below: L2-E-035 called for coated copper conductors. The installed cable had uncoated conductors. L2-E-035 called for all cables to be provided with an outer jacket. The installed cable did not have a jacket. L2-E-035 called for cable insulation and jacketing that was self-extinguishing and non-propagating with regard to fire as described in IEEE 383-1974, Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations. The Rome catalogue data made no claim as to fire propagation properties. The event demonstrated that the cable lacked fire propagation properties because 1) the cable ignited following the fault, 2) the cable did not self extinguish after the fault was denergized, and 3) flame was propagated along the cable. L2-E-035 called for 133 percent insulation level and insulation shielding if specified in the purchase order. The installed cable did not have either of these features. The cable consisted of single conductor 500 MCM uncoated copper with 130 mils of cross-linked polyethylene insulation rated for continuous operation at 5 kV and 90 degree Celsius. The insulation thickness was determined from the overall cable diameter and from the licensees measurement of conductor diameter. The manufacturers catalogue information (SPEC 7155 dated January 1, 1991) stated that an insulation thickness of 120 mils is suitable for applications requiring 100 percent insulation levels. However, due to the high-resistance grounding scheme used on the Robinson 4 kV electrical system, an insulation level of 133 percent or 173 percent was required, depending on how long a ground fault could remain on the system. The significance of not having adequate insulation thickness was that, should a single line to ground fault occur the voltage on the two un-faulted phases would exceed the rating of the insulation. The cable did not have a jacket. The significance of not having a jacket was that the cable insulation was more vulnerable to damage during installation. Also, the jacket, if installed, would have provided a buffer between the insulation and grounded metal parts, such as the conduit or bus enclosure. The cable did not have an insulation shield. When an insulation shield is not installed, the electric field will be partly in the insulation and partly in whatever lies between the insulation and ground. This situation could be conducive to corona if a thin layer of air lies between the insulator surface and ground, which can lead to insulation deterioration. IEEE 666-1991, Design Guide for Electric Power Service Systems for Generating Stations, Section 12.3.6 states: Power cables rated 5 kV and over should be equipped with insulation shield. The significance of not having a grounded insulation shield was that voltage stress on the insulation was not symmetrical and uniform around the circumference, but rather greater at points where the insulation contacted a grounded surface, such as a metal conduit, than at other points around the circumference. The following information indicated that shielded cable was originally intended for this cable: 1) Design Change Notice No. 6 to DCN-851 changed the termination detail from one depicting the grounding of shield wires to one with no shield wires, and 2) installation instruction 4.35 directed installation of a stress cone for cable C21344A, which would be needed only for a shielded cable. Cognizant licensee engineers stated that the Rome cable installed as part of the Bus 5 modification was different than other 4 kV cable installed at Robinson and was used only for the Bus 4 to Bus 5 connection and the feeder from Bus 5 to station service transformer 2E. During the inspection, the licensee did not present any documentation explaining or justifying why the installed cable for the Bus 5 modification was different than Standard Specification L2-E-035 and the typical cables installed in the plant. The team reviewed the 4 kV cables connected to Buses 1 through 5, and found this statement to be correct. All the 4 kV cables connected to Buses 1 through 5, except for the two cables mentioned above, met or exceeded standard specification L2-E-035, with at least 133 percent insulation and insulation shield. In addition to construction details of the faulted cable, the team reviewed various design considerations related to the cable. The ampacity of two 500 MCM, 90 degree Celsius, cables installed in conduit in free air is 954 amperes. The team estimated the maximum continuous load on Bus 5 as 493 amperes; 216 amperes for the 1750 HP Circulating Water Pump and 277 amperes for the 2000 kV station service transformer. The overcurrent relays were set at 1000 amperes. Therefore, the cables were not overloaded during normal operation. The conduits were the correct size for the cables installed within them. The number of bends in the conduits did not exceed the recommended maximum number of bends. Therefore, pulling tension limits should not have been exceeded during installation. This did not preclude the possibility that the three single conductors became twisted as the cable was pulled through three 90 degree bends. The licensees Event Review Team (ERT) visually examined the faulted cable and the station service transformer 2E feeder cable and determined the three single conductors were twisted. Twisting of one conductor around the other two conductors could result in jamming of the cables in the conduit since the combined diameter of the twisted cables would be greater than the inside diameter of the conduit. The twisting would have led to excessive pulling force being applied during cable installation. The required pulling force is proportional to the side wall pressure exerted on the cable at a bend. Because of the extensive damage resulting from the length of time the fault was energized, the failure mechanism could not be determined with absolute certainty. The licensees causal analysis determined with a fair degree of certainty that the initial fault occurred at a point where the conduits terminate at the top of Bus 5 switchgear. After consideration of the above facts and review of the licensees causal analysis, the team concluded that the failure mechanism probably involved one or more of the following factors: Degradation of the insulation at the surface of the cable due to corona Damage to the insulation due to inadvertent twisting of the three conductors during the pulling-in process resulting in excessive side-wall pressure at one or more of the three 90 degree bends in the conduit Rubbing of the cable against the conduit or switchgear top plate due to turbine building vibration A secondary fault at the Bus 4 cable compartment for circuit breaker 52/24 was caused by plasma gas migrating inside the conduit and through a hole in the conduit seal, along with terminations that were not taped. The ERT postulated that the hole was caused by pressure built up in the conduit as a result of the fault. The ERT further postulated that this secondary fault at circuit breaker 52/24 created permanent degradation of the insulation at that location. All of the cable within the compartment was completed destroyed when Bus 4 was reenergized about four hours after the initial fault was cleared. The licensee stated that corrective actions related to the cable failure would be to replace the Rome cable feeding station service transformer 2E before plant startup. The licensees Significant Adverse Condition Investigation Report for the event states that a search, using catalog identification numbers, was made across the Progress Energy fleet for this type of cable or similar cable and none was found. The licensee did not believe revisions were needed to the design control process because the process had been changed earlier to preclude the problems described herein, i.e. lack of proper control over purchasing and field changes. The team concluded that the apparent root cause of the initial cable failure and subsequent associated short-circuits was poor quality control over the non-safety-related modification process for installing the cable. A cable of lesser quality than other 5 kV cables installed throughout the plant was installed as a substitute during this modification. The cable terminations were not taped and the cable was not restrained to prevent rubbing. The consequence of the cable fault was a reactor trip. Because of the magnitude of the electrical fault, the reactor trip would have occurred regardless of whether bus tie circuit breaker 52/24 was fully functional. The resultant voltage transient decreased RCP speed which lowed RCS flow and initiated a reactor trip. This occurred faster than the time delay overcurrent protective relays associated with circuit breaker 52/24. Additional review by the NRC will be needed to determine whether the cable installation represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-08, Deficiencies in Non Safety-Related Cable Installation.
05000261/FIN-2010009-09	2010Q2	Robinson	Failure to Repair Circuit Breaker 52/24 Resulting in Breaker Being Unable to Operate	Circuit breaker 52/24 is the non safety-related tie circuit breaker between 4 kV Bus 4 and Bus 5. Following an electrical fault on cabling between this breaker and Bus 5 as described in Section 4.1, the breaker failed to open to clear the fault due to a lack of control power. The team reviewed equipment records related to circuit breaker 52/24 and determined that Work Request 357740 was written in November 2008 to repair the closed position indicating light located on the front of the circuit breaker. Because the closed position light would not illuminate after the light bulb was replaced, licensee personnel assumed the problem involved the socket for the bulb. Although the licensee had subsequently developed a work order to repair the socket, the licensee had not performed any additional repairs up to the time of the event. A number of opportunities existed to identify the source of the problem, including additional work requests and walkdowns by the system engineer. The additional work requests were canceled to the work order and the system engineer failed to recognize the potential impact of the failed indicating light regarding breaker operation. Following the event, the licensee determined that one of the control power fuses in the breaker trip circuit was failed. Laboratory examination by the licensee revealed that the fuse had a cracked internal element. The licensees ERT found that the overcurrent relays and the circuit breaker were fully functional. The failed fuse caused the breaker trip circuit to be deenergized, resulting in the indicating lamp being off and preventing the circuit breaker from tripping. Operations, Maintenance, and Engineering personnel did not fully understand the significance of the deenergized breaker indicating light. Operations personnel did not request an engineering assessment when they reviewed the work order. However, because station engineering was independently aware of the condition, it is not evident that a request for an engineering assessment would have resulted in a different outcome. The broken fuse, style LPN-RK-30SP, was manufactured by Bussman Division of Cooper Industries. As part of their corrective actions for this problem, the licensee checked the resistance of 16 fuses of the same style to determine whether any incipient degradation was taking place. The tested group included in-service fuses of various sizes as well as three new fuses. The licensee determined all the fuses had acceptable resistance readings. The licensee stated they would also provide training to appropriate plant personnel regarding this event and expectations for response to circuit breaker indicating lamps being off when they should be on. (Note: On April 14, 2010, the NRC issued Information Notice 2010-09, Importance of Understanding Circuit Breaker Control Power Indications, which described the problem with circuit breaker 52/24 control power). Section 4.1 states that, because of the high magnitude of the fault current, a reactor trip would have occurred as a result of the March 28 event, regardless of whether circuit breaker 52/24 was fully functional. However, for potential faults resulting in smaller currents, proper operation of circuit breaker 52/24 would prevent a reactor trip. The team concluded the licensee failed to understand the possible implications of circuit breaker 52/24 indicating light being off and should have pursued the issue in a timely manner. The problem existed for approximately 17 months until this event revealed the circuit breaker was unable to isolate a fault condition. Additional review by the NRC will be needed to determine whether the failure to correct, in a timely manner, a problem with the indicating light for circuit breaker 52/24 and the underlying problem with the control power fuse represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue will be identified as URI 05000261/2010009-09, Failure to Repair Circuit Breaker 52/24 Resulting in Breaker Being Unable to Operate.
05000261/FIN-2010009-10	2010Q2	Robinson	Failure of Charging Pump Suction Valves to Automatically Transfer Due to Errors in Implementing a Instrumentation Component Upgrade	Following the cable fault and resultant reactor trip, VCT level decreased and reached a low level set point that should have automatically transferred the suction source for the running charging pump to the RWST. The transfer did not take place as designed. The control circuitry which implements this transfer utilizes two VCT level transmitters. When each transmitter senses a low level, it energizes a relay via a comparator. When both relays are energized, and their contacts are closed, the circuit for opening the charging pump suction from RWST valve (LCV-115B) should be made up and the valve should open. Then, when LCV-115B opens, a signal is generated to close the VCT suction valve (LCV-115C.) One of the relays in the LCV-115B circuit was driven by an older style Hagan level comparator, and the other relay was driven by a newer style NUS comparator. Different NUS comparator configuration options, such as electromechanical relay or solid state output, can be made by placing plug-type jumpers at different locations on the circuit board. The licensees post-event troubleshooting revealed that the NUS comparator was not properly configured when it was installed in 2008. The NUS comparator should have been configured to have its output function operate in the solid state mode and energize the control relay when a low level was sensed. When the comparator was configured in 2008, the placement of jumpers resulted in an electromechanical relay output, which was only capable of de-energizing the control relay upon low level. As a result, the control relay driven by the NUS comparator was in the energized state when level in the VCT was normal. When level in the VCT decreased below the level at which the suction to the charging pumps should have transferred, the associated valves did not reposition because the relay driven by the NUS comparator was de-energized and the valve open circuit was not made up. The licensee did not detect the incorrect configuration of the NUS comparator after installation because of the limited scope of the post-installation testing. When the new comparator module was calibrated the bistable trip light responded as intended, satisfying the test acceptance criterion. The output contacts were not checked during the calibration and the licensee did not perform an integrated test, such as simulating a low VCT level, to confirm the two valves repositioned. The licensee replaced the VCT level Hagan comparator with an NUS comparator as part of a larger project to provide a replacement for obsolete Hagan comparators. Licensee engineers stated that about 80 percent of the Hagan comparators had been replaced with NUS comparators at the time of the AIT inspection. The team questioned the extent of condition for potential similar errors in replacement comparators, i.e. incorrect placement of jumpers and inadequate testing for detecting errors. The licensee noted that comparators used to perform reactor protection system functions, safety injection functions and certain other functions were subject to Technical Specification surveillance testing, which provided a check of the comparator output contacts. The licensee also pointed out that the circuit in question may have been unique in that only one of the comparators used in the two-out-of-two logic had been changed to the new NUS module. If two NUS modules had been installed, both containing the incorrect configuration for the jumpers, the transfer from VCT to RWST suction would have taken place with a normal VCT level and the problem would have been self revealing. The licensee stated that many control functions using the new NUS modules would alarm when the bistable actuates, making a similar problem self revealing. The licensee controlled the substitution of NUS comparators for Hagan comparators under the plant modification process using Engineering Evaluation EE-92-144. The licensee controlled component removal and installation within the maintenance process. The installation of the comparator for the charging pump suction transfer control circuit was accomplished under Work Order 011162348 in September 2008. Work order instructions directed an I&C technician to refer to the calibration procedure to determine the desired comparator configuration and refer to NUS instruction book EIP-M-DAM800 to determine the placement of jumpers necessary to implement that configuration. The placement and removal of jumpers was translated to work instructions which were reviewed and verified by an I&C system engineer. The licensee stated their planned corrective actions would include a review of all control circuits incorporating NUS comparators to confirm these circuits will operate properly. In cases where a review indicates proper operation cannot be assured, the licensee stated that appropriate testing will be performed. In addition, the process for implementing any future NUS comparator installations will be strengthened to preclude the problems described above. The team determined the failure of the suction for the charging pumps to automatically transfer from the VCT to the RWST upon low level in the VCT was caused by an error in the work instructions describing the placement of jumpers when a VCT level comparator was replaced. Additionally, the licensees post-maintenance testing was not adequate to detect the problem. Additional review by the NRC will be needed to determine whether these problems represent a performance deficiency. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-10, Failure of Charging Pump Suction Valves to Automatically Transfer Due to Errors in Implementing an Instrumentation Component Upgrade.
05000261/FIN-2010009-11	2010Q2	Robinson	FCV 626, RCP Thermal Barrier Outlet Isolations CCW Valve, Unexpected Closure	Valve FCV-626 is located in the combined CCW return from the three RCP thermal barrier heat exchangers. In its normal open position it allows CCW flow to pass through the thermal barrier heat exchangers, providing backup cooling to the RCP seals in the event of a loss of the primary cooling flow (seal injection) from the charging pumps. There are two close functions for FCV-626: 1) closes on high flow in the return line which is indicative of a rupture of a thermal barrier heat exchanger (RCS to CCW system leak) and 2) closes in response to a Phase B containment isolation signal. The valve has no automatic opening functions. The valve closed when power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator. The valve remained closed for approximately 39 minutes before the operators recognized the condition, reopened FCV-626, and restored CCW cooling to the RCP thermal barrier heat exchangers. Plant staff knew that FCV-626, a motor operated valve, was powered from Bus E-2 via MCC 6. However, plant staff, including operators, was unaware that FCV-626 would close on a momentary loss of power. Additionally, the simulator was modeled such that FCV-626 remained open when power to Bus E-2 was momentarily interrupted. The high flow closure function of FCV-626 is accomplished using flow orifice FE-626, which is located in the thermal barrier return line, and provides flow switch FIC-626 with a hydraulic input to operate high and low flow contacts. When the high flow contact opens, relay FIC-626X is de-energized and closes a contact in the closing circuit for the motor operator of FCV-626, thereby closing FCV-626. Plant procedure EDP-008, Instrument Buses, incorrectly indicated that the power source for the flow switch FIC-626 control circuit was from Instrument Bus 1. The power for the FIC-626 control circuit is from Instrument Bus 4. Instrument Bus 4 is fed from MCC-6, which also feeds motor operated valve FCV-626. When Bus E-2 transferred to the EDG, both valve FCV-626 and relay FIC-626X lost power for approximately 10 seconds. During this time interval, relay FIC-626X repositioned to its de-energized state, which closed a contact in the close circuit of valve FCV-626. When Bus E-2 reenergized, valve FCV-626 immediately began to close, which sealed in contacts to completely close the valve. The close circuit was sealed in before relay FIC-626X reset to its energized state. The team concluded that the most likely cause of the time delay for the relay to reset was a constant voltage transformer located between the relay and MCC-6. The safety significance of inadvertent shutoff of RCP thermal barrier cooling water is discussed in Section 1.1 of this report. The team reviewed historical data associated with the control circuit for valve FCV-626 and determined the licensee had at least two potential opportunities to discover the behavior of FCV-626 on a loss of power. The first opportunity was in 2005 while implementing Engineering Change (EC) 59456. While performing the EC, workers encountered wiring issues as documented in NCR168221. The licensee subsequently determined that flow switch FIC-626, which was previously thought to be powered from Instrument Bus 1, required no power to operate. As part of that investigation, it was noted that relay FIC-626X was powered from Instrument Bus 4. Wiring discrepancies existed in some of the associated drawings, but were either not noted or not pursued. 27 Enclosure 1 Additionally, the licensee did not update EDP-008, which continued to show Instrument Bus 1 Breaker 16 as the power source for the flow switch FIC-626 control circuit. The licensee has written NCR 391995 to correct these deficiencies. The second opportunity occurred in 2008 during the performance of OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (refueling). As part of the test, 480V safety-related Bus E-2 was transferred to the B EDG. Data recovered by the licensee indicated that FCV-626 closed at approximately the same time the B EDG re-energized Bus E-2. However, during the test, CCW system flow, which was being provided by the opposite train of power, was stable and RCPs were not running. Thus sufficient information was available to recognize that flow perturbations were not the cause for FCV-626 closing. About two hours later, the valve was reopened. The licensee either did not identify or did not pursue the unexpected behavior of FCV-626. The ERT entered the problems described in this section into the corrective action system. One corrective action will clarify the drawings associated with the control circuitry of FCV-626 and make some minor corrections to current drawings. Another corrective action will implement a modification to prevent inadvertent closure of valve FCV-626 for a momentary loss of power. The licensee stated the modification would be implemented prior to restart of the plant from the refueling outage. Additional review by the NRC will be needed to determine whether the design of FCV- 626, which caused the valve to close during a momentary loss of power, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. This issue is identified as URI 05000261/2010009-11, FCV 626, RCP Thermal Barrier Outlet Isolation CCW Valve, Unexpected Closure. In order to better understand the reason FCV-626 closed during a momentary loss of power, the team reviewed the licensing bases for the CCW system, including FCV-626. The team reviewed correspondence between the licensee and the NRC regarding NUREG 0737, Clarification of TMI Action Plan Requirements, Item II.K.3.25, Power on Pump Seals. This TMI item required the licensee to determine the consequences of a loss of RCP cooling due to a loss of offsite power lasting two hours. In their correspondence, the licensee stated that no modifications were necessary because the CCW system is still operable during a loss of offsite power (powered from the emergency buses) and provides flow to the RCP thermal barrier heat exchangers. They also stated that the B and C CCW pumps are automatically (requiring no operator action) started by a station blackout signal during a loss of offsite power event. Additional review by the NRC will be needed to determine if the behavior of RCP seal cooling following a loss of offsite power event is consistent with the description provided by the licensee in NUREG 0737 correspondence and if any differences represent a violation. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-12, NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event.
05000261/FIN-2010009-12	2010Q2	Robinson	NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event	Valve FCV-626 is located in the combined CCW return from the three RCP thermal barrier heat exchangers. In its normal open position it allows CCW flow to pass through the thermal barrier heat exchangers, providing backup cooling to the RCP seals in the event of a loss of the primary cooling flow (seal injection) from the charging pumps. There are two close functions for FCV-626: 1) closes on high flow in the return line which is indicative of a rupture of a thermal barrier heat exchanger (RCS to CCW system leak) and 2) closes in response to a Phase B containment isolation signal. The valve has no automatic opening functions. The valve closed when power to safety-related 480 volt Bus E-2 was transferred to the emergency diesel generator. The valve remained closed for approximately 39 minutes before the operators recognized the condition, reopened FCV-626, and restored CCW cooling to the RCP thermal barrier heat exchangers. Plant staff knew that FCV-626, a motor operated valve, was powered from Bus E-2 via MCC 6. However, plant staff, including operators, was unaware that FCV-626 would close on a momentary loss of power. Additionally, the simulator was modeled such that FCV-626 remained open when power to Bus E-2 was momentarily interrupted. The high flow closure function of FCV-626 is accomplished using flow orifice FE-626, which is located in the thermal barrier return line, and provides flow switch FIC-626 with a hydraulic input to operate high and low flow contacts. When the high flow contact opens, relay FIC-626X is de-energized and closes a contact in the closing circuit for the motor operator of FCV-626, thereby closing FCV-626. Plant procedure EDP-008, Instrument Buses, incorrectly indicated that the power source for the flow switch FIC-626 control circuit was from Instrument Bus 1. The power for the FIC-626 control circuit is from Instrument Bus 4. Instrument Bus 4 is fed from MCC-6, which also feeds motor operated valve FCV-626. When Bus E-2 transferred to the EDG, both valve FCV-626 and relay FIC-626X lost power for approximately 10 seconds. During this time interval, relay FIC-626X repositioned to its de-energized state, which closed a contact in the close circuit of valve FCV-626. When Bus E-2 reenergized, valve FCV-626 immediately began to close, which sealed in contacts to completely close the valve. The close circuit was sealed in before relay FIC-626X reset to its energized state. The team concluded that the most likely cause of the time delay for the relay to reset was a constant voltage transformer located between the relay and MCC-6. The safety significance of inadvertent shutoff of RCP thermal barrier cooling water is discussed in Section 1.1 of this report. The team reviewed historical data associated with the control circuit for valve FCV-626 and determined the licensee had at least two potential opportunities to discover the behavior of FCV-626 on a loss of power. The first opportunity was in 2005 while implementing Engineering Change (EC) 59456. While performing the EC, workers encountered wiring issues as documented in NCR168221. The licensee subsequently determined that flow switch FIC-626, which was previously thought to be powered from Instrument Bus 1, required no power to operate. As part of that investigation, it was noted that relay FIC-626X was powered from Instrument Bus 4. Wiring discrepancies existed in some of the associated drawings, but were either not noted or not pursued. 27 Enclosure 1 Additionally, the licensee did not update EDP-008, which continued to show Instrument Bus 1 Breaker 16 as the power source for the flow switch FIC-626 control circuit. The licensee has written NCR 391995 to correct these deficiencies. The second opportunity occurred in 2008 during the performance of OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (refueling). As part of the test, 480V safety-related Bus E-2 was transferred to the B EDG. Data recovered by the licensee indicated that FCV-626 closed at approximately the same time the B EDG re-energized Bus E-2. However, during the test, CCW system flow, which was being provided by the opposite train of power, was stable and RCPs were not running. Thus sufficient information was available to recognize that flow perturbations were not the cause for FCV-626 closing. About two hours later, the valve was reopened. The licensee either did not identify or did not pursue the unexpected behavior of FCV-626. The ERT entered the problems described in this section into the corrective action system. One corrective action will clarify the drawings associated with the control circuitry of FCV-626 and make some minor corrections to current drawings. Another corrective action will implement a modification to prevent inadvertent closure of valve FCV-626 for a momentary loss of power. The licensee stated the modification would be implemented prior to restart of the plant from the refueling outage. Additional review by the NRC will be needed to determine whether the design of FCV- 626, which caused the valve to close during a momentary loss of power, represents a performance deficiency. An Unresolved Item will be opened pending completion of this review. This issue is identified as URI 05000261/2010009-11, FCV 626, RCP Thermal Barrier Outlet Isolation CCW Valve, Unexpected Closure. In order to better understand the reason FCV-626 closed during a momentary loss of power, the team reviewed the licensing bases for the CCW system, including FCV-626. The team reviewed correspondence between the licensee and the NRC regarding NUREG 0737, Clarification of TMI Action Plan Requirements, Item II.K.3.25, Power on Pump Seals. This TMI item required the licensee to determine the consequences of a loss of RCP cooling due to a loss of offsite power lasting two hours. In their correspondence, the licensee stated that no modifications were necessary because the CCW system is still operable during a loss of offsite power (powered from the emergency buses) and provides flow to the RCP thermal barrier heat exchangers. They also stated that the B and C CCW pumps are automatically (requiring no operator action) started by a station blackout signal during a loss of offsite power event. Additional review by the NRC will be needed to determine if the behavior of RCP seal cooling following a loss of offsite power event is consistent with the description provided by the licensee in NUREG 0737 correspondence and if any differences represent a violation. An Unresolved Item will be opened pending completion of this review. The issue is identified as URI 05000261/2010009-12, NUREG 0737 Response From Licensee to the NRC Describing the Behavior of RCP Seal Cooling Following a Loss of Offsite Power Event.

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